10-K405 1 a2042981z10-k405.txt FORM 10-K405 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 FORM 10-K (Mark One) /X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED) OR / / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED) For the fiscal year ended DECEMBER 31, 2000 ----------------- Commission Registrant, State of Incorporation, IRS Employer File Number Address, and Telephone Number Identification Number ----------- ----------------------------- --------------------- 2-26720 LOUISVILLE GAS AND ELECTRIC COMPANY 61-0264150 (A Kentucky Corporation) 220 West Main Street P. O. Box 32010 Louisville, Kentucky 40232 (502) 627-2000 1-3464 KENTUCKY UTILITIES COMPANY 61-0247570 (A Kentucky and Virginia Corporation) One Quality Street Lexington, Kentucky 40507-1428 (859) 255-2100 Securities registered pursuant to section 12(b) of the Act: Kentucky Utilities Company -------------------------- Name of each exchange on Title of each class which registered ------------------- ---------------- Preferred Stock, 4.75% cumulative, Philadelphia Stock Exchange stated value $100 per share Securities registered pursuant to section 12(g) of the Act: Louisville Gas and Electric Company ----------------------------------- 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) Kentucky Utilities Company -------------------------- Preferred Stock, cumulative, stated value $100 per share (Title of class) Indicate by check mark whether the registrants (1) have 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 registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes X No --- --- Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. /X/ As of February 28, 2001, 860,287 shares of voting preferred stock of Louisville Gas and Electric Company, with an aggregate market value of $22,831,500, were outstanding and held by non-affiliates. Additionally, Louisville Gas and Electric Company had 21,294,223 shares of common stock outstanding, all held by LG&E Energy Corp. Kentucky Utilities had 37,817,878 shares of common stock outstanding, all held by LG&E Energy Corp. This combined Form 10-K is separately filed by Louisville Gas and Electric Company and Kentucky Utilities Company. Information contained herein related to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants. DOCUMENTS INCORPORATED BY REFERENCE Proxy statements for Louisville Gas and Electric Company and Kentucky Utilities Company, currently anticipated to be prepared and filed with the Commission during April 2001, are incorporated by reference into Part III of this Form 10-K. TABLE OF CONTENTS PART I Item 1. Business........................................................ 7 Louisville Gas and Electric Company General...................................................... 7 Electric Operations.......................................... 8 Gas Operations............................................... 9 Rates and Regulation......................................... 10 Construction Program and Financing........................... 11 Coal Supply.................................................. 11 Gas Supply................................................... 12 Environmental Matters........................................ 12 Competition.................................................. 13 Kentucky Utilities Company General...................................................... 13 Electric Operations.......................................... 13 Rates and Regulation......................................... 14 Construction Program and Financing........................... 15 Coal Supply.................................................. 16 Environmental Matters........................................ 17 Competition.................................................. 17 Employees and Labor Relations................................... 17 Item 2. Properties...................................................... 17 Item 3. Legal Proceedings............................................... 20 Item 4. Submission of Matters to a Vote of Security Holders............. 21 Executive Officers of the Companies....................................... 21 PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters.......................................... 25 Item 6. Selected Financial Data......................................... 26 Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition: Louisville Gas and Electric Company....................... 27 Kentucky Utilities Company................................ 38 Item 7A. Quantitative and Qualitative Disclosures About Market Risk...... 48 Item 8. Financial Statements and Supplementary Data: Louisville Gas and Electric Company.......................... 49 Kentucky Utilities Company................................... 74 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure..................................... 95 PART III Item 10. Directors and Executive Officers of the Registrant (a).......... 95 Item 11. Executive Compensation (a)...................................... 95 Item 12. Security Ownership of Certain Beneficial Owners and Management (a)........................................... 95 Item 13. Certain Relationships and Related Transactions (a).............. 95 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K...................................... 95
Signatures ............................................................... 116
(a) Incorporated by reference. INDEX OF ABBREVIATIONS Capital Corp. LG&E Capital Corp. Clean Air Act The Clean Air Act, as amended in 1990 CNN Certificate of Public Convenience and Necessity CT Combustion Turbines DSM Demand Side Management ECR Environmental Cost Recovery EEI Electric Energy, Inc. EITF Emerging Issues Task Force Issue EPA U.S. Environmental Protection Agency ESM Earnings Sharing Mechanism FAC Fuel Adjustment Clause FERC Federal Energy Regulatory Commission FPA Federal Power Act FT Firm Transportation GSC Gas Supply Clause Holding Company Act Public Utility Holding Company Act of 1935 IBEW International Brotherhood of Electrical Workers IMEA Illinois Municipal Electric Agency IMPA Indiana Municipal Power Agency Kentucky Commission Kentucky Public Service Commission KIUC Kentucky Industrial Utility Consumers, Inc. KU Kentucky Utilities Company KU Energy KU Energy Corporation Kva Kilovolt-ampere LEM LG&E Energy Marketing Inc. LG&E Louisville Gas and Electric Company LG&E Energy LG&E Energy Corp. LG&E Services LG&E Energy Services Inc. Mcf Thousand Cubic Feet Merger Agreement Agreement and Plan of Merger dated May 20, 1997 MGP Manufactured Gas Plant Mmbtu Million British thermal units Moody's Moody's Investor Services, Inc. Mw Megawatts Mwh Megawatt hours NAAQS National Ambient Air Quality Standards NNS No-Notice Service NOx Nitrogen Oxide OMU Owensboro Municipal Utilities PBR Performance-Based Ratemaking Powergen Powergen plc PUHCA Public Utility Holding Company Act of 1935 S&P Standard & Poor's Rating Services SCR Selective Catalytic Reduction SEC Securities And Exchange Commission SERP Supplemental Employee Retirement Plan SFAS Statement of Financial Accounting Standards SIP State Implementation Plan SO2 Sulfur Dioxide Virginia Staff Virginia Commission Staff Tennessee Gas Tennessee Gas Pipeline Company Texas Gas Texas Gas Transmission Corporation TRA Tennessee Regulatory Authority Trimble County LG&E's Trimble County Unit 1 USWA United Steelworkers of America
Utility Operations Operations of LG&E and KU Virginia Commission Virginia State Corporation Commission
PART I. Item 1. Business. On December 11, 2000, LG&E Energy Corp. and Powergen plc successfully completed the merger transaction involving the two companies. LG&E Energy had announced on February 28, 2000, that its Board of Directors accepted the offer to be acquired by Powergen for cash of approximately $3.2 billion or $24.85 per share and the assumption of $2.2 billion of LG&E Energy's debt. Pursuant to the acquisition agreement, among other things, LG&E Energy became a wholly owned subsidiary of Powergen and, as a result, LG&E and KU became indirect subsidiaries of Powergen. The utility operations (LG&E and KU) of LG&E Energy have continued their separate identities and continue to serve customers in Kentucky and Virginia under their existing names. The preferred stock and debt securities of the utility operations were not affected by this transaction resulting in the utility operations' obligation to continue to file SEC reports. Following the merger, Powergen became a registered holding company under PUHCA, and LG&E and KU, as subsidiaries of a registered holding company, became subject to additional regulation under PUHCA. As a result of the Powergen merger and in order to comply with the Public Utility Holding Company Act of 1935, LG&E Services was formed and became effective on January 1, 2001. LG&E Services provides certain services to affiliated entities, including LG&E and KU, at cost as required under the Holding Company Act. On January 1, 2001, approximately 1,000 employees, mainly from LG&E Energy, LG&E and KU, were moved to LG&E Services. In January 2001, LG&E Energy announced voluntary workforce separation programs for certain employee groups. It is estimated that the separation programs may result in a workforce reduction of approximately 700 employees at LG&E and 250 employees at KU. LOUISVILLE GAS AND ELECTRIC COMPANY General Incorporated on July 2, 1913, LG&E is a regulated public utility that supplies natural gas to approximately 299,000 customers and electricity to approximately 364,000 customers in Louisville and adjacent areas in Kentucky. LG&E's service area covers approximately 700 square miles in 17 counties and has an estimated population of one million. Included in this area is the Fort Knox Military Reservation, to which LG&E transports gas and provides electric service, but which maintains its own distribution systems. LG&E also provides gas service in limited additional areas. LG&E's coal-fired electric generating plants, which are all equipped with systems to reduce sulfur dioxide emissions, produce most of LG&E's electricity. The remainder is generated by a hydroelectric power plant and combustion turbines. Underground natural gas storage fields help LG&E provide economical and reliable gas service to customers. See Item 2, Properties. For the year ended December 31, 2000, 72% of total operating revenues was derived from electric operations and 28% 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 $ 205,105 $ 159,670 $ 364,775 47% Commercial 171,414 61,888 233,302 30 7 Industrial 104,738 15,898 120,636 15 Public authorities 54,270 9,193 63,463 8 ------- --------- --------- --------- Total retail 535,527 246,649 782,176 100% ========= Wholesale sales 165,080 17,344 182,424 Gas transported - net -- 6,922 6,922 Provision for rate refunds (2,500) -- (2,500) Miscellaneous 12,851 1,574 14,425 --------- --------- --------- Total $ 710,958 $ 272,489 $ 983,447 ========= ========= =========
See Note 14 of LG&E's Notes to Financial Statements under Item 8 for financial information concerning segments of business for the three years ended December 31, 2000. Electric Operations The sources of LG&E's electric operating revenues and the volumes of sales for the three years ended December 31, 2000, were as follows:
2000 1999 1998 ---- ---- ---- ELECTRIC OPERATING REVENUES (Thousands of $): Residential $205,105 $214,733 $213,476 Commercial 171,414 176,457 170,954 Industrial 104,738 111,889 113,372 Public authorities 54,270 55,968 55,075 -------- ---------- -------- Total retail 535,527 559,047 552,877 Wholesale sales 165,080 221,336 99,340 Provision for rate refunds (2,500) (1,735) (4,500) Miscellaneous 12,851 12,022 10,794 -------- -------- -------- Total $710,958 $790,670 $658,511 ======== ======== ======== ELECTRIC SALES (Thousands of Mwh): Residential 3,722 3,680 3,534 Commercial 3,350 3,290 3,133 Industrial 3,043 3,047 3,097 Public authorities 1,214 1,187 1,140 ------- ------- ------- Total retail 11,329 11,204 10,904 Wholesale sales 6,834 8,428 4,970 ------- ------- ------- Total 18,163 19,632 15,874 ====== ====== ======
LG&E uses efficient coal-fired boilers, fully equipped with sulfur dioxide removal systems, to generate most of its electricity. LG&E's weighted-average system wide emission rate for sulfur dioxide in 2000 was approximately 0.65 lbs./Mmbtu of heat input and, every unit was below its emission limit. The 2000 maximum local peak load of 2,542 Mw occurred on Wednesday, August 9, 2000. The record local peak load of 2,612 Mw occurred on Friday, July 30, 1999, when the temperature was 106 degrees F. The electric utility business is affected by seasonal weather patterns. As a result, operating revenues (and associated operating expenses) are not generated evenly throughout the year. See LG&E's Results of Operations under Item 7. LG&E's current reserve margin is 12%. At December 31, 2000, LG&E owned steam and combustion turbine generating facilities with a capacity of 2,637 Mw and an 80 Mw hydroelectric facility on the Ohio River. See 8 Item 2, Properties. LG&E 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. LG&E 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. LG&E 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. Gas Operations The sources of LG&E's gas operating revenues and the volumes of sales for the three years ended December 31, 2000, were as follows:
2000 1999 1998 ---- ---- ---- GAS OPERATING REVENUES (Thousands of $): Residential $159,670 $103,655 $113,430 Commercial 61,888 38,627 40,888 Industrial 15,898 10,401 11,969 Public authorities 9,193 9,013 8,884 -------- -------- -------- Total retail 246,649 161,696 175,171 Wholesale sales 17,344 8,118 8,720 Gas transported - net 6,922 6,350 6,926 Miscellaneous 1,574 1,415 728 -------- -------- -------- Total $272,489 $177,579 $191,545 ======== ======== ======== GAS SALES (Millions of cu. ft.): Residential 24,274 21,565 20,040 Commercial 10,132 9,033 8,448 Industrial 3,089 2,781 2,860 Public authorities 1,576 2,228 1,967 -------- -------- -------- Total retail 39,071 35,607 33,315 Wholesale sales 5,115 3,881 3,880 Gas transported 14,729 14,014 13,027 -------- -------- -------- Total 58,915 53,502 50,222 ======== ======== =========
The gas utility business is affected by seasonal weather patterns. As a result, operating revenues (and associated operating expenses) are not generated evenly throughout the year. See LG&E's Results of Operations under Item 7. LG&E has underground natural gas storage fields that help provide economical and reliable gas service to ultimate consumers. By using gas storage fields strategically, LG&E can buy gas when prices are low, store it, and retrieve the gas when demand is high. Currently, LG&E buys competitively priced gas from several large producers under contracts of varying duration. By purchasing from multiple suppliers and storing any excess gas, LG&E is able to secure favorably priced gas for its customers. Without storage capacity, LG&E would be forced to buy additional gas when customer demand increases, which is usually when the price is highest. A number of industrial customers purchase their natural gas requirements directly from alternate suppliers for delivery through LG&E's distribution system. Generally, transportation of natural gas for LG&E'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 LG&E economically indifferent as to whether gas is sold or merely transported. 9 The all-time maximum day gas sendout of 545,000 Mcf occurred on Sunday, January 20, 1985, when the average temperature for the day was -11 degrees F. During 2000, maximum day gas sendout was 483,000 Mcf, occurring on December 17, when the average temperature for the day was 10 degrees F. Supply on that day consisted of 205,000 Mcf from purchases, 227,000 Mcf delivered from underground storage, and 51,000 Mcf transported for industrial customers. For a further discussion, see Gas Supply under Item 1. Rates and Regulation Following the merger transaction involving LG&E Energy and Powergen, Powergen became a registered holding company under PUHCA. As a result, Powergen, its utility subsidiaries, including LG&E, and certain of its non-utility subsidiaries are subject to extensive regulation by the SEC under PUHCA with respect to issuances and sales of securities, acquisitions and sales of certain utility properties, and intra-system sales of certain goods and services. In addition, PUHCA generally limits the ability of registered holding companies to acquire additional public utility systems and to acquire and retain businesses unrelated to the utility operations of the holding company. Powergen believes that it has adequate authority (including financing authority) under existing SEC orders and regulations for it and its subsidiaries to conduct their businesses as proposed during 2001. Powergen will seek additional authorization when necessary. The Kentucky Commission has regulatory jurisdiction over the rates and service of LG&E and over the issuance of certain of its securities. The Kentucky Commission has the ability to examine the rates LG&E charges its retail customers at any time. LG&E is a "public utility" as defined in the FPA, and is subject to the jurisdiction of the Department of Energy and the FERC with respect to the matters covered in the FPA, including the sale of electric energy at wholesale in interstate commerce. In addition, the FERC has sole jurisdiction over the issuance by LG&E of short-term securities. For a discussion of current regulatory matters, see Rates and Regulation for LG&E under Item 7 and Note 3 of LG&E's Notes to Financial Statements under Item 8. LG&E's electric rates contain a FAC, whereby increases and decreases in the cost of fuel for electric generation are reflected in the rates charged to all electric customers. The Kentucky Commission requires public hearings at six-month intervals to examine past fuel adjustments, and at two-year intervals to review past operations of the fuel clause and transfer of the then current fuel adjustment charge or credit to the base charges. The Kentucky Commission also requires that electric utilities, including LG&E, file certain documents relating to fuel procurement and the purchase of power and energy from other utilities. LG&E's electric rates are subject to an Earnings Sharing Mechanism. The ESM, in place for three years beginning in 2000, sets an upper and lower point for rate of return on equity, whereby if LG&E's rate of return for the calendar year falls within the range of 10.5% to 12.5%, no action is necessary. If earnings are above the upper limit, then excess earnings are shared 40% with ratepayers and 60% with shareholders; if earnings are below the lower limit, then earnings deficiency is recovered 40% from ratepayers and 60% from shareholders. The first ESM filing was made on March 1, 2001, for year ended December 31, 2000. By order of the Kentucky Commission rate changes prompted by the ESM filing go into effect in April of each year. At December 31, 2000, LG&E recorded in its financial statements an estimated refund to ratepayers of $2.5 million. LG&E's rates contain an ECR surcharge which recovers certain costs incurred by LG&E that are required to comply with the Clean Air Act and other environmental regulations. See Note 3 of LG&E's Notes to Financial Statements under Item 8. LG&E's gas rates contain a GSC, whereby increases or decreases in the cost of gas supply are reflected in LG&E's 10 rates, subject to approval of the Kentucky Commission. The GSC procedure prescribed by order of the Kentucky Commission provides for quarterly rate adjustments to reflect the expected cost of gas supply in that quarter. In addition, the GSC contains a mechanism whereby any over- or under-recoveries of gas supply cost from prior quarters will be refunded to or recovered from customers through the adjustment factor determined for subsequent quarters. In February 2001, the Kentucky Commission ordered LG&E to make monthly GSC filings. Integrated resource planning regulations in Kentucky require LG&E and the other major utilities to make triennial filings with the Kentucky Commission of various historical and forecasted information relating to forecasted load, capacity margins and demand-side management techniques. The last integrated resource plan was filed in 1999. Pursuant to Kentucky law, the Kentucky Commission has established the boundaries of the service territory or area of each retail electric supplier in Kentucky (including LG&E), other than municipal corporations, within which each such supplier has the exclusive right to render retail electric service. Construction Program and Financing LG&E's construction program is designed to ensure that there will be adequate capacity and reliability to meet the electric and gas needs of its service area. These needs are continually being reassessed and appropriate revisions are made, when necessary, in construction schedules. LG&E's estimates of its construction expenditures can vary substantially due to numerous items beyond LG&E'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, 2000, gross property additions amounted to $696 million. Internally generated funds and external financings for the five-year period were sufficient to provide for all of these gross additions. The gross additions during this period amounted to approximately 22% of total utility plant at December 31, 2000, and consisted of $538 million for electric properties and $158 million for gas properties. Gross retirements during the same period were $108 million, consisting of $79 million for electric properties and $29 million for gas properties. Coal Supply Coal-fired generating units provided more than 97% of LG&E's net kilowatt-hour generation for 2000. The remainder of 2000 net generation was made up of a hydroelectric plant and natural gas and oil fueled combustion turbine peaking units. Coal will be the predominant fuel used by LG&E in the foreseeable future, with natural gas and oil being used for peaking capacity and flame stabilization in coal-fired boilers or in emergencies. LG&E has no nuclear generating units and has no plans to build any in the foreseeable future. LG&E has entered into coal supply agreements with various suppliers for coal deliveries for 2001 and beyond. LG&E normally augments its coal supply agreements with spot market purchases. LG&E has a coal inventory policy which it believes provides adequate protection under most contingencies. LG&E had a coal inventory of approximately 425,811 tons, or a 22-day supply, on hand at December 31, 2000. LG&E expects to continue purchasing most of its coal, which has a sulfur content in the 2%-4.5% range, from western Kentucky, southwest Indiana, and West Virginia for the foreseeable future. This supply is relatively low priced coal, and in combination with its sulfur dioxide removal systems is expected to enable LG&E to continue to provide adequate electric service in compliance with existing environmental laws and regulations. Coal is delivered for LG&E's Mill Creek plant by rail and barge; Trimble County plant by barge and Cane Run plant by rail. 11 The historical average delivered costs of coal purchased by LG&E were as follows:
2000 1999 1998 ---- ---- ---- Per ton $20.96 $21.49 $22.38 Per Mmbtu $ .92 $ .95 $ .98 Spot purchases as % of all sources 1% 5% 24%
The delivered cost of coal is expected to remain flat during 2001 due to contracts to buy coal already in place, although there has been a recent coal price increase for spot purchases. Gas Supply LG&E purchases natural gas supplies from multiple sources under contracts for varying periods of time, while transportation services are purchased from Texas Gas and Tennessee Gas. During 2000, Texas Gas filed with FERC for a change in its rates as required under the settlement in its last rate case. The requested increase, the resolution of that case, and the timing and amounts of refunds, if any, are not known at this time. LG&E participates in that and other proceedings, as appropriate. LG&E transports on the Texas Gas system under NNS and FT rates. During the winter months, LG&E has 184,900 Mmbtu per day in NNS. LG&E's summer NNS levels are 60,000 Mmbtu per day and its summer FT levels are 54,000 Mmbtu per day. Each of these NNS and FT agreements with Texas Gas expire in equal portions in 2001, 2003, and 2005. LG&E also transports on the Tennessee Gas system under Tennessee's Gas Rate FT-A. LG&E's contract levels with Tennessee Gas are 51,000 Mmbtu per day annually. The FT-A agreement with Tennessee Gas expires 2002. LG&E 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 that are market-responsive. These firm supplies, in tandem with pipeline transportation services, provide the reliability and flexibility necessary to serve LG&E's customers. LG&E 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 1999-2000 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 LG&E was $5.08 in 2000, $2.99 in 1999 and $3.05 in 1998. Natural gas prices in the unregulated wholesale market increased significantly throughout 2000, particularly as the year progressed. Natural gas prices have increased above historic levels due to record cold temperatures, decreased exploration and production levels, and higher demand by electric generators. Environmental Matters Protection of the environment is a major priority for LG&E. LG&E engages in a variety of activities within the jurisdiction of federal, state, and local regulatory agencies. Those agencies have issued LG&E permits for various activities subject to air quality, water quality, and waste management laws and regulations. For the five-year period 12 ending with 2000, expenditures for pollution control facilities represented $124 million or 19% of total construction expenditures. LG&E estimates that construction expenditures for the installation of nitrogen oxide control equipment from 2001 through 2004 will be approximately $150 million. For a discussion of environmental matters, see Rates and Regulation for LG&E under Item 7 and Note 12 of LG&E's Notes to Financial Statements under Item 8. Competition In the last several years, LG&E 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; write-offs of previously deferred expenses; an increase in focus on commercial, industrial and residential customers; an increase in employee involvement and training; a major realignment and formation of new business units, and continuous modifications of its organizational structure. LG&E will continue to take additional steps to better position itself for competition in the future. See Note 16 of LG&E's Notes to Financial Statements under Item 8. KENTUCKY UTILITIES COMPANY General KU was incorporated in Kentucky in 1912 and incorporated in Virginia in 1991. KU is a regulated public utility engaged in producing, transmitting and selling electric energy. KU provides electric service to approximately 464,000 customers in over 600 communities and adjacent suburban and rural areas in 77 counties in central, southeastern and western Kentucky, and to approximately 29,000 customers in 5 counties in southwestern Virginia. In Virginia, KU operates under the name Old Dominion Power Company. KU operates under appropriate franchises in substantially all of the 160 Kentucky incorporated municipalities served. No franchises are required in unincorporated Kentucky or Virginia communities. The lack of franchises is not expected to have a material adverse effect on KU's operations. KU also sells wholesale electric energy to 12 municipalities. Electric Operations The sources of KU's electric operating revenues and the volumes of sales for the three years ended December 31, 2000, were as follows:
2000 1999 1998 ---- ---- ---- ELECTRIC OPERATING REVENUES (Thousands of $): Residential $241,783 $242,304 $238,566 Commercial 161,291 160,895 158,340 Industrial 153,017 154,460 154,475 Mine Power 27,089 28,792 31,620 Public authorities 57,979 58,500 58,740 -------- -------- -------- Total retail 641,159 644,951 641,741 Wholesale sales 198,073 286,595 179,118 Provision for rate refunds - (5,900) (21,500) Miscellaneous 12,709 11,664 10,755 -------- -------- -------- Total $851,941 $937,310 $810,114 ======== ======== ======== ELECTRIC SALES (Thousands of Mwh): Residential 5,714 5,447 5,247 Commercial 3,954 3,760 3,644 13 Industrial 5,044 4,911 4,747 Mine Power 767 752 838 Public authorities 1,495 1,437 1,424 -------- -------- -------- Total retail 16,974 16,307 15,900 Wholesale sales 7,573 10,188 7,224 -------- -------- -------- Total 24,547 26,495 23,124 ======== ======== ========
The electric utility business is affected by seasonal weather patterns. As a result, operating revenues (and associated operating expenses) are not generated evenly throughout the year. See KU's Results of Operations under Item 7. KU's weighted-average system wide emission rate for sulfur dioxide in 2000 was approximately 1.3 lbs./Mmbtu of heat input and, every unit was below its emission limit. KU's current reserve margin is 12%. At December 31, 2000, KU owned steam and combustion turbine generating facilities with a capacity of 3,832 Mw and a 24 Mw hydroelectric facility. See Item 2, Properties. KU obtains power from other utilities under bulk power purchase and interchange contracts. At December 31, 2000, KU's system capability, including purchases from others, was 4,308 Mw. On August 9, 2000, a record local peak load was set at 3,775 Mw. Under a contract expiring in 2020 with OMU, KU has agreed to purchase from OMU the surplus output of the 150-Mw and 250-Mw generating units at OMU's Elmer Smith station. Purchases under the contract are made under a contractual formula which has resulted in costs which were and are expected to be comparable to the cost of other power purchased or generated by KU. Such power constituted about 7% of KU's net system output during 2000. See Note 11 of KU's Notes to Financial Statements under Item 8. KU owns 20% of the common stock of EEI, which owns and operates a 1,000-Mw generating station in southern Illinois. KU is entitled to take 20% of the available capacity of the station. Purchases from EEI are made under a contractual formula which has resulted in costs which were and are expected to be comparable to the cost of other power purchased or generated by KU. Such power constituted about 6% of KU's net system output in 2000. See Note 11 of KU's Notes to Financial Statements under Item 8. Rates and Regulation Following the merger transaction involving LG&E Energy and Powergen, Powergen became a registered holding company under PUHCA. As a result, Powergen, its utility subsidiaries, including KU, and certain of its non-utility subsidiaries are subject to extensive regulation by the SEC under PUHCA with respect to issuances and sales of securities, acquisitions and sales of certain utility properties, and intra-system sales of certain goods and services. In addition, PUHCA generally limits the ability of registered holding companies to acquire additional public utility systems and to acquire and retain businesses unrelated to the utility operations of the holding company. Powergen believes that it has adequate authority (including financing authority) under existing SEC orders and regulations for it and its subsidiaries to conduct their businesses as proposed during 2001. Powergen will seek additional authorization when necessary. The Kentucky Commission and the Virginia Commission have regulatory jurisdiction over KU's retail rates and service, and over the issuance of certain of its securities. By reason of owning and operating a small amount of electric utility property in one county in Tennessee (having a gross book value of about $225,000) from which KU serves five customers, KU is subject to the jurisdiction of the TRA. FERC has classified KU as a "public utility" as defined in the FPA. FERC has jurisdiction under the FPA over certain of the electric utility facilities and operations, wholesale sale of power and related transactions and accounting practices of KU, and in certain 14 other respects as provided in the FPA. In addition, the FERC has sole jurisdiction over the issuance by KU of short-term securities. For a discussion of current regulatory matters, see Rates and Regulation for KU under Item 7 and Note 3 of KU's Notes to the Financial Statements under Item 8. KU's Kentucky retail electric rates contain a FAC, whereby increases and decreases in the cost of fuel for electric generation are reflected in the rates charged to all electric customers. The Kentucky Commission requires public hearings at six-month intervals to examine past fuel adjustments, and at two-year intervals to review past operations of the fuel clause and transfer of the then current fuel adjustment charge or credit to the base charges. The Kentucky Commission also requires that electric utilities, including KU, file certain documents relating to fuel procurement and the purchase of power and energy from other utilities. The FAC mechanism for Virginia customers uses an average fuel cost factor based primarily on projected fuel costs. The fuel cost factor may be adjusted annually for over- or under collections of fuel costs from the previous year. KU's Kentucky retail electric rates are subject to an Earnings Sharing Mechanism. The ESM, in place for three years beginning in 2000, sets an upper and lower point for rate of return on equity, whereby if KU's rate of return for the calendar year falls within the range of 10.5% to 12.5%, no action is necessary. If earnings are above the upper limit, then excess earnings are shared 40% with ratepayers and 60% with shareholders; if earnings are below the lower limit, then earnings deficiency is recovered 40% from ratepayers and 60% from shareholders. The first ESM filing was made on March 1, 2001, for year ended December 31, 2000. By order of the Kentucky Commission rate changes prompted by the ESM filing go into effect in April of each year. At December 31, 2000, KU expects to fall within the range, therefore no adjustment was made to the financial statements. KU's Kentucky rates contain an ECR surcharge which recovers certain costs incurred by KU that are required to comply with the Clean Air Act and other environmental regulations. See Note 3 of KU's Notes to Financial Statements under Item 8. Integrated resource planning regulations in Kentucky require KU and the other major utilities to make triennial filings with the Kentucky Commission of various historical and forecasted information relating to forecasted load, capacity margins and demand-side management techniques. The last integrated resource plan was filed in 1999. Pursuant to Kentucky law, the Kentucky Commission has established the boundaries of the service territory or area of each retail electric supplier in Kentucky (including KU), other than municipal corporations, within which each such supplier has the exclusive right to render retail electric service. KU customers in Virginia will have retail choice beginning January 2002, pursuant to the Virginia Electric Restructuring Act. KU has filed unbundled rates that become effective January 1, 2002, for those customers who choose an energy provider other than KU. Rates are capped at current levels through June 2007. The Virginia Commission will continue to require each Virginia utility to make annual filings of either a base rate change or an Annual Informational Filing consisting of a set of standard financial schedules. These filings are subject to review by the Virginia Staff. The Virginia Staff issues a Staff Report, which includes any findings or recommendations to the Virginia Commission relating to the individual utility's financial performance during the historic 12-month period, including previously accepted adjustments. The Staff Report can lead to an adjustment in rates, but will be limited to decreases through June 2007. Construction Program and Financing 15 KU's construction program is designed to ensure that there will be adequate capacity and reliability to meet the electric needs of its service area. These needs are continually being reassessed and appropriate revisions are made, when necessary, in construction schedules. KU's estimates of its construction expenditures can vary substantially due to numerous items beyond KU'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, 2000, gross property additions amounted to $574 million. Internally generated funds and external financings for the five-year period were sufficient to provide for all of these gross additions. The gross additions during this period amounted to approximately 20% of total utility plant at December 31, 2000. Gross retirements during the same period were $88 million. Coal Supply Coal-fired generating units provided more than 99% of KU's net kilowatt-hour generation for 2000. The remainder of KU's net generation for 2000 was provided by oil and/or natural gas burning units and hydroelectric plants. The historical average delivered cost of coal purchased and the percentage of spot coal purchases were as follows:
2000 1999 1998 ---- ---- ---- Per ton $25.63 $26.65 $26.97 Per Mmbtu $1.07 $1.11 $1.12 Spot purchases as % of all sources 51% 53% 42%
The delivered cost of coal is expected to increase during 2001. KU's historical average cost of coal purchased is higher than LG&E's due to the lower sulfur content of the coal KU purchases for use at its Ghent plant and higher cost to transport coal to the E.W. Brown plant. KU maintains its fuel inventory at levels estimated to be necessary to avoid operational disruptions at its coal-fired generating units. Reliability of coal deliveries can be affected from time to time by a number of factors, including fluctuations in demand, coal mine labor issues and other supplier or transporter operating difficulties. KU believes there are adequate reserves available to supply its existing base-load generating units with the quantity and quality of coal required for those units throughout their useful lives. KU intends to meet a portion of its coal requirements with three-year or shorter contracts. As part of this strategy, KU will continue to negotiate replacement contracts as contracts expire. KU does not anticipate any problems negotiating new contracts for future coal needs. The balance of coal requirements will be met through spot purchases. KU had a coal inventory of approximately 403,436 tons, or an 18-day supply, on hand at December 31, 2000. KU expects to continue purchasing most of its coal, which has a sulfur content in the .7% - 3.5% range, from western and eastern Kentucky, West Virginia, southwest Indiana, Wyoming and Pennsylvania for the foreseeable future. Coal for Ghent is delivered by barge. Deliveries to the Tyrone, Green River and Pineville locations are by truck. Delivery to E.W. Brown is by rail. KU has no long-term contracts in place for the purchase of natural gas for its combustion turbine peaking units. KU has met its gas requirements through spot purchases and does not anticipate encountering any significant problems acquiring an adequate supply of fuel necessary to operate its peaking units. 16 Environmental Matters Protection of the environment is a major priority for KU. KU engages in a variety of activities within the jurisdiction of federal, state, and local regulatory agencies. Those agencies have issued KU permits for various activities subject to air quality, water quality, and waste management laws and regulations. For the five-year period ending with 2000, expenditures for pollution control facilities represented $42 million or 7% of total construction expenditures. KU estimates that construction expenditures for the installation of nitrogen oxide control equipment from 2001 through 2004 will be approximately $190 million. See Note 11 of KU's Notes to Financial Statements under Item 8. Competition KU 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; an increase in focus on not only commercial and industrial customers, but residential customers as well; an increase in employee involvement and training; and continuous modifications of its organizational structure. KU will continue to take additional steps to better position itself for competition in the future. See Note 14 of KU's Notes to Financial Statements under Item 8. EMPLOYEES AND LABOR RELATIONS LG&E had 2,003 full-time employees and KU had 1,475 full-time employees at December 31, 2000. Of the LG&E total, 1,192 operating, maintenance, and construction employees were members of IBEW Local 2100. The current three-year contract with the IBEW will expire in November 2001. Of the KU total, 221 operating, maintenance, and construction employees were members of IBEW Local 2100 and USWA Local 9447-01. In August 2000, KU and employees represented by IBEW Local 2100 entered into a one-year collective bargaining agreement. At the same time, KU and employees represented by USWA entered into a two-year collective bargaining agreement. As a result of the Powergen merger and in order to comply with the Public Utility Holding Company Act of 1935, LG&E Services was formed and became effective on January 1, 2001. LG&E Services provides certain services to affiliated entities, including LG&E and KU, at cost as required under the Holding Company Act. On January 1, 2001, approximately 1,000 employees, mainly from LG&E Energy, LG&E and KU, were moved to LG&E Services. See Note 16 of LG&E's Notes to Financial Statements and Note 14 of KU's Notes to Financial Statements under Item 8 for workforce separation program in effect for 2001. These separation programs are anticipated to result in workforce reductions of approximately 700 and 250 employees at LG&E and KU, respectively. ITEM 2. Properties. LG&E'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. LG&E owns and operates the following electric generating stations:
Capability Rating (Kw) ----------- Steam Stations: Mill Creek - Kosmosdale, KY. Unit 1 303,000 17 Unit 2 301,000 Unit 3 386,000 Unit 4 480,000 --------- Total Mill Creek 1,470,000 Cane Run - near Louisville, KY. Unit 4 155,000 Unit 5 168,000 Unit 6 240,000 --------- Total Cane Run 563,000 Trimble County - Bedford, KY. (a) Unit 1 371,000 Combustion Turbine Generators (Peaking capability): Zorn 16,000 Paddy's Run 43,000 Cane Run 16,000 Waterside 33,000 E.W. Brown (b) 125,000 --------- Total combustion turbine generators 233,000 --------- Total capability rating 2,637,000 =========
(a) Amount shown represents LG&E's 75% interest in Trimble County. See Note 13 of LG&E's Notes to Financial Statements, Jointly Owned Electric Utility Plant, under Item 8 for further discussion on ownership. (b) Amount shown represents LG&E's 38% interest in Unit 6 and 7 at E.W. Brown. See Notes 12 and 13 of LG&E's Notes to Financial Statements, under Item 8 for further discussion on ownership. LG&E also owns an 80 Mw hydroelectric generating station located in Louisville, operated under license issued by the FERC. At December 31, 2000, LG&E's electric transmission system included 21 substations with a total capacity of approximately 11,519,700 Kva and approximately 652 structure miles of lines. The electric distribution system included 84 substations with a total capacity of approximately 3,448,730 Kva, 3,693 structure miles of overhead lines, 366 miles of underground conduit, and 5,694 miles of underground conductors. LG&E's gas transmission system includes 212 miles of transmission mains, and the gas distribution system includes 3,885 miles of distribution mains. LG&E 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, LG&E entered into an operating lease for its corporate office building located in downtown Louisville, Kentucky. The lease is for a period of 15 years and is scheduled to expire June 2005. Other properties owned by LG&E 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 LG&E's First Mortgage Bonds constitutes a direct first mortgage lien upon much of the property owned by LG&E. 18 KU's power generating system consists of the coal-fired units operated at its five steam generating stations. Combustion turbines supplement the system during peak or emergency periods. KU owns and operates the following electric generating stations:
Capability Rating (Kw) ----------- Steam Stations: Tyrone - Tyrone, KY. Unit 1 27,000 Unit 2 31,000 Unit 3 71,000 --------- Total Tyrone 129,000 Green River - South Carrollton, KY. Unit 1 26,000 Unit 2 27,000 Unit 3 71,000 Unit 4 103,000 --------- Total Green River 227,000 E.W. Brown - Burgin, KY. Unit 1 104,000 Unit 2 168,000 Unit 3 439,000 --------- Total E.W. Brown 711,000 Pineville - Four Mile, KY. Unit 3 34,000 Ghent - Ghent, KY. Unit 1 483,000 Unit 2 492,000 Unit 3 493,000 Unit 4 494,000 --------- Total Ghent 1,962,000 Combustion Turbine Generators (Peaking capability): E.W. Brown - Burgin, KY. (Units 6-11) (a) 724,000 Haefling - Lexington, KY. 45,000 --------- Total combustion turbine generators 769,000 --------- Total capability rating 3,832,000 =========
(a) Amount shown includes the KU's 62% interest in Unit 6 and 7 at E.W. Brown and 100% of four other units. See Notes 11 and 12 of KU's Notes to Financial Statements, under Item 8 for further discussion on ownership. Substantially all properties are subject to the lien of KU's Mortgage Indenture. KU also owns a 24 Mw hydroelectric generating station located in Burgin, Kentucky, operated under license issued by the FERC. 19 At December 31, 2000, KU's electric transmission system included 112 substations with a total capacity of approximately 14,855,396 Kva and approximately 4,227 structure miles of lines. The electric distribution system included 438 substations with a total capacity of approximately 5,046,307 Kva and 14,772 structure miles of lines. ITEM 3. Legal Proceedings. Rates and Regulatory Matters For a discussion of current regulatory matters, including, among others, a discussion of (a) rate matters related to the Kentucky Commission's proceeding involving LG&E's and KU's PBR filings and ESM filings, (b) proceedings before the Kentucky Supreme Court and the Kentucky Commission regarding environmental cost recovery surcharge refunds, and (c) fuel adjustment clause proceedings before the Kentucky Commission regarding electric line loss refunds, see Rates and Regulation under Item 7 and Notes 3 and 12 of LG&E's Notes to Financial Statements and Notes 3 and 11 of KU's Notes to Financial Statements under Item 8. Performance-Based Ratemaking In October, 1998, LG&E and KU filed applications with the Kentucky Commission for approval of the PBR proposal for determining electric rates. In January 2000, the Kentucky Commission issued orders requiring LG&E and KU to reduce annual base rates, effective March 1, 2000. The orders also eliminated the temporary effectiveness of the PBR proposal, reinstated the FAC mechanism and offered the utilities a three year ESM program whereby incremental annual earnings above or below a range of 10.5% to 12.5% would be shared 60% with shareholders and 40% with ratepayers. In February 2000, LG&E and KU filed tariffs incorporating the ESM. In June 2000, the Kentucky Commission issued orders reducing the original January 2000 base rate reductions to now require reductions in base rates of approximately $26.3 million at LG&E and $30.4 million at KU, effective June 1, 2000. The orders implemented LG&E's and KU's ESM tariffs, with certain modifications, for a three year term. No parties filed appeals from the Kentucky Commission's orders within the time allowed by statute. See Rates and Regulations under Item 7 and Note 3 to LG&E's Notes to Financial Statements and Note 3 to KU's Notes to Financial Statements under Item 8. Fuel Adjustment Clause Proceedings Pursuant to Kentucky statute, LG&E and KU operate under six-month and two-year reviews by the Kentucky Commission of the fuel cost incurred to serve their customers. Both LG&E and KU have participated in proceedings in front of the Kentucky Commission concerning the recovery of fuel costs associated with wholesale sales and recovery of purchased power energy costs. As a result of these proceedings, the Kentucky Commission issued orders in August 1999 requiring aggregate refunds totaling approximately $800,000 for LG&E and $6.7 million for KU for the periods between November 1996 to August 2000. The issue of whether interest on these amounts is to be refunded has been appealed to the Kentucky Court of Appeals by LG&E, KU and the intervenor group, with a final ruling expected in late 2001 or early 2002. See also Note 3 to LG&E's Notes to Financial Statements and Note 3 to KU's Notes to Financial Statements under Item 8. See Rates and Regulatory Matters above regarding further matters arising during LG&E's and KU's FAC proceedings. Environmental For a discussion of environmental matters concerning (a) currently proposed reductions in NOx and SO2 emission limits, (b) issues at LG&E's Mill Creek generating plant and LG&E's and KU's manufactured gas plant sites, and (c) other environmental items affecting LG&E and KU, see Environmental Matters under Item 7 and Note 12 of LG&E's Notes to Financial Statements and Note 11 of KU's Notes to Financial Statements under 20 Item 8, respectively. Other In the normal course of business, other lawsuits, claims, environmental actions, and other governmental proceedings arise against LG&E and KU. To the extent that damages are assessed in any of these lawsuits, LG&E and KU believe that their 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 LG&E's or KU's consolidated financial position or results of operations, respectively. ITEM 4. Submission of Matters to a Vote of Security Holders. None. Executive Officers of LG&E at December 31, 2000:
Effective Date of Election to Present Name Age Position Position ---- --- -------- -------- Roger W. Hale 56 Chairman of the January 1, 1992 Board, and Chief Executive Officer Victor A. Staffieri 46 President and June 7, 2000 Chief Operating Officer R. Foster Duncan* 46 Executive Vice February 16, 1999 President and Chief Financial Officer John R. McCall 57 Executive Vice July 1, 1994 President, General Counsel and Corporate Secretary Frederick J. Newton III 45 Senior Vice January 2, 1999 President and Chief Administrative Officer S. Bradford Rives 42 Senior Vice December 11, 2000 President - Finance and Controller Paul W. Thompson 43 Senior Vice June 7, 2000 President - Energy Services Chris Hermann 53 Senior Vice December 11, 2000 President - Distribution Operations Wendy C. Welsh 46 Senior Vice December 11, 2000 President - Information Technology Martyn Gallus 36 Senior Vice December 11, 2000 President - Energy Marketing 21 David A. Vogel 35 Vice President - December 11, 2000 Retail Services Daniel K. Arbough 39 Treasurer December 11, 2000
* Effective January 31, 2001, Richard Aitken-Davies was appointed Chief Financial Officer. 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 Shareholders, scheduled to be held in June 2001. There are no family relationships between or among executive officers of LG&E and KU. Before he was elected to his current positions, Mr. Hale was Chairman of the Board and Chief Executive Officer of LG&E Energy Corp. from August 1990 to the present and Chairman of the Board and Chief Executive Officer of LG&E from January 1992 to the present. Before he was elected to his current positions, Mr. Staffieri was President of LG&E from January 1994 to May 1997; President --Distribution Services of LG&E Energy Corp. from December 1995 to May 1997; Chief Financial Officer of LG&E Energy Corp and LG&E from May 1997 to February 1999 and Chief Financial Officer of KU from May 1998 to February 1999. Before he was elected to his indicated positions, Mr. Duncan was Vice President and Corporate Treasurer of Freeport-McMoRan, Inc. and Freeport-McMoRan Copper & Gold Inc. and their affiliates from May 1994 to January 1998; and Executive Vice President - Planning and Development of LG&E Energy Corp. from January 1998 to February 1999. Before he was elected to his current positions, Mr. McCall was Executive Vice President, General Counsel and Corporate Secretary of LG&E Energy Corp. and LG&E from July 1994 to the present. Before he was elected to his current positions, Mr. Newton was Director of Human Resources, Manufacturing and Engineering at Unilever from October 1993 to July 1995; Senior Director, Human Resources, Supply Chain, at Unilever from August 1995 to July 1996; Vice President, Human Resources, at Venator Group from August 1996 to July 1997; Senior Vice President, Human Resources, at Venator Group's Champs Sports Division from August 1997 to April 1998; and Senior Vice President - Human Resources and Administration of LG&E Energy Corp., LG&E and KU from May 1998 to January 1999. Before he was elected to his current positions, Mr. Rives was Vice President and Treasurer of LG&E Power Inc. from June 1994 to March 1995; Vice President, Controller and Treasurer of LG&E Power Inc. from March 1995 to December 1995; Vice President - Finance, Non-Utility Businesses of LG&E Energy Corp. from January 1996 to March 1996; Vice President - Finance and Controller of LG&E Energy Corp. from March 1996 to February 1999; and Senior Vice President - Finance and Business Development from February 1999 to December 2000. Before he was elected to his current positions, Mr. Thompson was Vice President - Business Development for LG&E Energy Corp. from July 1994 to September 1996; Vice President, Retail Electric Business for LG&E from September 1996 to June 1998; Group Vice President for LG&E Energy Marketing, Inc. from June 1998 to August 1999; Vice President, Retail Electric Business for LG&E from December 1998 to August 1999; and Senior Vice President - Energy Services for LG&E Energy Corp. from August 1999 to June 2000. 22 Before he was elected to his current positions, Mr. Hermann was Vice President and General Manager, Wholesale Electric Business of LG&E from January 1993 to June 1997; Vice President, Business Integration of LG&E from June 1997 to May 1998; and Vice President, Power Generation and Engineering Services, of LG&E from May 1998 to December 1999. Before she was elected to her current positions, Ms. Welsh was Vice President - Information Services of LG&E from January 1994 to May 1997; and Vice President, Administration of LG&E Energy Corp. from May 1997 to February 1998. Before he was elected to his current positions, Mr. Gallus was Director, Risk Management, then Director, Product Development, then Vice President, Trading, then Senior Vice President, of LG&E Energy Marketing Inc., respectively, beginning in February 1996. Before he was elected to his current positions, Mr. Vogel served in management positions within the Gas Department of LG&E during the five prior years to this report. Before he was elected to his current position, Mr. Arbough was Manager, Corporate Finance of LG&E Energy Corp., and LG&E from August 1996 to May 1998; Director, Corporate Finance of LG&E Energy Corp., LG&E and KU from May 1998 to present. Executive Officers of KU at December 31, 2000:
Effective Date of Election to Present Name Age Position Position ---- --- -------- -------- Roger W. Hale 56 Chairman of the Board, May 4, 1998 and Chief Executive Officer Victor A. Staffieri 46 President and Chief June 7, 2000 Operating Officer R. Foster Duncan* 46 Executive Vice President February 16, 1999 and Chief Financial Officer John R. McCall 57 Executive Vice President, May 4, 1998 General Counsel and Corporate Secretary Frederick J. Newton III 45 Senior Vice President and January 2, 1999 Chief Administrative Officer S. Bradford Rives 42 Senior Vice President - December 11, 2000 Finance and Controller Paul W. Thompson 43 Senior Vice President - June 7, 2000 Energy Services Chris Hermann 53 Senior Vice President - December 11, 2000 Distribution Operations 23 Wendy C. Welsh 47 Senior Vice President - December 11, 2000 Information Technology Martyn Gallus 36 Senior Vice President - December 11, 2000 Energy Marketing Gary E. Blake 48 Vice President - Sales May 4, 1998 and Service James J. Ellington 55 Vice President - Power May 4, 1998 Generation David A. Vogel 35 Vice President - Retail December 11, 2000 Services Daniel K. Arbough 39 Treasurer December 11, 2000
* Effective January 31, 2000, Richard Aitken-Davies was appointed Chief Financial Officer. 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 Shareholders, scheduled to be held in June 2001. There are no family relationships between or among executive officers of LG&E and KU. Before he was elected to his current positions, Mr. Hale was Chairman of the Board and Chief Executive Officer of LG&E Energy Corp. from August 1990 to the present and Chairman of the Board and Chief Executive Officer of LG&E from January 1992 to the present. Before he was elected to his current positions, Mr. Staffieri was President of LG&E from January 1994 to May 1997; President --Distribution Services of LG&E Energy Corp. from December 1995 to May 1997; Chief Financial Officer of LG&E Energy Corp and LG&E from May 1997 to February 1999 and Chief Financial Officer of KU from May 1998 to February 1999. Before he was elected to his indicated positions, Mr. Duncan was Vice President and Corporate Treasurer of Freeport-McMoRan, Inc. and Freeport-McMoRan Copper & Gold Inc. and their affiliates from May 1994 to January 1998; and Executive Vice President - Planning and Development of LG&E Energy Corp. from January 1998 to February 1999. Before he was elected to his current positions, Mr. McCall was Executive Vice President, General Counsel and Corporate Secretary of LG&E Energy Corp. and LG&E from July 1994 to the present. Before he was elected to his current positions, Mr. Newton was Director of Human Resources, Manufacturing and Engineering at Unilever from October 1993 to July 1995; Senior Director, Human Resources, Supply Chain, at Unilever from August 1995 to July 1996; Vice President, Human Resources, at Venator Group from August 1996 to July 1997; Senior Vice President, Human Resources, at Venator Group's Champs Sports Division from August 1997 to April 1998; and Senior Vice President - Human Resources and Administration of LG&E Energy Corp., LG&E and KU from May 1998 to January 1999. Before he was elected to his current positions, Mr. Rives was Vice President and Treasurer of LG&E Power Inc. from June 1994 to March 1995; Vice President, Controller and Treasurer of LG&E Power Inc. from March 24 1995 to December 1995; Vice President - Finance, Non-Utility Businesses of LG&E Energy Corp. from January 1996 to March 1996; Vice President - Finance and Controller of LG&E Energy Corp. from March 1996 to February 1999; and Senior Vice President - Finance and Business Development from February 1999 to December 2000. Before he was elected to his current positions, Mr. Thompson was Vice President - Business Development for LG&E Energy Corp. from July 1994 to September 1996; Vice President, Retail Electric Business for LG&E from September 1996 to June 1998; Group Vice President for LG&E Energy Marketing, Inc. from June 1998 to August 1999; Vice President, Retail Electric Business for LG&E from December 1998 to August 1999; and Senior Vice President - Energy Services for LG&E Energy Corp. from August 1999 to June 2000. Before he was elected to his current positions, Mr. Hermann was Vice President and General Manager, Wholesale Electric Business of LG&E from January 1993 to June 1997; Vice President, Business Integration of LG&E from June 1997 to May 1998; and Vice President, Power Generation and Engineering Services, of LG&E from May 1998 to December 1999. Before she was elected to her current positions, Ms. Welsh was Vice President - Information Services of LG&E from January 1994 to May 1997; and Vice President, Administration of LG&E Energy Corp. from May 1997 to February 1998. Before he was elected to his current positions, Mr. Gallus was Director, Risk Management, then Director, Product Development, then Vice President, Trading, then Senior Vice President, of LG&E Energy Marketing Inc., respectively, beginning in February 1996. Before he was elected to his current position, Mr. Blake was Vice President - Retail Marketing of KU from November 1992 to May 1998. Before he was elected to his current position, Mr. Ellington was Superintendent of KU's Ghent plant from May 1986 to May 1998. Before he was elected to his current positions, Mr. Vogel served in management positions within the Gas Department of LG&E during the five prior years to this report. Before he was elected to his current position, Mr. Arbough was Manager, Corporate Finance of LG&E Energy Corp., and LG&E from August 1996 to May 1998; Director, Corporate Finance of LG&E Energy Corp., LG&E and KU from May 1998 to present. PART II. ITEM 5. Market for the Registrant's Common Equity and Related Stockholder Matters. LG&E: All LG&E common stock, 21,294,223 shares, is held by LG&E Energy. Therefore, there is no public market for LG&E's common stock. The following table sets forth LG&E's cash distributions on common stock paid to LG&E Energy (in thousands of $):
2000 1999 ---- ---- 25 First quarter $23,000 $22,000 Second quarter 16,500 22,000 Third quarter 16,500 22,000 Fourth quarter 17,000 23,000
KU: All KU common stock, 37,817,878 shares, is held by LG&E Energy. Therefore, there is no public market for KU's common stock. The following table sets forth KU's cash distributions on common stock paid to LG&E Energy (in thousands of $):
2000 1999 ---- ---- First quarter $19,000 $18,000 Second quarter 25,000 18,000 Third quarter 25,000 18,000 Fourth quarter 25,500 19,000
ITEM 6. Selected Financial Data.
Years Ended December 31 (Thousands of $) ---------------- 2000 1999 1998 1997 1996 ---- ---- ---- ---- ---- LG&E: Operating revenues: Revenues $ 985,947 $ 969,984 $ 854,556 $ 845,543 $ 821,115 Provision for rate refunds (2,500) (1,735) (4,500) -- -- ----------- ----------- ----------- ----------- ----------- Total operating revenues 983,447 968,249 850,056 845,543 821,115 =========== =========== =========== =========== =========== Net operating income: Before unusual items 150,361 142,263 138,207 148,186 147,263 Provision for rate refunds (1,491) (2,172) (2,684) -- -- ----------- ----------- ----------- ----------- ----------- Total net operating income 148,870 140,091 135,523 148,186 147,263 =========== =========== =========== =========== =========== Net income: Before unusual items 112,064 108,442 104,381 113,273 107,941 Provision for rate refunds (1,491) (2,172) (2,684) -- -- Merger costs -- -- (23,577) -- -- ----------- ----------- ----------- ----------- ----------- Net income 110,573 106,270 78,120 113,273 107,941 =========== =========== =========== =========== =========== Net income available for common stock 105,363 101,769 73,552 108,688 103,373 =========== =========== =========== =========== =========== Total assets 2,226,084 2,171,452 2,104,637 2,055,641 2,006,712 =========== =========== =========== =========== =========== Long-term obligations (including amounts due within one year) $ 606,800 $ 626,800 $ 626,800 $ 646,800 $ 646,800 =========== =========== =========== =========== ===========
26 LG&E's Management's Discussion and Analysis of Results of Operations and Financial Condition and LG&E's Notes to Financial Statements should be read in conjunction with the above information.
Years Ended December 31 (Thousands of $) --------------- 2000 1999 1998 1997 1996 ----------- ----------- ----------- ----------- ----------- KU: Operating revenues: Revenues $ 851,941 $ 943,210 $ 831,614 $ 716,437 $ 711,711 Provision for rate refund -- (5,900) (21,500) -- -- ----------- ----------- ----------- ----------- ----------- Operating revenues 851,941 937,310 810,114 716,437 711,711 =========== =========== =========== =========== =========== Net operating income: Before unusual items 128,136 139,534 138,263 118,408 117,337 Provision for rate refund -- (3,518) (12,875) -- -- ----------- ----------- ----------- ----------- ----------- Operating income 128,136 136,016 125,388 118,408 117,337 =========== =========== =========== =========== =========== Net income: Before unusual items 95,524 110,076 107,303 85,713 86,163 Provision for rate refund -- (3,518) (12,875) -- -- Merger costs -- -- (21,664) -- -- ----------- ----------- ----------- ----------- ----------- Net income 95,524 106,558 72,764 85,713 86,163 =========== =========== =========== =========== =========== Net income available for common stock 93,268 104,302 70,508 83,457 83,907 =========== =========== =========== =========== =========== Total assets 1,739,518 1,785,090 1,761,201 1,679,880 1,673,055 =========== =========== =========== =========== =========== Long-term obligations (including amounts due within one year) $ 484,830 $ 546,330 $ 546,330 $ 546,351 $ 546,373 =========== =========== =========== =========== ===========
KU's Management's Discussion and Analysis of Results of Operations and Financial Condition and KU's Notes to Financial Statements should be read in conjunction with the above information. ITEM 7. Management's Discussion and Analysis of Results of Operations and Financial Condition. LG&E: GENERAL The following discussion and analysis by management focuses on those factors that had a material effect on LG&E's financial results of operations and financial condition during 2000, 1999, and 1998 and should be read in connection with the financial statements and notes thereto. Some of the following discussion may contain forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words "anticipate," "expect," "estimate," "objective," "possible," "potential" and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include: general economic conditions; business and competitive conditions in the energy industry; changes in federal or state legislation; unusual weather; actions by state or federal regulatory agencies; and other factors described from time to time in LG&E's reports to the Securities and Exchange Commission, including Exhibit No. 99.01 to this report on Form 27 10-K. MERGER On December 11, 2000, LG&E Energy Corp. and Powergen plc successfully completed the merger transaction involving the two companies. LG&E Energy had announced on February 28, 2000, that its Board of Directors accepted the offer to be acquired by Powergen for cash of approximately $3.2 billion or $24.85 per share and the assumption of $2.2 billion of LG&E Energy's debt. Pursuant to the acquisition agreement, LG&E Energy became a wholly owned subsidiary of Powergen and, as a result, LG&E became an indirect subsidiary of Powergen. LG&E will continue its separate identity and serve customers in Kentucky under its existing name. The preferred stock and debt securities of LG&E were not affected by this transaction and LG&E will continue to file SEC reports. Following the merger, Powergen became a registered holding company under PUHCA, and LG&E, as a subsidiary of a registered holding company, became subject to additional regulation under PUHCA. See "Rates and Regulation" under Item 1. Effective May 4, 1998, following the receipt of all required state and federal regulatory approvals, LG&E Energy and KU Energy merged, with LG&E Energy as the surviving corporation. The outstanding preferred stock of LG&E, a subsidiary of LG&E Energy, was not affected by the merger. See Note 2 of LG&E's Notes to Financial Statements under Item 8. RESULTS OF OPERATIONS Net Income LG&E's net income increased $4.3 million for 2000, as compared to 1999. This increase is mainly due to higher gas sales resulting from the colder winter weather experienced in 2000, lower administrative costs and operating expenses at the electric generating stations, partially offset by decreased electric revenues due to a rate reduction ordered by the Kentucky Commission and higher maintenance expenses. Net income increased $28.2 million for 1999, compared to 1998, primarily due to non-recurring charges in 1998 for merger-related expenses of $23.6 million, after tax. Excluding these non-recurring charges, net income increased $4.6 million. This increase is mainly due to higher electric revenues, lower administrative costs and operating expenses at the electric generating stations, partially offset by higher maintenance expenses at the electric generating stations. Revenues A comparison of operating revenues for the years 2000 and 1999, excluding the provisions recorded for refunds in 2000 and in 1999, with the immediately preceding year reflects both increases and decreases, which have been segregated by the following principal causes (in thousands of $):
Increase (Decrease) From Prior Period Electric Revenues Gas Revenues Cause 2000 1999 2000 1999 ---------------------------- --------- --------- --------- --------- Retail sales: Fuel and gas supply adjustments, etc $ (9,027) $ (2,014) $ 57,156 $ (24,791) 28 Merger surcredit (2,331) (4,194) -- -- Performance based rate 4,114 (6,076) -- -- Demand side management/ decoupling 6 (2,985) (20) (6,462) Environmental cost recovery surcharge (1,308) (570) -- -- Electric rate reduction (20,727) -- -- -- Gas rate increase -- -- 4,221 -- Variation in sales volumes 5,753 22,009 23,596 17,779 --------- --------- --------- --------- Total retail sales (23,520) 6,170 84,953 (13,474) Wholesale sales (56,256) 121,996 9,226 (602) Gas transportation-net -- -- 572 (575) Other 829 1,228 159 685 --------- --------- --------- --------- Total $ (78,947) $ 129,394 $ 94,910 $ (13,966) ========= ========= ========= =========
Electric revenues decreased in 2000 primarily due to a decrease in brokered activity in the wholesale electric sales market and the electric rate reduction ordered by the Kentucky Commission. In January 2000, the Kentucky Commission ordered an electric rate reduction and the termination of LG&E's proposed electric PBR mechanism. Gas revenues increased primarily as a result of higher gas supply costs billed to customers through the gas supply clause coupled with increased gas sales in 2000 due to colder weather, as heating degree days increased 15% over 1999. Increased wholesale gas sales, and the effects of a gas rate increase ordered by the Kentucky Commission in September 2000 also contributed to increased gas revenues. Electric revenues increased in 1999 primarily due to wholesale electric sales and higher levels of retail sales volumes, partially offset by the PBR and merger surcredit bill reductions. Wholesale sales increased in 1999 due to large amounts of power available. Gas revenues decreased primarily as a result of lower gas supply costs billed to customers through the gas supply clause, partially offset by increased gas sales in 1999 due to colder weather. Expenses Fuel for electric generation and gas supply expenses comprises a large component of LG&E's total operating costs. LG&E's electric rates contain an FAC and gas rates contain a GSC, whereby increases or decreases in the cost of fuel and gas supply are reflected in the FAC and GSC factors, subject to approval by the Kentucky Commission. In July 1999, the Kentucky Commission implemented rates proposed in LG&E's PBR filing resulting in the discontinuance of the FAC. In January 2000, the Kentucky Commission rescinded the PBR rates and ordered the reinstatement of the FAC. See Note 3 of LG&E's Notes to Financial Statements under Item 8 for a further discussion of the PBR and the FAC. Fuel for electric generation increased $.3 million (.2%) in 2000 because of an increase in generation to support increased electric sales ($7.6 million), offset partially by a lower cost of coal burned ($7.3 million). Fuel for electric generation increased $4.4 million (2.9%) in 1999 because of an increase in generation to support increased electric sales ($7.4 million), offset partially by a lower cost of coal burned ($3 million). The average delivered cost per ton of coal purchased was $20.96 in 2000, $21.49 in 1999, and $22.38 in 1998. Power purchased decreased $72.7 million (42.9%) in 2000 primarily due to decreased brokered sales activity in the wholesale electric market. Power purchased increased $119.4 million (238%) in 1999 primarily due to increased purchases to serve native load customers during the summer months and off-system sales activity. Gas supply expenses increased $82.2 million (71.6%) in 2000 primarily due to an increase in cost of net gas supply ($70.4 million), and due to an increase in the volume of gas delivered to the distribution system ($11.8 29 million). Gas supply expenses decreased $11.1 million (8.9%) in 1999 primarily due to a decrease in cost of net gas supply ($17.1 million), partially offset by an increase in the volume of gas delivered to the distribution system ($6 million). The average unit cost per Mcf of purchased gas was $5.08 in 2000, $2.99 in 1999, and $3.05 in 1998. Operation expenses decreased $18.7 million (12.1%) in 2000 primarily due to lower administrative costs, $13.8 million, (due to decreases in pension expense, $5.4 million, year 2000 expenses, $4.0 million, and decreased salaries due to fewer employees in 2000, $2 million) and a decrease in steam production costs primarily at the Mill Creek generating station ($5 million). Operation expenses decreased $8.9 million (5.4%) in 1999 primarily due to decreased costs to operate the electric generating plants ($5.7 million) and lower administrative costs ($4.6 million). Maintenance expenses for 2000 increased $5.6 million (9.6%) primarily due to an increase in software maintenance agreements ($3.9 million), and maintenance of communications equipment ($1.5 million). Maintenance expenses for 1999 increased $5.3 million (10.1%) primarily due to increases in scheduled outages at the Mill Creek generating station units 3 and 4, and the Cane Run generating station units 4 and 6 ($2.4 million) and increased forced outages at Mill Creek units 1 and 4 and Cane Run unit 5 ($3.9 million). Depreciation and amortization increased $1.1 million (1.1%) in 2000 and increased $4 million (4.3%) in 1999 over 1998 because of additional utility plant in service in both years. A depreciation study was completed in late 2000 with new depreciation rates going into effect on January 1, 2001. The new rates, as compared to rates in effect for 2000, are expected to increase LG&E's depreciation expense by about $.9 million in 2001. Property and other taxes increased $2.1 million (12.1%) in 2000 primarily due to increased payroll and property taxes. Other income - net, increased $.8 million (18.9%) in 2000 primarily due to a decrease in income tax expense associated with increased interest expenses. LG&E incurred a pre-tax charge in 1998 for costs associated with the merger of LG&E Energy and KU Energy of $32.1 million. The amount charged is in excess of the amount permitted to be deferred as a regulatory asset by the Kentucky Commission. The corresponding tax benefit of $8.5 million is recorded in other income-net. See Note 2 of LG&E's Notes to Financial Statements under Item 8. Interest charges for 2000 increased $5.3 million (13.9%) due to having short-term borrowings for entire 2000 as compared to two months in 1999 ($7.1 million), partially offset by a decrease in interest on debt to associated companies ($1 million) and lower interest rates on variable rate debt ($1 million). Interest charges for 1999 increased $1.6 million (4.5%) due to short-term borrowings, partially offset by lower interest rates on variable rate debt ($.6 million). See Note 10 of LG&E's Notes to Financial Statements under Item 8. LG&E's embedded cost of long-term debt was 5.40% at December 31, 2000, and 5.46% at December 31, 1999. See Note 10 of LG&E's Notes to Financial Statements under Item 8. Variations in income tax expenses are largely attributable to changes in pre-tax income as well as non-deductible merger expenses in 1998. 30 The rate of inflation may have a significant impact on LG&E's operations, its ability to control costs and the need to seek timely and adequate rate adjustments. However, relatively low rates of inflation in the past few years have moderated the impact on current operating results. LIQUIDITY AND CAPITAL RESOURCES LG&E uses net cash generated from its operations and external financing to fund construction of plant and equipment and the payment of dividends. LG&E believes that such sources of funds will be sufficient to meet the needs of its business in the foreseeable future. Operating Activities Cash provided by operations was $156.2 million, $180.5 million and $225.7 million in 2000, 1999, and 1998, respectively. The 2000 decrease resulted mainly from an increase in accounts receivable, and a decrease in accrued taxes. The 1999 decrease resulted from a net decrease in non-cash income statement items and a net decrease in net current assets, including decreases in accounts payable and accrued taxes. Investing Activities LG&E's primary use of funds continues to be for capital expenditures and the payment of dividends. Capital expenditures were $144 million, $195 million and $138 million in 2000, 1999, and 1998, respectively. LG&E expects its capital expenditures for 2001 and 2002 will total approximately $413 million, which consists primarily of construction estimates associated with installation of nitrogen oxide control equipment as described in the section titled "Environmental Matters," purchase of two jointly owned CTs with KU and on-going construction for the distribution systems. Net cash used for investment activities decreased by $43.3 million in 2000 as compared to 1999, and increased $47.2 million in 1999 compared to 1998, primarily due to construction expenditures. Financing Activities Cash outflows for financing activities in 2000 were $67.7 million. Cash inflow from financing activities in 1999 was $26.7 million and cash outflow for 1998 was $107.6 million. In 2000, total debt was paid down by $20 million to $606.8 million at December 31, 2000. LG&E received $40 million in contributed capital from its parent company in December 2000. LG&E also refinanced $108.3 million of its pollution control bonds in 2000. As of December 2000, LG&E had committed credit facility aggregating $200 million with various banks. Unused capacity under these lines were approximately $200 million after considering the commercial paper support. The credit facility will expire in 2001 and management expects to renegotiate the credit facility at that time. Future Capital Requirements Future capital requirements may be affected in varying degrees by factors such as load growth, changes in construction expenditure levels, rate actions by regulatory agencies, new legislation, market entry of competing electric power generators, changes in environmental regulations and other regulatory requirements. LG&E anticipates funding its requirements through operating cash flow, debt, preferred stock or common equity. 31 LG&E's debt ratings as of February 28, 2001, were:
Moody's S&P Fitch ------- --- ----- First mortgage bonds A1 A- AA- Unsecured debt A2 BBB A+ Preferred stock a2 BBB- A Commercial paper P-1 A-2 F-1
The Moody's and Fitch ratings are on Credit Watch with negative implications. These ratings reflect the views of Moody's, S&P and Fitch. A security rating is not a recommendation to buy, sell or hold securities and is subject to revision or withdrawal at any time by the rating agency. Market Risks LG&E is exposed to market risks from changes in interest rates and commodity prices. To mitigate changes in cash flows attributable to these exposures, LG&E uses various financial instruments including derivatives. Derivative positions are monitored using techniques that include market value and sensitivity analysis. Interest Rate Sensitivity LG&E has short-term and long-term variable rate debt obligations outstanding. At December 31, 2000, the potential change in interest expense associated with a 1% change in base interest rates of LG&E's unhedged debt was estimated at $1.2 million. Interest rate swaps are used to hedge LG&E's underlying variable rate debt obligations. These swaps hedge specific debt issuance and consistent with management's designation are accorded hedge accounting treatment. As of December 31, 2000, LG&E had swaps with a combined notional value of $234.3 million. The swaps exchange floating-rate interest payments for fixed interest payments to reduce the impact of interest rate changes on LG&E's Pollution Control Bonds. As of December 31, 2000, 66% of the outstanding variable interest rate borrowings were converted to fixed interest rates through swaps. The potential loss in fair value from these positions resulting from a hypothetical 1% adverse movement in base interest rates is estimated at $6.9 million as of December 31, 2000. Changes in the market value of these swaps if held to maturity, as LG&E intends to do, are not expected to have any effect on LG&E's net income or cash flow. See Note 4 of LG&E's Notes to Financial Statements under Item 8. Commodity Price Sensitivity LG&E has limited exposure to market price volatility in prices of fuel and electricity, as long as cost-based regulations exist, including the FAC and GSC. YEAR 2000 COMPUTER SOFTWARE ISSUE Result of Year 2000 Preparation The remediation efforts of LG&E in preparing for potential Year 2000 computer problems were successful and 32 resulted in LG&E incurring no material disruptions in services or operations of any sort. To the extent, if any, certain third parties such as interconnected utilities, key customers or suppliers still face Year 2000 disruptions due to incomplete remediation, LG&E may still retain risk related to Year 2000 issues. LG&E is not presently aware of any such situations and does not anticipate such events will have a material effect on LG&E's financial condition or results of operations. Cost of Year 2000 Issues LG&E's system modification costs related to the Year 2000 issue were expensed as incurred, while new system installations are being capitalized pursuant to generally accepted accounting principles. See Note 1 of LG&E's Notes to Financial Statements under Item 8. Through December 2000, LG&E incurred approximately $18.6 million in capital and operating costs in connection with the Year 2000 issue. RATES AND REGULATION Following the merger transaction involving LG&E Energy and Powergen, Powergen became a registered holding company under PUHCA. As a result, Powergen, its utility subsidiaries, including LG&E, and certain of its non-utility subsidiaries are subject to extensive regulation by the SEC under PUHCA with respect to issuances and sales of securities, acquisitions and sales of certain utility properties, and intra-system sales of certain goods and services. In addition, PUHCA generally limits the ability of registered holding companies to acquire additional public utility systems and to acquire and retain businesses unrelated to the utility operations of the holding company. Powergen believes that it has adequate authority (including financing authority) under existing SEC orders and regulations for it and its subsidiaries to conduct their businesses as proposed during 2001. Powergen will seek additional authorization when necessary. LG&E is subject to the jurisdiction of the Kentucky Commission in virtually all matters related to electric and gas utility regulation, and as such, their accounting is subject to SFAS No. 71, ACCOUNTING FOR THE EFFECTS OF CERTAIN TYPES OF REGULATION. Given LG&E's competitive position in the market and the status of regulation in the state of Kentucky, LG&E has no plans or intentions to discontinue its application of SFAS No. 71. See Note 3 of LG&E's Notes to Financial Statements under Item 8. Environmental Cost Recovery In August 1999, a final order of the Kentucky Commission approved LG&E's settlement agreement concerning the refund of the recovery of costs associated with pre-1993 environmental projects. LG&E began applying the refund to customers' bills in October 1999, and completed the refund process in the month of November 2000. All aspects of the original litigation of this issue have now been resolved. In March 2000, LG&E filed an application with the Kentucky Commission to obtain a CCN to construct up to three SCRs NOx reduction facilities. The construction and subsequent operation of the SCRs is intended to reduce NOx emission levels to meet the EPA's mandated NOx emission level of 0.15 lbs./ Mmbtu by May 2003. Following a period of discovery in the proceeding, the Kentucky Commission granted LG&E's request for a CCN in June 2000. In its order, the Kentucky Commission ruled that LG&E's proposed plan for construction was "reasonable, cost-effective and will not result in the wasteful duplication of facilities." In October 2000, LG&E filed an application with the Kentucky Commission to amend its Environmental Compliance Plan to reflect the addition of the proposed NOx reduction technology projects and to amend its Environmental Cost Recovery Tariff to include an overall rate of return on capital investments. Approval of LG&E's application will allow LG&E to begin to recover the costs associated with these new projects, subject 33 to Kentucky Commission oversight during normal six-month and two-year reviews. Following the completion of hearings in March 2001, a ruling is expected by May 2001. Electric PBR/ESM In October 1998, LG&E filed an application with the Kentucky Commission for approval of a new method of determining electric rates that sought to provide financial incentives for LG&E to further reduce customers' rates. The filing was made pursuant to the September 1997 Kentucky Commission order approving the merger of LG&E Energy and KU Energy, wherein the Kentucky Commission directed LG&E to indicate whether they desired to remain under traditional rate of return regulation or commence non-traditional regulation. The proposed ratemaking method, known as PBR, included financial incentives for LG&E to reduce fuel costs and increase generating efficiency, and to share any resulting savings with customers. Additionally, the PBR proposal provided for financial penalties and rewards to assure continued high quality service and reliability. In April 1999, LG&E filed a joint agreement with KU and the Kentucky Attorney General to adopt the PBR plan subject to certain amendments. The Kentucky Commission issued initial orders implementing the amended PBR plan, effective July 1999, and subject to modification. The Kentucky Commission also consolidated into the continuing PBR proceedings an earlier March 1999, rate complaint by a group of industrial intervenors, KIUC, in which KIUC requested significant reductions in electric rates. Hearings were conducted before the Kentucky Commission on LG&E's amended PBR plan and the KIUC rate reduction petitions in August and September 1999. In January 2000, the Kentucky Commission issued orders for LG&E in the subject cases, ruling that LG&E should reduce base rates by $27.2 million effective with bills rendered beginning March 1, 2000. The Kentucky Commission eliminated LG&E's proposal to operate under its PBR plan and reinstated the FAC mechanism effective March 1, 2000. The Kentucky Commission offered LG&E the opportunity to operate under an ESM for the next three years. Under this mechanism, incremental annual earnings resulting in a rate of return on equity either above or below a range of 10.5% to 12.5% would be shared 60% with shareholders and 40% with ratepayers. Later in January 2000, LG&E filed motions for correction to the January 2000 orders for computational and other errors made in the Kentucky Commission's orders which produced overstatements in the base rate reductions to LG&E of $1.1 million. In February 2000, LG&E accepted the Kentucky Commission's proposed ESM and filed an ESM tariff which contained detailed provisions for operation of the ESM rates. In June 2000, the Kentucky Commission ruled that the final rate reduction should be $26.3 million, a change of approximately $900,000 and ordered LG&E to implement the revised rates effective with service rendered beginning June 1, 2000. LG&E reinstated its FAC beginning with March 2000 billings. The first ESM filing was made on March 1, 2001, for year ended December 31, 2000. By order of the Kentucky Commission rate changes prompted by the ESM filing go into effect in April of each year. At December 31, 2000, LG&E recorded in its financial statements an estimated refund to ratepayers of $2.5 million. DSM LG&E's rates contain a DSM provision. The provision includes a rate mechanism that provides concurrent recovery of DSM costs and provides an incentive for implementing DSM programs. This program had allowed LG&E to recover revenues from lost sales associated with the DSM program (decoupling), but in 1998, LG&E and customer interest groups requested an end to the then current form of the decoupling rate mechanism. In 34 September 1998, the Kentucky Commission accepted LG&E's modified tariff discontinuing the decoupling mechanism effective as of June 1, 1998. In September 2000, LG&E filed a plan to continue DSM programming with the Kentucky Commission. This filing calls for the expansion of the DSM programs into the service territory served by KU and proposes a mechanism to recover revenues from lost sales associated with DSM programs based on program planning engineering estimates and post-implementation evaluation. Gas PBR Since October 1997, LG&E has implemented an experimental performance-based ratemaking mechanism related to gas procurement activities and off-system gas sales only. During the three-year test period beginning October 1997, rate adjustments related to this mechanism will be determined for each 12-month period beginning November 1 and ending October 31. Since its implementation on November 1, 1997, through October 31, 2000, LG&E has achieved $19.6 million in savings. Of the total savings, LG&E has retained $8.9 million, and the remaining portion of $10.7 million has been shared with customers. In December 2000, LG&E filed an Application reporting on the operation of the experimental PBR and requested the Kentucky Commission to extend the PBR for an additional five years as a result of the benefits provided to both LG&E and its customers during the preceding three year experimental period. A ruling is expected by the summer of 2001. FAC Prior to implementation of the PBR in July 1999, and following its termination in March 2000, LG&E employed an FAC mechanism, which under Kentucky law allowed LG&E to recover from customers, the actual fuel costs associated with retail electric sales. In February 1999, LG&E received orders from the Kentucky Commission requiring a refund to retail electric customers of approximately $3.9 million resulting from reviews of the FAC from November 1994, through April 1998, of which $1.9 million was refunded in April 1999, for the period beginning November 1994, and ending October 1996. The orders changed LG&E's method of computing fuel costs associated with electric line losses on wholesale sales appropriate for recovery through the FAC. Following rehearing in December 1999, the Kentucky Commission agreed with LG&E 's position on the appropriate loss factor to use in the FAC computation and issued an order reducing the refund level for the 18-month period under review to approximately $800,000. LG&E enacted the refund with billings in the month of January 2000. LG&E and KIUC each filed separate appeals from the Kentucky Commission's February 1999 orders with the Franklin County, Kentucky Circuit Court and in May 2000, the Court affirmed the Kentucky Commission's orders regarding the amounts disallowed and ordered the case remanded as to the Kentucky Commission's denial of interest, directing the Kentucky Commission to determine whether interest should be awarded to LG&E's ratepayers. In June 2000, LG&E appealed the Circuit Court's decision to the Kentucky Court of Appeals. A final decision on the appeal is not expected until late 2001 or early 2002. Gas Rate Case In March 2000, LG&E filed an application with the Kentucky Commission requesting an adjustment in LG&E's gas rates. LG&E asked for a general adjustment in gas rates for a test year for the twelve months ended December 31, 1999. The revenue increase applied for was $26.4 million. The Kentucky Commission subsequently suspended the effective date of the proposed new tariffs, and held hearings during August 2000. In September 2000, the Kentucky Commission granted LG&E an annual increase in its base gas revenues of $20.2 million effective September 28, 2000. The Kentucky Commission authorized a return on equity of 11.25%. The Kentucky Commission approved LG&E's proposal for a weather normalization billing adjustment mechanism that will normalize the effect of weather on revenues from gas sales. In October 2000, 35 the Kentucky Attorney General requested that the Kentucky Commission grant rehearing on a single revenue requirements issue (normalization of forfeited discounts) on the grounds that the September order did not rule on or otherwise discuss the issue. In November 2000, the Kentucky Commission granted the Attorney General's request for rehearing, rejected the Attorney General's proposed adjustment to normalize the level of forfeited discounts, and ordered that its September 2000 order be modified to reflect its findings on the issue. Kentucky Commission Administrative Case for Affiliate Transactions In December 1997, the Kentucky Commission opened Administrative Case No. 369 to consider Kentucky Commission policy regarding cost allocations, affiliate transactions and codes of conduct governing the relationship between utilities and their non-utility operations and affiliates. The Kentucky Commission intends to address two major areas in the proceedings: the tools and conditions needed to prevent cost shifting and cross-subsidization between regulated and non-utility operations; and whether a code of conduct should be established to assure that non-utility segments of the holding company are not engaged in practices that could result in unfair competition caused by cost shifting from the non-utility affiliate to the utility. In September 1998, the Kentucky Commission issued a draft code of conduct and cost allocation guidelines. In January 1999, LG&E, as well as all parties to the proceeding, filed comments on the Kentucky Commission draft proposals. In December 1999, the Kentucky Commission issued guidelines on cost allocation and held a hearing in January 2000, on the draft code of conduct. In February 2000, the Kentucky Commission issued a draft Code of Conduct for the purpose of further consideration in the process to promulgate a regulation. In early 2000, the Kentucky General Assembly enacted legislation, House Bill 897, which authorized the Kentucky Commission to require utilities who provide nonregulated activities to keep separate accounts and allocate costs in accordance with procedures established by the Kentucky Commission. On February 14, 2001, the Kentucky Commission published notice of their intent to promulgate new administrative regulations. In the same Bill, the General Assembly set forth provisions to govern a utilities activities related to the sharing of information, databases, and resources between its employees or an affiliate involved in the marketing or the provision of nonregulated activities and its employees or an affiliate involved in the provision of regulated services. The legislation became law in July 2000 and LG&E has been operating pursuant thereto since that time. Environmental Matters The Clean Air Act imposed stringent new SO2 and NOx emission limits on electric generating units. LG&E previously had installed scrubbers on all of its generating units. LG&E's strategy for Phase II SO2 reductions, which commenced January 1, 2000, is to increase scrubber removal efficiency to delay additional capital expenditures and may also include fuel switching or upgrading scrubbers. LG&E met the NOx emission requirements of the Act through installation of low-NOx burner systems. LG&E's compliance plans are subject to many factors including developments in the emission allowance and fuel markets, future regulatory and legislative initiatives, and advances in clean air control technology. LG&E will continue to monitor these developments to ensure that its environmental obligations are met in the most efficient and cost-effective manner. In September 1998, the EPA announced its final "NOx SIP Call" rule requiring states to impose significant additional reductions in NOx emissions by May 2003, in order to mitigate alleged ozone transport impacts on the Northeast region. The Commonwealth of Kentucky is currently in the process of revising its State Implementation Plan or "SIP" to require reductions in NOx emissions from coal-fired generating units to the 0.15 lb./Mmbtu level on a system-wide basis. In related proceedings in response to petitions filed by various Northeast states, in December 1999, EPA issued a final rule pursuant to Section 126 of the Clean Air Act directing similar NOx reductions from a number of specifically targeted generating units including all LG&E 36 units. Both rules were appealed to the U.S. Court of Appeals for the D.C. Circuit. The D.C. Circuit subsequently upheld most provisions of the NOx SIP Call rule, but extended the compliance date to May 2004. As the court has yet to issue a final ruling on the Section 126 rule, all LG&E generating units remain subject to the May 2003 compliance date under that rule. LG&E continues to monitor the status of various appeals pending in the D.C. Circuit and U.S. Supreme Court. LG&E is currently implementing a plan for adding significant additional NOx controls to its generating units. Installation of additional NOx controls will proceed on a phased basis, with installation of controls commencing in late 2000 and continuing through the final compliance date. LG&E estimates that it will incur total capital costs of approximately $160 million to reduce its NOx emissions to the 0.15 lb./Mmbtu level on a company-wide basis. In addition, LG&E will incur additional operating and maintenance costs in operating new NOx controls. LG&E believes its costs in this regard to be comparable to those of similarly situated utilities with like generation assets. LG&E anticipates that such capital and operating costs are the type of costs that are eligible for recovery from customers under its environmental surcharge mechanism and believes that a significant portion of such costs could be recovered. However, Kentucky Commission approval is necessary and there can be no guarantee of recovery. LG&E is also monitoring several other air quality issues which may potentially impact coal-fired power plants, including the appeal of the D.C. Circuit's remand of the EPA's revised air quality standards for ozone and particulate matter, measures to implement EPA's regional haze rule, and EPA's December 2000 determination to regulate mercury emissions from power plants. In addition, LG&E is currently working with local regulatory authorities to review the effectiveness of remedial measures aimed at controlling particulate matter emissions from its Mill Creek Station. LG&E previously settled a number of property damage claims from adjacent residents and completed significant remedial measures as part of its ongoing capital construction program. LG&E owns or formerly owned three properties which are the location of past MGP operations. Various contaminants are typically found at such former MGP sites and environmental remediation measures are frequently required. With respect to the sites, LG&E has completed cleanups, obtained regulatory approval of site management plans, or reached agreements for other parties to assume responsibility for cleanup. Based on currently available information, management estimates that it will incur additional costs of $400,000. Accordingly, an accrual of $400,000 has been recorded in the accompanying financial statements. See Note 12 of LG&E's Notes to Financial Statements under Item 8 for an additional discussion of environmental issues. FUTURE OUTLOOK Competition and Customer Choice LG&E has moved aggressively over the past decade to be positioned for, and to help promote, the energy industry's shift to customer choice and a competitive market for energy services. Specifically, LG&E has taken many steps to prepare for the expected increase in competition in its business, including support for performance-based ratemaking structures, aggressive cost reduction activities; strategic acquisitions, dispositions and growth initiatives; write-offs of previously deferred expenses; an increase in focus on commercial and industrial customers; an increase in employee training; and necessary corporate and business unit realignments. LG&E continues to be active in the national debate surrounding the restructuring of the energy industry and the move toward a competitive, market-based environment. LG&E has urged Congress to set a specific date for a complete transition to a competitive market, one that will quickly and efficiently bring the benefits associated 37 with customer choice. LG&E has previously advocated the implementation of this transition by January 1, 2001, and now recommends adoption of federal legislation specifying a date certain and appropriate transition regulations implementing deregulation. In December 1997, the Kentucky Commission issued a set of principles which was intended to serve as its guide in consideration of issues relating to industry restructuring. Among the issues addressed by these principles are: consumer protection and benefit, system reliability, universal service, environmental responsibility, cost allocation, stranded costs and codes of conduct. During 1998, the Kentucky Commission and a task force of the Kentucky General Assembly had each initiated proceedings, including meetings with representatives of utilities, consumers, state agencies and other groups in Kentucky, to discuss the possible structure and effects of energy industry restructuring in Kentucky. In November 1999, the task force issued a report to the Governor of Kentucky and a legislative agency recommending no general electric industry restructuring actions during the 2000 legislative session and no such actions were taken at the 2000 or 2001 legislative sessions. Thus, at the time of this report, neither the Kentucky General Assembly nor the Kentucky Commission has adopted or approved a plan or timetable for retail electric industry competition in Kentucky. The nature or timing of the ultimate legislative or regulatory actions regarding industry restructuring and their impact on LG&E, which may be significant, cannot currently be predicted. While many states have moved forward in providing retail choice, many others have not. Some are reconsidering their initiatives and have even delayed implementation. Recent activities in California that have resulted in extremely high wholesale (and in some cases, consumer) electric prices are becoming significant factors in the deliberations by other states. KU GENERAL The following discussion and analysis by management focuses on those factors that had a material effect on KU's financial results of operations and financial condition during 2000, 1999, and 1998 and should be read in connection with the financial statements and notes thereto. Some of the following discussion may contain forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words "anticipate," "expect," "estimate," "objective," "possible," "potential" and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include: general economic conditions; business and competitive conditions in the energy industry; changes in federal or state legislation; unusual weather; actions by state or federal regulatory agencies; and other factors described from time to time in KU's reports to the Securities and Exchange Commission, including Exhibit No. 99.01 to this report on Form 10-K. MERGER On December 11, 2000, LG&E Energy Corp. and Powergen plc successfully completed the merger transaction involving the two companies. LG&E Energy had announced on February 28, 2000, that its Board of Directors accepted the offer to be acquired by Powergen for cash of approximately $3.2 billion or $24.85 per share and the assumption of $2.2 billion of LG&E Energy's debt. Pursuant to the acquisition agreement, LG&E Energy became a wholly 38 owned subsidiary of Powergen and, as a result, KU became an indirect subsidiary of Powergen. KU will continue its separate identity and serve customers in Kentucky and Virginia under its existing name. The preferred stock and debt securities of KU were not affected by this transaction and KU will continue to file SEC reports. Following the merger, Powergen became a registered holding company under PUHCA and KU, as a subsidiary of a registered holding company, became subject to additional regulation under PUHCA. See "Rates and Regulation" under Item 1. Effective May 4, 1998, following the receipt of all required state and federal regulatory approvals, LG&E Energy and KU Energy merged, with LG&E Energy as the surviving corporation. The outstanding preferred stock of KU, a subsidiary of KU Energy before the merger, was not affected by the merger. See Note 2 of KU's Notes to Financial Statements under Item 8. RESULTS OF OPERATIONS Net Income KU's net income decreased $11 million for 2000, as compared to 1999, primarily due to retail rate reductions ordered by the Kentucky Commission . The rate reduction resulted in reduced retail revenues of $28.3 million. Excluding the impact of the rate reduction, net income would have increased approximately $6 million. The increase was due to higher retail electric sales and lower purchased power and operation expenses, offset by lower off-system sales and increased depreciation and amortization. KU's net income increased $33.8 million for 1999, as compared to 1998, primarily due to non-recurring charges in 1998 for merger-related expenses and ECR refund of $21.5 million and $12.9 million, after tax, respectively, offset by net rate refunds incurred in 1999 of $3.5 million, after tax. Excluding these non-recurring charges, net income increased $2.9 million. This increase was due to higher retail electric and off-system sales, and lower operation and maintenance costs, offset by higher purchased power expenses for the year. Revenues A comparison of operating revenues for the years 2000 and 1999, excluding the provision for rate refunds for the ECR refund and the FAC refund previously recovered from customers, $5.9 million in 1999 and $21.5 million in 1998, with the immediately preceding year reflects both increases and decreases which have been segregated by the following principal causes (in thousands of $):
Increase (Decrease) From Prior Period Cause 2000 1999 ----- ---- ---- Retail sales: Fuel clause adjustments, etc $ 6,893 $ (1,744) Merger surcredit (2,327) (4,123) Environmental cost recovery surcharge (4,994) (1,977) Performance based rate 3,439 (5,558) Electric rate reduction (28,343) -- Variation in sales volumes 20,187 19,303 --------- --------- Total retail sales (5,145) 5,901 Wholesale sales (88,522) 106,160 Other 2,398 (465) --------- --------- 39 Total $ (91,269) $ 111,596 ========= =========
Electric revenues decreased in 2000 primarily due to a decrease in brokered activity in the wholesale electric sales market and the electric rate reduction ordered by the Kentucky Commission. In January 2000, the Kentucky Commission ordered the termination of KU's proposed electric PBR mechanism and an electric rate reduction. The increase in wholesale sales in 1999 was primarily due to more aggressive marketing efforts. Provision for rate refund reflects a net charge in revenues during 1999 of $5.9 million for the refund of costs previously recovered from customers under the fuel adjustment clause and the environmental cost recovery mechanism. Provision for rate refund reflects a charge in revenues during 1998 of $21.5 million for the refund of environmental costs previously recovered from customers. See Note 3 of KU's Notes to Financial Statements under Item 8. Expenses Fuel for electric generation comprises a large component of KU's total operating expenses. KU's Kentucky jurisdictional electric rates were subject to a FAC whereby increases or decreases would be reflected in the FAC factor, subject to the approval of the Kentucky Commission. Effective July 2, 1999, the FAC was discontinued and replaced with an amended electric PBR. In January 2000, the Kentucky Commission rescinded KU's PBR rates and ordered the reinstatement of the FAC. See Note 3 of KU's Notes to Financial Statements under Item 8 for a further discussion of the PBR and the FAC. KU's wholesale and Virginia jurisdictional electric rates contain a fuel adjustment clause whereby increases or decreases in the cost of fuel are reflected in rates, subject to the approval of the Virginia Commission and the FERC. Fuel for electric generation were approximately the same in 2000 as compared to 1999. An increase in volume burned ($5.1 million) was offset by decreases in the cost of fuel ($5.1 million). Fuel for electric generation increased $2.5 million (1%) in 1999 because of an increase in generation ($5.1 million), partially offset by a decrease in the cost of coal burned ($2.6 million). KU's average delivered cost per ton of coal purchased was $25.63 in 2000, $26.65 in 1999 and $26.97 in 1998. Power purchased expense decreased $75.4 million in 2000 primarily due to the decrease in wholesale sales. Power purchased increased $115.7 million in 1999 primarily to support the aforementioned wholesale sales. Operation expenses decreased $8.4 million (7.3%) in 2000 primarily because of decreased administrative and general expenses of $10 million offset by increased transmission expenses ($2.1 million). The administrative and general expenses decrease was primarily due to decreased medical expense ($3.4 million) and pension expense ($3.9 million). Maintenance expense increased $4.3 million (7.5%) in 2000 due to increases in maintenance at the steam generating plants, primarily due to a scheduled turbine outage at Ghent Unit 1. Maintenance expense decreased $6.3 million (10%) in 1999 due to decreases in maintenance at the steam generating plants and the transmission and distribution systems. Depreciation and amortization increased $8.3 million (9.3%) in 2000 and $3.3 million (3.8%) in 1999 because of additional utility plant in service in both years. 40 A depreciation study was completed in late 2000 with new depreciation rates going into effect on January 1, 2001. The new rates, as compared to rates in effect for 2000, are expected to decrease KU's depreciation expense by about $6 million in 2001. Property and other taxes increased $2.1 million in 2000 over 1999 (13.8%) due to increases in payroll taxes ($1.4 million), property tax ($.4 million) and Kentucky Commission fees ($.3 million). Merger costs to achieve reflects the one-time charge during 1998 of $21.7 million (the corresponding tax benefit of $.2 million is recorded in other income - net) for merger related expenses as discussed in Note 2 of KU's Notes to Financial Statements under Item 8. KU's embedded cost of long-term debt was 6.89% at December 31, 2000, and 7.00% at December 31, 1999. See Note 10 of KU's Notes to Financial Statements under Item 8. Variations in income tax expense are largely attributable to changes in pre-tax income as well as non-deductible merger expenses. The rate of inflation may have a significant impact on KU's operations, its ability to control costs and the need to seek timely and adequate rate adjustments. However, relatively low rates of inflation in the past few years have moderated the impact on current operating results. LIQUIDITY AND CAPITAL RESOURCES KU uses net cash generated from its operations and external financing to fund construction of plant and equipment and the payment of dividends. KU believes that such sources of funds will be sufficient to meet the needs of its business in the foreseeable future. Operating Activities Cash provided by operations was $176.3 million, $204.2 million and $239.4 million in 2000, 1999 and 1998, respectively. The 2000 decrease resulted from a decrease in net income caused by the aforementioned electric rate reduction ordered by the Kentucky Commission. The decrease was further caused by a net increase in net current assets, including increases in accounts receivable and decreases in accounts payable, and provision for rate refunds, partially offset by decreases in inventory. The 1999 decrease resulted from an increase in net income and a net decrease in net current assets. Investing Activities KU's primary use of funds continues to be for capital expenditures and the payment of dividends. Capital expenditures were $101 million, $181 million and $92 million in 2000, 1999 and 1998, respectively. The higher amount in 1999 capital expenditures was primarily due to the purchase of a 62% interest in two combustion turbines. KU expects its capital expenditures for 2001 and 2002 will total approximately $300 million which consists primarily of construction costs associated with installation of nitrogen oxide control equipment as described in the section titled "Environmental Matters," purchase of two jointly owned CTs with LG&E and on going construction for the distribution system. Net cash used for investment activities decreased by $80.8 million in 2000 compared to 1999, and increased $89.3 million in 1999 compared to 1998, primarily due to construction expenditures. 41 Financing Activities Cash outflows from financing activities were $82.4 million, $75.2 million and $94.0 million, in 2000, 1999 and 1998, respectively. In 2000, KU retired a $61.5 million first mortgage bond and refinanced $12.9 million of its pollution control bonds. The long-term debt balance as of December 31, 2000, was $430.8 million. Short-term debt increased $61.2 million in 2000. KU received $15 million in contributed capital from its parent company in December 2000. KU maintains an uncommitted line of credit which totaled $100 million at December 31, 2000. There was no outstanding balance as of that date. Future Capital Requirements Future capital requirements may be affected in varying degrees by factors such as load growth, changes in construction expenditure levels, rate actions by regulatory agencies, new legislation, market entry of competing electric power generators, changes in environmental regulations and other regulatory requirements. KU anticipates funding its requirements through operating cash flow, debt, preferred stock or common equity. KU's debt ratings as of February 28, 2001, were:
Moody's S&P Fitch ------- --- ----- First mortgage bonds A1 A- AA- Preferred stock a2 BBB- A Commercial paper P-1 A-2 F-1
The Moody's and Fitch ratings are on Credit Watch with negative implications. These ratings reflect the views of Moody's, S&P and Fitch. A security rating is not a recommendation to buy, sell or hold securities and is subject to revision or withdrawal at any time by the rating agency. Market Risks KU is exposed to market risks from changes in interest rates and commodity prices. To mitigate changes in cash flows attributable to these exposures, KU uses various financial instruments including derivatives. Derivative positions are monitored using techniques that include market value and sensitivity analysis. Interest Rate Sensitivity KU has short-term and long-term variable rate debt obligations outstanding. At December 31, 2000, the potential change in interest expense associated with a 1% change in base interest rates of KU's variable rate debt is estimated at $2.2 million. Interest rate swaps are used to hedge KU's underlying debt obligations. These swaps hedge specific debt issuances and consistent with management's designation are accorded hedge accounting treatment. As of December 31, 2000, KU has swaps with a notional value of $153 million. The swaps exchange fixed-rate interest payments for floating interest payments on KU's Series P, R, and PCS-9 Bonds. The potential loss in 42 fair value from these positions resulting from a hypothetical 1% adverse movement in base interest rates is estimated at $8.3 million as of December 31, 2000. Changes in the market value of these swaps if held to maturity, as KU intends to do, will have no effect on KU's net income or cash flow. See Note 4 of KU's Notes to Financial Statements under Item 8. Commodity Price Sensitivity KU has limited exposure to market price volatility in prices of fuel and electricity, as long as cost-based regulations exist, including the FAC. YEAR 2000 COMPUTER SOFTWARE ISSUE Result of Year 2000 Preparation The remediation efforts of KU in preparing for potential Year 2000 computer problems were successful and resulted in KU incurring no material disruptions in services or operations of any sort. To the extent, if any, certain third parties such as interconnected utilities, key customers or suppliers still face Year 2000 disruptions due to incomplete remediation, KU may still retain risk related to Year 2000 issues. KU is not presently aware of any such situations and does not anticipate such events will have a material effect on KU's financial condition or results of operations. Cost of Year 2000 Issues KU's system modification costs related to the Year 2000 issue were expensed as incurred, while new system installations are being capitalized pursuant to generally accepted accounting principles. See Note 1 of KU's Notes to Financial Statements under Item 8. Through December 2000, KU incurred approximately $5.3 million in capital and operating costs in connection with the Year 2000 issue. RATES AND REGULATION Following the merger transaction involving LG&E Energy and Powergen, Powergen became a registered holding company under PUHCA. As a result, Powergen, its utility subsidiaries, including KU, and certain of its non-utility subsidiaries are subject to extensive regulation by the SEC under PUHCA with respect to issuances and sales of securities, acquisitions and sales of certain utility properties, and intra-system sales of certain goods and services. In addition, PUHCA generally limits the ability of registered holding companies to acquire additional public utility systems and to acquire and retain businesses unrelated to the utility operations of the holding company. Powergen believes that it has adequate authority (including financing authority) under existing SEC orders and regulations for it and its subsidiaries to conduct their businesses as proposed during 2001. Powergen will seek additional authorization when necessary. KU is subject to the jurisdiction of the Kentucky Commission, the Virginia Commission and FERC in virtually all matters related to electric utility regulation, and as such, its accounting is subject to SFAS No. 71, ACCOUNTING FOR THE EFFECTS OF CERTAIN TYPES OF REGULATION. Given KU's competitive position in the market and the status of regulation in the states of Kentucky and Virginia, KU has no plans or intentions to discontinue its application of SFAS No. 71. See Note 3 of KU's Notes to Financial Statements under Item 8. Environmental Cost Recovery 43 In August 1999, a final order of the Kentucky Commission approved KU's settlement agreement concerning the refund of the recovery of costs associated with pre-1993 environmental projects. KU began applying the refund to customers' bills in October 1999, and completed the refund process in the month of November 2000. All aspects of the original litigation of this issue have now been resolved. In March 2000, KU filed an application with the Kentucky Commission to obtain a CCN to construct up to four SCRs NOx reduction facilities. The construction and subsequent operation of the SCRs is intended to reduce NOx emission levels to meet the EPA's mandated NOx emission level of 0.15 lbs./ Mmbtu by May 2003. Following a period of discovery in the proceeding, the Kentucky Commission granted KU's request for a CCN in June 2000. In its order, the Kentucky Commission ruled that KU's proposed plan for construction was "reasonable, cost-effective and will not result in the wasteful duplication of facilities." In October 2000, KU filed an application with the Kentucky Commission to amend its Environmental Compliance Plan to reflect the addition of the proposed NOx reduction technology projects and to amend its Environmental Cost Recovery Tariff to include an overall rate of return on capital investments. Approval of KU's application will allow KU to begin to recover the costs associated with these new projects, subject to Kentucky Commission oversight during normal six-month and two-year reviews. Following the completion of hearings in March 2001, a ruling is expected by May 2001. Electric PBR/ESM In October 1998, KU filed an application with the Kentucky Commission for approval of a new method of determining electric rates that sought to provide financial incentives for KU to further reduce customers' rates. The filing was made pursuant to the September 1997 Kentucky Commission order approving the merger of LG&E Energy and KU Energy, wherein the Kentucky Commission directed KU to indicate whether they desired to remain under traditional rate of return regulation or commence non-traditional regulation. The proposed ratemaking method, known as PBR, included financial incentives for KU to reduce fuel costs and increase generating efficiency, and to share any resulting savings with customers. Additionally, the PBR proposal provided for financial penalties and rewards to assure continued high quality service and reliability. In April 1999, KU filed a joint agreement with LG&E and the Kentucky Attorney General to adopt the PBR plan subject to certain amendments. The Kentucky Commission issued initial orders implementing the amended PBR plan, effective July 1999, and subject to modification. The Kentucky Commission also consolidated into the continuing PBR proceedings an earlier March 1999, rate complaint by a group of industrial intervenors, KIUC, in which KIUC requested significant reductions in electric rates. Hearings were conducted before the Kentucky Commission on KU's amended PBR plans and the KIUC rate reduction petitions in August and September 1999. In January 2000, the Kentucky Commission issued orders for KU in the subject cases, ruling that KU should reduce base rates by $36.5 million effective with bills rendered beginning March 1, 2000. The Kentucky Commission eliminated KU's proposal to operate under its PBR plan and reinstated the FAC mechanism effective March 1, 2000. The Kentucky Commission offered KU the opportunity to operate under an ESM for the next three years. Under this mechanism, incremental annual earnings for KU resulting in a rate of return on equity either above or below a range of 10.5% to 12.5% would be shared 60% with shareholders and 40% with ratepayers. Later in January 2000, KU filed motions for correction to the January 2000 orders for computational and other errors made in the Kentucky Commission's orders which produced overstatements in the base rate reductions to KU of $7.7 million. In February 2000, KU accepted the Kentucky Commission's opportunity to use an ESM by 44 filing an ESM tariff, which contains the provisions operating under such mechanism. In June 2000, the Kentucky Commission ruled that the final rate reduction should be $30.4 million, a change of approximately $6.1 million from the original order and ordered KU to implement the revised rates effective with service rendered beginning June 1, 2000. KU reinstated its FAC beginning with March 2000 billings. The first ESM filing was made on March 1, 2001, for year ended December 31, 2000. By order of the Kentucky Commission rate changes prompted by the ESM filing go into effect in April of each year. At December 31, 2000, KU expects to fall within the range, therefore no adjustment was made to the financial statements. DSM In September 2000, KU filed a plan with the Kentucky Commission that would expand LG&E's current DSM programs into the service territory served by KU. The filing includes a rate mechanism that provides for concurrent recovery of DSM costs, provides an incentive for implementing DSM programs, and recovers revenues from lost sales associated with the DSM program. The Kentucky Commission has not issued an order in this case. KU expects a ruling in mid-2001. FAC Prior to implementation of the PBR in July 1999, and following its termination in March 2000, KU employed an FAC mechanism, which under Kentucky law allowed the utilities to recover from customers the actual fuel costs associated with retail electric sales. In July 1999, the Kentucky Commission issued a series of orders requiring KU to refund approximately $10.1 million resulting from reviews of the FAC from November 1994 to October 1998. The orders changed KU's method of computing fuel costs associated with electric line losses on off-system sales appropriate for recovery through the FAC, and KU's method for computing system line losses for the purpose of calculating the system sales component of the FAC charge. At KU's request, in July 1999, the Kentucky Commission stayed the refund requirement pending the Kentucky Commission's final determination of any rehearing request that KU may file. In August 1999, KU filed its request for rehearing of the July orders. In August 1999, the Kentucky Commission issued a final order in the KU proceedings, agreeing, in part, with KU's arguments outlined in its petition for rehearing. While the Kentucky Commission confirmed that KU should change its method of computing the fuel costs associated with electric line losses, it agreed with KU that the line loss percentage should be based on KU's actual line losses incurred in making wholesale sales rather than the percentage used in its Open Access Transmission Tariff. The Kentucky Commission also upheld its previous ruling concerning the computation of system line losses in the calculation of the FAC. The net effect of the Kentucky Commission's final order was to reduce the refund obligation to $6.7 million ($5.8 million on Kentucky jurisdictional basis) from the original order amount of $10.1 million. In August 1999, KU recorded its estimated share of anticipated FAC refunds. KU began implementing the refund in October and completed the refund in September 2000. Both KU and the KIUC appealed the order to the Franklin Circuit Court. In October 2000, the Court affirmed the Kentucky Commission's orders concerning all issues except interest, with respect to which it held that KU will be required to pay interest on the amount disallowed "if the Commission within its discretion so determines", and ordered the case be remanded to the Kentucky Commission on that issue. In November 2000, KU appealed the Circuit Court's decision to the Kentucky Court of Appeals. A decision is not expected until late 2001 or early 2002. 45 Kentucky Commission Administrative Case for Affiliate Transactions In December 1997, the Kentucky Commission opened Administrative Case No. 369 to consider Kentucky Commission policy regarding cost allocations, affiliate transactions and codes of conduct governing the relationship between utilities and their non-utility operations and affiliates. The Kentucky Commission intends to address two major areas in the proceedings: the tools and conditions needed to prevent cost shifting and cross-subsidization between regulated and non-utility operations; and whether a code of conduct should be established to assure that non-utility segments of the holding company are not engaged in practices that could result in unfair competition caused by cost shifting from the non-utility affiliate to the utility. In September 1998, the Kentucky Commission issued a draft code of conduct and cost allocation guidelines. In January 1999, KU, as well as all parties to the proceeding, filed comments on the Kentucky Commission draft proposals. In December 1999, the Kentucky Commission issued guidelines on cost allocation and held a hearing in January 2000, on the draft code of conduct. In February 2000, the Kentucky Commission issued its ruling in the case, including a draft Code of Conduct for the purpose of further consideration in the process to promulgate a regulation. In early 2000, the Kentucky General Assembly enacted legislation, House Bill 897, which authorized the Kentucky Commission to require utilities who provide nonregulated activities to keep separate accounts and allocate costs in accordance with procedures established by the Kentucky Commission. On February 14, 2001, the Kentucky Commission published notice of their intent to promulgate new administrative regulations. In the same Bill, the General Assembly set forth provisions to govern a utilities activities related to the sharing of information, databases, and resources between its employees or an affiliate involved in the marketing or the provision of nonregulated activities and its employees or an affiliate involved in the provision of regulated services. The legislation became law in July 2000 and KU has been operating pursuant thereto since that time. Environmental Matters The Clean Air Act imposed stringent new SO2 and NOx emission limits on electric generating units. KU met its Phase I SO2 requirements primarily through installation of a scrubber on Ghent Unit 1. KU's strategy for Phase II SO2 reductions, which commenced January 1, 2000, is to use accumulated emissions allowances to delay additional capital expenditures and may also include fuel switching or the installation of additional scrubbers. KU met the NOx emission requirements of the Act through installation of low-NOx burner systems. KU's compliance plans are subject to many factors including developments in the emission allowance and fuel markets, future regulatory and legislative initiatives, and advances in clean air control technology. KU will continue to monitor these developments to ensure that its environmental obligations are met in the most efficient and cost-effective manner. In September 1998, the EPA announced its final "NOx SIP Call" rule requiring states to impose significant additional reductions in NOx emissions by May 2003, in order to mitigate alleged ozone transport impacts on the Northeast region. The Commonwealth of Kentucky is currently in the process of revising its State Implementation Plan or "SIP" to require reductions in NOx emissions from coal-fired generating units to the 0.15 lb./Mmbtu level on a system-wide basis. In related proceedings in response to petitions filed by various Northeast states, in December 1999, EPA issued a final rule pursuant to Section 126 of the Clean Air Act directing similar NOx reductions from a number of specifically targeted generating units including all KU units in the eastern half of Kentucky. Additional petitions currently pending before EPA may potentially result in rules encompassing KU's remaining generating units. Both rules were appealed to the U.S. Court of Appeals for the D.C. Circuit. The D.C. Circuit subsequently upheld most provisions of the NOx SIP Call rule, but extended the compliance date to May 2004. As the court has yet to issue a final ruling on the Section 126 rule, all KU generating units, except for KU's Green River generating station, remain subject to the May 2003 46 compliance date under that rule. As KU's Green River station is not covered by the Section 126 rule, those facilities are subject to the May 2004 compliance date as extended by the D.C. Circuit. KU continues to monitor the status of various appeals pending in the D.C. Circuit and U.S. Supreme Court. KU is currently implementing a plan for adding significant additional NOx controls to its generating units. Installation of additional NOx controls will proceed on a phased basis, with installation of controls commencing in late 2000 and continuing through the final compliance date. KU estimates that it will incur total capital costs of approximately $195 million to reduce its NOx emissions to the 0.15 lb./Mmbtu level on a company-wide basis. In addition, KU will incur additional operating and maintenance costs in operating new NOx controls. KU believes its costs in this regard to be comparable to those of similarly situated utilities with like generation assets. KU anticipates that such capital and operating costs are the type of costs that are eligible for recovery from customers under its environmental surcharge mechanism and believes that a significant portion of such costs could be recovered. However, Kentucky Commission approval is necessary and there can be no guarantee of recovery. KU owns or formerly owned several properties which contained past MGP operations. Various contaminants are typically found at such former MGP sites and environmental remediation measures are frequently required. KU has completed the cleanup of a site owned by KU. With respect to other former MGP sites no longer owned by KU, KU is unaware of what, if any, additional exposure or liability it may have. In October 1999, approximately 38,000 gallons of diesel fuel leaked from a cracked valve in an underground pipeline at KU's E.W. Brown Station. Under the oversight of EPA and state officials, KU commenced immediate spill containment and recovery measures which prevented the spill from reaching the Kentucky River. KU ultimately recovered approximately 34,000 gallons of diesel fuel. In November 1999, the Kentucky Division of Water issued a notice of violation for the incident. KU is currently negotiating with the state in an effort to reach a complete resolution of this matter. KU expects to incur costs of approximately $1.5 million. KU is monitoring the status of EPA's revised NAAQS for ozone and particulate matter. In May 1999, the Washington D.C. Circuit remanded the final rule and directed EPA to undertake additional rulemaking efforts. KU continues to monitor EPA actions to challenge that ruling. See Note 11 of KU's Notes to Financial Statements under Item 8 for an additional discussion of environmental issues. FUTURE OUTLOOK Competition and Customer Choice KU has moved aggressively over the past decade to be positioned for, and to help promote the energy industry's shift to customer choice and a competitive market for energy services. Specifically, KU has taken many steps to prepare for the expected increase in competition in its business, including support for PBR structures, aggressive cost reduction activities; strategic acquisitions, dispositions and growth initiatives; write-offs of previously deferred expenses; an increase in focus on commercial and industrial customers; an increase in employee training; and necessary corporate and business unit realignments. KU continues to be active in the national debate surrounding the restructuring of the energy industry and the move toward a competitive, market-based environment. KU has urged Congress to set a specific date for a complete transition to a competitive market, one that will quickly and efficiently bring the benefits associated with customer choice. KU has previously advocated the implementation of this transition by January 1, 2001, and now recommends adoption 47 of federal legislation specifying a date certain and appropriate transition regulations implementing deregulation. In December 1997, the Kentucky Commission issued a set of principles which was intended to serve as its guide in consideration of issues relating to industry restructuring. Among the issues addressed by these principles are: consumer protection and benefit, system reliability, universal service, environmental responsibility, cost allocation, stranded costs and codes of conduct. During 1998, the Kentucky Commission and a task force of the Kentucky General Assembly each initiated proceedings, including meetings with representatives of utilities, consumers, state agencies and other groups in Kentucky, to discuss the possible structure and effects of energy industry restructuring in Kentucky. In November 1999, the task force issued a report to the Governor of Kentucky and a legislative agency recommending no general electric industry restructuring actions during the 2000 legislative session and no such actions were taken at the 2000 or 2001 legislative sessions. Thus, at the time of this report, neither the Kentucky General Assembly nor the Kentucky Commission has adopted or approved a plan or timetable for retail electric industry competition in Kentucky. The nature or timing of the ultimate legislative or regulatory actions regarding industry restructuring and their impact on KU, which may be significant, cannot currently be predicted. While many states have moved forward in providing retail choice, many others have not. Some are reconsidering their initiatives and have even delayed implementation. Recent activities in California that have resulted in extremely high wholesale (and in some cases, consumer) electric prices are becoming significant factors in the deliberations by other states. KU's customers in Virginia will have retail choice beginning January 2002, pursuant to the Virginia Electric Restructuring Act. The Virginia Commission is promulgating regulations to govern the various activities required by the Act. KU has filed unbundled rates that become effective January 1, 2002, for those customers who choose to be provided the energy from a supplier other than KU. ITEM 7A. Quantitative and Qualitative Disclosure About Market Risk. See LG&E's and KU's Management's Discussion and Analysis of Results of Operations and Financial Condition, Market Risks, under Item 7. 48 ITEM 8. Financial Statements and Supplementary Data. Louisville Gas and Electric Company Statements of Income (Thousands of $)
Years Ended December 31 2000 1999 1998 --------- --------- --------- OPERATING REVENUES: Electric .............................. $ 713,458 $ 792,405 $ 663,011 Gas ................................... 272,489 177,579 191,545 Provision for rate refunds (Note 3) ... (2,500) (1,735) (4,500) --------- --------- --------- Total operating revenues (Note 1) ... 983,447 968,249 850,056 --------- --------- --------- OPERATING EXPENSES: Fuel for electric generation .......... 159,418 159,129 154,683 Power purchased ....................... 96,894 169,573 50,176 Gas supply expenses ................... 196,912 114,745 125,894 Other operation expenses .............. 135,943 154,667 163,584 Maintenance ........................... 63,709 58,119 52,786 Depreciation and amortization ......... 98,291 97,221 93,178 Federal and state income taxes (Note 8) 64,425 57,774 56,307 Property and other taxes .............. 18,985 16,930 17,925 --------- --------- --------- Total operating expenses ............ 834,577 828,158 714,533 --------- --------- --------- Net operating income ..................... 148,870 140,091 135,523 Merger costs (Note 2) .................... -- -- 32,072 Other income - net (Note 9) .............. 4,921 4,141 10,991 Interest charges ......................... 43,218 37,962 36,322 --------- --------- --------- Net income ............................... 110,573 106,270 78,120 Preferred stock dividends ................ 5,210 4,501 4,568 --------- --------- --------- Net income available for common stock .... $ 105,363 $ 101,769 $ 73,552 ========= ========= =========
Statements of Retained Earnings (Thousands of $)
Years Ended December 31 2000 1999 1998 ---- ---- ---- Balance January 1 ....................... $259,231 $247,462 $258,910 Add net income .......................... 110,573 106,270 78,120 -------- -------- -------- 369,804 353,732 337,030 -------- -------- -------- Deduct: Cash dividends declared on stock: 5% cumulative preferred ............... 1,075 1,075 1,075 Auction rate cumulative preferred ..... 2,666 1,957 2,024 $5.875 cumulative preferred ........... 1,469 1,469 1,469 Common ................................ 50,000 90,000 85,000 -------- -------- -------- 55,210 94,501 89,568 -------- -------- -------- Balance December 31 ..................... $314,594 $259,231 $247,462 ======== ======== ========
The accompanying notes are an integral part of these financial statements. 49 Louisville Gas and Electric Company Statements of Comprehensive Income (Thousands of $)
Years Ended December 31 2000 1999 1998 ---- ---- ---- Net income available for common stock .......... $ 105,363 $ 101,769 $ 73,552 Unrealized holding losses on available-for-sale securities arising during the period ........ -- (402) (14) Income tax (expense) benefit related to items of other comprehensive income .................. -- 163 (18) --------- --------- --------- Comprehensive income ........................... $ 105,363 $ 101,530 $ 73,520 ========= ========= =========
The accompanying notes are an integral part of these financial statements. 50 Louisville Gas and Electric Company Balance Sheets (Thousands of $)
December 31 2000 1999 ---- ---- ASSETS: Utility plant, at original cost (Note 1): Electric ........................................ $2,459,206 $2,396,707 Gas ............................................. 389,371 365,128 Common .......................................... 148,530 141,009 ---------- ---------- 2,997,107 2,902,844 Less: reserve for depreciation ................. 1,296,865 1,215,032 ---------- ---------- 1,700,242 1,687,812 Construction work in progress ................... 189,218 162,995 ---------- ---------- 1,889,460 1,850,807 ---------- ---------- Other property and investments - less reserve ...... 1,357 1,224 Current assets: Cash and temporary cash investments ............. 2,495 54,761 Marketable securities (Note 6) .................. 4,056 6,936 Accounts receivable - less reserve of $1,286 in 2000 and $1,233 in 1999 .................... 170,852 113,859 Materials and supplies - at average cost: Fuel (predominantly coal) ..................... 9,325 17,350 Gas stored underground ........................ 54,441 38,780 Other ......................................... 31,685 35,010 Prepayments and other ........................... 1,317 2,775 ---------- ---------- 274,171 269,471 ---------- ---------- Deferred debits and other assets: Unamortized debt expense ........................ 5,784 5,607 Regulatory assets (Note 3) ...................... 36,808 31,443 Other ........................................... 18,504 12,900 ---------- ---------- 61,096 49,950 ---------- ---------- $2,226,084 $2,171,452 ========== ========== CAPITAL AND LIABILITIES: Capitalization (see statements of capitalization): Common equity ................................... $ 778,928 $ 683,376 Cumulative preferred stock ...................... 95,140 95,328 Long-term debt (Note 10) ........................ 360,600 380,600 ---------- ---------- 1,234,668 1,159,304 ---------- ---------- Current liabilities: Current portion of long-term debt (Note 10) ..... 246,200 246,200 Notes payable (Note 11) ......................... 114,589 120,097 Accounts payable ................................ 134,392 113,008 Provision for rate refunds ...................... 2,500 8,962 Dividends declared .............................. 1,367 24,236 Accrued taxes ................................... 8,073 23,759 Accrued interest ................................ 6,350 9,265 Other ........................................... 15,826 15,725 ---------- ---------- 529,297 561,252 ---------- ---------- Deferred credits and other liabilities: Accumulated deferred income taxes (Notes 1 and 8) 289,232 255,910 Investment tax credit, in process of amortization 62,979 67,253 Accumulated provision for pensions and related benefits (Note 7) ............................... 31,257 38,431 Customers' advances for construction ............ 9,578 11,104 Regulatory liabilities (Note 3) ................. 55,152 58,726 Other ........................................... 13,921 19,472 ---------- ---------- 462,119 450,896 ---------- ---------- Commitments and contingencies (Note 12) $2,226,084 $2,171,452 ========== ==========
The accompanying notes are an integral part of these financial statements. 51 Louisville Gas and Electric Company Statements of Cash Flows (Thousands of $)
Years Ended December 31 2000 1999 1998 ---- ---- ---- CASH FLOWS FROM OPERATING ACTIVITIES: Net income .................................... $ 110,573 $ 106,270 $ 78,120 Items not requiring cash currently: Depreciation and amortization ............... 98,291 97,221 93,178 Deferred income taxes - net ................. 31,020 (5,279) 2,747 Investment tax credit - net ................. (4,274) (4,289) (4,258) Other ....................................... 8,481 6,924 5,534 Change in certain net current assets: Accounts receivable ......................... (56,993) 28,721 (17,708) Materials and supplies ...................... (4,311) (559) 423 Accounts payable ............................ 21,384 (20,665) 34,779 Provision for rate refunds .................. (6,462) (4,299) 13 Accrued taxes ............................... (15,686) (8,170) 13,206 Accrued interest ............................ (2,915) 1,227 22 Prepayments and other ....................... 1,561 (7) 976 Other ......................................... (24,431) (16,602) 18,679 --------- --------- --------- Net cash flows from operating activities .... 156,238 180,493 225,711 --------- --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Purchases of securities ....................... (708) (1,144) (17,397) Proceeds from sales of securities ............. 4,089 11,662 18,841 Construction expenditures ..................... (144,216) (194,644) (138,345) --------- --------- --------- Net cash flows used for investing activities . (140,835) (184,126) (136,901) --------- --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: Short-term borrowing .......................... (5,508) 120,097 -- Issuance of pollution control bonds ........... 106,545 -- -- Retirement of first mortgage bonds and pollution control bonds ....................... (130,627) -- (20,000) Additional paid-in capital .................... 40,000 -- -- Payment of dividends .......................... (78,079) (93,433) (87,552) --------- --------- --------- Net cash flows from financing activities .... (67,669) 26,664 (107,552) --------- --------- --------- Change in cash and temporary cash investments .... (52,266) 23,031 (18,742) Cash and temporary cash investments at beginning of year ............................. 54,761 31,730 50,472 --------- --------- --------- Cash and temporary cash investments at end of year .......................................... $ 2,495 $ 54,761 $ 31,730 ========= ========= ========= Supplemental disclosures of cash flow information: Cash paid during the year for: Income taxes ................................ $ 46,562 $ 76,761 $ 40,334 Interest on borrowed money .................. 42,958 33,507 34,245
The accompanying notes are an integral part of these financial statements. 52 Louisville Gas and Electric Company Statements of Capitalization (Thousands of $)
December 31 2000 1999 ---- ---- 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) Additional paid-in capital ................................... 40,000 -- Unrealized loss on marketable securities, net of income taxes ($128) in 1999 (Note 6) .............................. -- (189) Retained earnings ............................................ 314,594 259,231 ----------- ----------- 778,928 683,376 ----------- ----------- CUMULATIVE PREFERRED STOCK: Redeemable on 30 days notice by LG&E Current Shares Redemption Outstanding Price ----------- ---------- $25 par value, 1,720,000 shares authorized - 5% series .......... 860,287 $ 28.00 21,507 21,507 Without par value, 6,750,000 shares authorized - Auction rate .................... 500,000 100.00 50,000 50,000 $5.875 series ................... 250,000 103.53 25,000 25,000 Preferred stock expense ........... (1,367) (1,179) ----------- ---------- 95,140 95,328 ----------- ---------- LONG-TERM DEBT (Note 10): First mortgage bonds - Series due July 1, 2002, 7 1/2% ............................ -- 20,000 Series due August 15, 2003, 6% ............................. 42,600 42,600 Pollution control series: P due June 15, 2015, 7.45% ............................... -- 25,000 Q due November 1, 2020, 7 5/8% ........................... -- 83,335 R due November 1, 2020, 6.55% ............................ 41,665 41,665 S due September 1, 2017, variable ........................ 31,000 31,000 T due September 1, 2017, variable ........................ 60,000 60,000 U due August 15, 2013, variable .......................... 35,200 35,200 V due August 15, 2019, 5 5/8% ............................ 102,000 102,000 W due October 15, 2020, 5.45% ............................ 26,000 26,000 X due April 15, 2023, 5.90% .............................. 40,000 40,000 Y due May 1, 2027, variable .............................. 25,000 -- Z due August 1, 2030, variable ........................... 83,335 -- ----------- ----------- Total first mortgage bonds ............................ 486,800 506,800 Pollution control bonds (unsecured) - Series due September 1, 2026, variable ..................... 22,500 22,500 Series due September 1, 2026, variable ..................... 27,500 27,500 Series due November 1, 2027, variable ...................... 35,000 35,000 Series due November 1, 2027, variable ...................... 35,000 35,000 ----------- ----------- Total unsecured pollution control bonds .................. 120,000 120,000 ----------- ----------- Total bonds outstanding .................................... 606,800 626,800 Less current portion of long-term debt ..................... 246,200 246,200 ----------- ----------- Long-term debt ............................................. 360,600 380,600 ----------- ----------- Total capitalization ....................................... $ 1,234,668 $ 1,159,304 =========== ===========
The accompanying notes are an integral part of these financial statements. 53 Louisville Gas and Electric Company Notes to Financial Statements NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES LG&E, a subsidiary of LG&E Energy and an indirect subsidiary of Powergen, is a regulated public utility 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 is an exempt public utility holding company with wholly-owned subsidiaries including LG&E, KU, Capital Corp., LEM, and LG&E Services. All of the LG&E's Common Stock is held by LG&E Energy. On December 11, 2000, LG&E Energy Corp. and Powergen plc completed the merger involving the two companies. Powergen is a registered public utility holding company under PUHCA. No costs associated with the Powergen merger nor any of the effects of purchase accounting have been reflected in the financial statements of LG&E. UTILITY PLANT. LG&E'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 for determining retail customer rates. LG&E 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 2000 were 3.6% (3.3% electric, 3.8% gas and 7.3% common); for 1999 were 3.4% (3.2% electric, 3.2% gas, and 7.1% common); and for 1998 were 3.4% (3.2% electric, 3.4% gas, and 7.4% common) of average depreciable plant. Pursuant to a recently completed depreciation study, LG&E will implement new depreciation rates as of January 1, 2001. The new rates are expected to be 3.5% (3.3% electric, 3.4% gas, and 7.3% common). CASH AND TEMPORARY CASH INVESTMENTS. LG&E 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. GAS STORED UNDERGROUND. Gas inventories of $54.4 million and $38.8 million at December 31, 2000 and 1999, respectively, are included in gas stored underground in the balance sheet. The inventory is accounted for using the average-cost method. FINANCIAL INSTRUMENTS. LG&E uses over-the-counter interest-rate swap agreements to hedge its exposure to fluctuations in the interest rates it pays on variable-rate debt. LG&E also uses exchange-traded U.S. Treasury note and bond futures to hedge its exposure to fluctuations in the value of its investments in the preferred stocks of other companies. Gains and losses on interest-rate swaps used to hedge interest rate risk are reflected in interest charges monthly. Gains and losses on U.S. Treasury note and bond futures used to hedge investments in preferred stocks are charged or credited to other income - net. The treasury futures are now listed as assets held for sale. See Note 4, Financial Instruments. DEBT EXPENSE. Debt expense is amortized over the lives of the related bond issues, consistent with regulatory 54 practices. DEFERRED INCOME TAXES. Deferred income taxes have been provided for all material book-tax temporary differences. INVESTMENT TAX CREDITS. Investment tax credits resulted from provisions of the tax law that permitted a reduction of LG&E's tax liability based on credits for certain construction expenditures. Deferred investment tax credits are being amortized to income over the estimated lives of the related property that gave rise to the credits. REVENUE RECOGNITION. Revenues are recorded based on service rendered to customers through month-end. LG&E accrues an estimate for unbilled revenues from each meter reading date to the end of the accounting period. The unbilled revenue estimates included in accounts receivable for LG&E at December 31, 2000 and 1999, were approximately $62.8 million and $31.1 million, respectively. Under an agreement approved by the Kentucky Commission in 1994, LG&E implemented a demand side management program, including a "decoupling mechanism" which allowed LG&E to recover a predetermined level of revenue on electric and gas residential sales. In 1998, the decoupling mechanism was suspended. See Note 3, Rates and Regulatory Matters. 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. LG&E implemented a Kentucky Commission-approved experimental performance-based ratemaking mechanism related to gas procurement and off-system gas sales activity in October 1997. See Note 3, Rates and Regulatory Matters. MANAGEMENT'S USE OF ESTIMATES. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported assets and liabilities and disclosure of contingent items at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. See Note 12, Commitments and Contingencies, for a further discussion. NEW ACCOUNTING PRONOUNCEMENTS. During 2000 and 1999, the following accounting pronouncements were issued that affect LG&E: SFAS No. 133, ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES, establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or a liability measured at its fair value. SFAS No. 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that LG&E must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. SFAS No. 133 could increase the volatility in earnings and other comprehensive income. SFAS No. 137, ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES -- DEFERRAL OF THE EFFECTIVE DATE OF SFAS NO. 133, deferred the effective date of SFAS No. 133 until January 1, 2001. LG&E adopted SFAS No. 133 on January 1, 2001. The effect of this statement will be a charge of $3.6 million to cumulative effect of change in accounting principle (net of tax) in other comprehensive income. EITF No. 98-10, ACCOUNTING FOR ENERGY TRADING AND RISK MANAGEMENT ACTIVITIES was adopted effective January 1, 1999. The pronouncement requires energy trading contracts to be marked to market on the balance sheet, with the gains and losses shown net in the income statement. EITF No. 98-10 more broadly defines what represents energy trading to include economic activities related to physical assets which were not previously marked to market by established industry practice. Adoption of EITF No. 98-10 did not have a material impact on LG&E's consolidated results of operations or financial position. 55 NOTE 2 - MERGERS AND ACQUISITIONS On December 11, 2000, LG&E Energy Corp. and Powergen plc successfully completed the merger transaction involving the two companies. LG&E Energy had announced on February 28, 2000, that its Board of Directors accepted the offer to be acquired by Powergen for cash of approximately $3.2 billion or $24.85 per share and the assumption of $2.2 billion of LG&E Energy's debt. Pursuant to the acquisition agreement, LG&E Energy became a wholly owned subsidiary of Powergen and, as a result, LG&E became an indirect subsidiary of Powergen. LG&E will continue its separate identity and serve customers in Kentucky under its existing name. The preferred stock and debt securities of LG&E were not affected by this transaction and LG&E will continue to file SEC reports. Following the merger, Powergen became a registered holding company under PUHCA, and LG&E, as a subsidiary of a registered holding company, became subject to additional regulations under PUHCA. LG&E Energy and KU Energy merged on May 4, 1998, with LG&E Energy as the surviving corporation. As a result of the merger, the LG&E Energy, which is the parent of LG&E, became the parent company of KU. The operating utility subsidiaries (LG&E and KU) have continued to maintain their separate corporate identities and serve customers in Kentucky and Virginia under their present names. LG&E Energy has estimated approximately $760 million in gross non-fuel savings over a ten-year period following the merger. Costs to achieve these savings for LG&E of $50.2 million were recorded in the second quarter of 1998, $18.1 million of which were initially deferred and are being amortized over a five-year period pursuant to regulatory orders. Primary components of the merger costs were separation benefits, relocation costs, and transaction fees, the majority of which were paid by December 31, 1998. LG&E expensed the remaining costs associated with the merger ($32.1 million) in the second quarter of 1998. In regulatory filings associated with approval of the merger, LG&E committed not to seek increases in existing base rates and proposed reductions in their retail customers' bills in amounts based on one-half of the savings, net of the deferred and amortized amount, over a five-year period. The preferred stock and debt securities of LG&E were not affected by the merger. Management has accounted for the LG&E Energy - KU Energy merger as a pooling of interests and as a tax-free reorganization under the Internal Revenue Code. As part of its LG&E Energy - KU Energy merger order, the Kentucky Commission approved a surcredit whereby 50% of the net non-fuel cost savings estimated to be achieved from the merger, less $18.1 million or 50% of the originally estimated costs to achieve such savings, be applied to reduce customer rates through a surcredit on customers' bills and the remaining 50% be retained by the companies. The surcredit is allocated 53% to KU and 47% to LG&E pursuant to Kentucky Commission order. The surcredit will be about 2% of customer bills through mid 2003 and will amount to approximately $55 million in net non-fuel savings to LG&E. Any fuel cost savings are passed to Kentucky customers through the companies' fuel adjustment clauses. See Note 3 for more information about LG&E's rates and regulatory matters. NOTE 3 - RATES AND REGULATORY MATTERS Accounting for the regulated utility business conforms with generally accepted accounting principles as applied to regulated public utilities and as prescribed by FERC and the Kentucky Commission. LG&E is subject to SFAS No. 71, ACCOUNTING FOR THE EFFECTS OF CERTAIN TYPES OF REGULATION, under which 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 return to customers in future rates. LG&E's current or expected recovery of deferred costs and expected return of deferred credits is generally based on specific ratemaking decisions or precedent for each item. The following regulatory assets and liabilities were included in LG&E's balance sheets 56 as of December 31 (in thousands of $):
2000 1999 ---- ---- Unamortized loss on bonds $ 19,036 $ 16,556 Merger costs 9,073 12,702 Manufactured gas sites 2,368 2,185 One utility costs 6,331 - -------- --------- Total regulatory assets 36,808 31,443 -------- --------- Deferred income taxes - net (54,593) (56,767) Deferred net gain (559) (1,959) ---------- --------- Total regulatory liabilities (55,152) (58,726) --------- --------- Regulatory liabilities - net $(18,344) $(27,283) ======== ========
PUHCA. Following the merger transaction involving LG&E Energy and Powergen, Powergen became a registered holding company under PUHCA. As a result, Powergen, its utility subsidiaries, including LG&E, and certain of its non-utility subsidiaries are subject to extensive regulation by the SEC under PUHCA with respect to issuances and sales of securities, acquisitions and sales of certain utility properties, and intra-system sales of certain goods and services. In addition, PUHCA generally limits the ability of registered holding companies to acquire additional public utility systems and to acquire and retain businesses unrelated to the utility operations of the holding company. Powergen believes that it has adequate authority (including financing authority) under existing SEC orders and regulations for it and its subsidiaries to conduct their businesses as proposed during 2001. Powergen will seek additional authorization when necessary. ENVIRONMENTAL COST RECOVERY. In August 1999, a final order of the Kentucky Commission approved LG&E's settlement agreement concerning the refund of the recovery of costs associated with pre-1993 environmental projects. LG&E began applying the refund to customers' bills in October 1999, and completed the refund process in the month of November 2000. All aspects of the original litigation of this issue have now been resolved. In March 2000, LG&E filed an application with the Kentucky Commission to obtain a CCN to construct up to three SCRs NOx reduction facilities. The construction and subsequent operation of the SCRs is intended to reduce NOx emission levels to meet the EPA's mandated NOx emission level of 0.15 lbs./ Mmbtu by May 2003. Following a period of discovery in the proceeding, the Kentucky Commission granted LG&E's request for a CCN in June 2000. In its order, the Kentucky Commission ruled that LG&E's proposed plan for construction was "reasonable, cost-effective and will not result in the wasteful duplication of facilities." In October 2000, LG&E filed an application with the Kentucky Commission to amend its Environmental Compliance Plan to reflect the addition of the proposed NOx reduction technology projects and to amend its Environmental Cost Recovery Tariff to include an overall rate of return on capital investments. Approval of LG&E's application will allow LG&E to begin to recover the costs associated with these new projects, subject to Kentucky Commission oversight during normal six-month and two-year reviews. Following the completion of hearings in March 2001, a ruling is expected by May 2001. ELECTRIC PBR/ESM. In October 1998, LG&E filed an application with the Kentucky Commission for approval of a new method of determining electric rates that sought to provide financial incentives for LG&E to further reduce customers' rates. The filing was made pursuant to the September 1997 Kentucky Commission order approving the merger of LG&E Energy and KU Energy, wherein the Kentucky Commission directed LG&E to indicate whether they desired to remain under traditional rate of return regulation or commence non-traditional regulation. The proposed ratemaking method, known as PBR, included financial incentives for LG&E to 57 reduce fuel costs and increase generating efficiency, and to share any resulting savings with customers. Additionally, the PBR proposal provided for financial penalties and rewards to assure continued high quality service and reliability. In April 1999, LG&E filed a joint agreement with KU and the Kentucky Attorney General to adopt the PBR plan subject to certain amendments. The Kentucky Commission issued initial orders implementing the amended PBR plan, effective July 1999, and subject to modification. The Kentucky Commission also consolidated into the continuing PBR proceedings an earlier March 1999, rate complaint by a group of industrial intervenors, KIUC, in which KIUC requested significant reductions in electric rates. Hearings were conducted before the Kentucky Commission on LG&E's amended PBR plan and the KIUC rate reduction petitions in August and September 1999. In January 2000, the Kentucky Commission issued orders for LG&E in the subject cases, ruling that LG&E should reduce base rates by $27.2 million effective with bills rendered beginning March 1, 2000. The Kentucky Commission eliminated LG&E's proposal to operate under its PBR plan and reinstated the FAC mechanism effective March 1, 2000. The Kentucky Commission offered LG&E the opportunity to operate under an ESM for the next three years. Under this mechanism, incremental annual earnings resulting in a rate of return on equity either above or below a range of 10.5% to 12.5% would be shared 60% with shareholders and 40% with ratepayers. Later in January 2000, LG&E filed motions for correction to the January 2000 orders for computational and other errors made in the Kentucky Commission's orders which produced overstatements in the base rate reductions to LG&E of $1.1 million. In February 2000, LG&E accepted the Kentucky Commission's proposed ESM and filed an ESM tariff which contained detailed provisions for operation of the ESM rates. In June 2000, the Kentucky Commission ruled that the final rate reduction should be $26.3 million, a change of approximately $900,000 and ordered LG&E to implement the revised rates effective with service rendered beginning June 1, 2000. LG&E reinstated its FAC beginning with March 2000 billings. The first ESM filing was made on March 1, 2001, for year ended December 31, 2000. By order of the Kentucky Commission rate changes prompted by the ESM filing go into effect in April of each year. At December 31, 2000, LG&E recorded in its financial statements an estimated refund to ratepayers of $2.5 million. DSM. LG&E's rates contain a DSM provision. The provision includes a rate mechanism that provides concurrent recovery of DSM costs and provides an incentive for implementing DSM programs. This program had allowed LG&E to recover revenues from lost sales associated with the DSM program (decoupling), but in 1998, LG&E and customer interest groups requested an end to the then current form of the decoupling rate mechanism. In September 1998, the Kentucky Commission accepted LG&E's modified tariff discontinuing the decoupling mechanism effective as of June 1, 1998. In September 2000, LG&E filed a plan to continue DSM programming with the Kentucky Commission. This filing calls for the expansion of the DSM programs into the service territory served by KU and proposes a mechanism to recover revenues from lost sales associated with DSM programs based on program planning engineering estimates and post-implementation evaluation. GAS PBR. Since October 1997, LG&E has implemented an experimental performance-based ratemaking mechanism related to gas procurement activities and off-system gas sales only. During the three-year test period beginning October 1997, rate adjustments related to this mechanism will be determined for each 12-month period beginning November 1 and ending October 31. Since its implementation on November 1, 1997, through October 31, 2000, LG&E has achieved $19.6 million in savings. Of the total savings, LG&E has retained $8.9 million, and the remaining portion of $10.7 million has been shared with customers. In December 2000, LG&E filed an Application reporting on the operation of the experimental PBR and requested the Kentucky Commission to extend the PBR for an additional five years as a result of the benefits provided to both 58 LG&E and its customers during the preceding three year experimental period. A ruling is expected by the summer of 2001. FAC. Prior to implementation of the PBR in July 1999, and following its termination in March 2000, LG&E employed an FAC mechanism, which under Kentucky law allowed LG&E to recover from customers, the actual fuel costs associated with retail electric sales. In February 1999, LG&E received orders from the Kentucky Commission requiring a refund to retail electric customers of approximately $3.9 million resulting from reviews of the FAC from November 1994, through April 1998, of which $1.9 million was refunded in April 1999, for the period beginning November 1994, and ending October 1996. The orders changed LG&E's method of computing fuel costs associated with electric line losses on wholesale sales appropriate for recovery through the FAC. Following rehearing in December 1999, the Kentucky Commission agreed with LG&E 's position on the appropriate loss factor to use in the FAC computation and issued an order reducing the refund level for the 18-month period under review to approximately $800,000. LG&E enacted the refund with billings in the month of January 2000. LG&E and KIUC each filed separate appeals from the Kentucky Commission's February 1999 orders with the Franklin County, Kentucky Circuit Court and in May 2000, the Court affirmed the Kentucky Commission's orders regarding the amounts disallowed and ordered the case remanded as to the Kentucky Commission's denial of interest, directing the Kentucky Commission to determine whether interest should be awarded to LG&E's ratepayers. In June 2000, LG&E appealed the Circuit Court's decision to the Kentucky Court of Appeals. A final decision on the appeal is not expected until late 2001 or early 2002. GAS RATE CASE. In March 2000, LG&E filed an application with the Kentucky Commission requesting an adjustment in LG&E's gas rates. LG&E asked for a general adjustment in gas rates for a test year for the twelve months ended December 31, 1999. The revenue increase applied for was $26.4 million. The Kentucky Commission subsequently suspended the effective date of the proposed new tariffs, and held hearings during August 2000. In September 2000, the Kentucky Commission granted LG&E an annual increase in its base gas revenues of $20.2 million effective September 28, 2000. The Kentucky Commission authorized a return on equity of 11.25%. The Kentucky Commission approved LG&E's proposal for a weather normalization billing adjustment mechanism that will normalize the effect of weather on revenues from gas sales. In October 2000, the Kentucky Attorney General requested that the Kentucky Commission grant rehearing on a single revenue requirements issue (normalization of forfeited discounts) on the grounds that the September order did not rule on or otherwise discuss the issue. In November 2000, the Kentucky Commission granted the Attorney General's request for rehearing, rejected the Attorney General's proposed adjustment to normalize the level of forfeited discounts, and ordered that its September 2000 order be modified to reflect its findings on the issue. KENTUCKY COMMISSION ADMINISTRATIVE CASE FOR AFFILIATE TRANSACTIONS. In December 1997, the Kentucky Commission opened Administrative Case No. 369 to consider Kentucky Commission policy regarding cost allocations, affiliate transactions and codes of conduct governing the relationship between utilities and their non-utility operations and affiliates. The Kentucky Commission intends to address two major areas in the proceedings: the tools and conditions needed to prevent cost shifting and cross-subsidization between regulated and non-utility operations; and whether a code of conduct should be established to assure that non-utility segments of the holding company are not engaged in practices that could result in unfair competition caused by cost shifting from the non-utility affiliate to the utility. In September 1998, the Kentucky Commission issued a draft code of conduct and cost allocation guidelines. In January 1999, LG&E, as well as all parties to the proceeding, filed comments on the Kentucky Commission draft proposals. In December 1999, the Kentucky Commission issued guidelines on cost allocation and held a hearing in January 2000, on the draft code of conduct. In February 2000, the Kentucky Commission issued including a draft Code of Conduct for the purpose of further consideration in the process to promulgate a regulation. In early 2000, the Kentucky General Assembly enacted legislation, House Bill 897, which authorized the Kentucky Commission to require utilities who provide nonregulated activities to keep separate accounts and allocate costs in accordance with procedures established by the Kentucky Commission. On February 14, 2001, the Kentucky Commission published notice 59 of their intent to promulgate new administrative regulations. In the same Bill, the General Assembly set forth provisions to govern a utilities activities related to the sharing of information, databases, and resources between its employees or an affiliate involved in the marketing or the provision of nonregulated activities and its employees or an affiliate involved in the provision of regulated services. The legislation became law in July 2000 and LG&E has been operating pursuant thereto since that time. NOTE 4 - FINANCIAL INSTRUMENTS The cost and estimated fair values of LG&E's non-trading financial instruments as of December 31, 2000 and 1999 follow (in thousands of $):
2000 1999 ---- ---- Fair Fair Cost Value Cost Value ---- ----- ---- ----- Marketable securities $ 4,403 $ 4,056 $ 7,253 $ 6,936 Long-term investments - Not practicable to estimate fair value 564 564 746 746 Preferred stock subject to mandatory redemption 25,000 25,275 25,000 24,861 Long-term debt (including current portion) 606,800 606,236 626,800 623,498 U.S. Treasury note and bond futures -- -- -- 81 Interest-rate swaps -- (5,998) -- 1,666
All of the above valuations reflect prices quoted by exchanges except for the swaps and the long-term investments. The fair values of the swaps reflect price quotes from dealers or amounts calculated using accepted pricing models. The fair values of the long-term investments reflect cost, since LG&E cannot reasonably estimate fair value. INTEREST RATE SWAPS. LG&E enters into interest rate swap agreements to exchange variable interest rate payment obligations without the exchange of underlying principal amounts. As of December 31, 2000, and 1999, LG&E was party to various interest rate swaps with aggregate notional amounts of $234.3 million in each year. Under swap agreements LG&E paid fixed rates averaging 4.40% and 3.80% and received variable rates averaging 4.84% and 5.46% at December 31, 2000, and 1999, respectively. The swaps mature on dates ranging from 2001 to 2020. At December 31, 2000, LG&E held U.S. Treasury note and bond futures contracts with notional amounts totaling $6.1 million. These contracts are used to hedge price risk associated with certain marketable securities and mature in March 2001. NOTE 5 - CONCENTRATIONS OF CREDIT AND OTHER RISK Credit risk represents the accounting loss that would be recognized at the reporting date if counterparties failed 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. LG&E's customer receivables and gas and electric revenues arise from deliveries of natural gas to approximately 299,000 customers and electricity to approximately 364,000 customers in Louisville and adjacent areas in 60 Kentucky. For the year ended December 31, 2000, 72% of total revenue was derived from electric operations and 28% from gas operations. In December 1998, LG&E and IBEW Local 2100 employees, which represent approximately 60% of LG&E's workforce, entered into a three-year collective bargaining agreement. NOTE 6 - MARKETABLE SECURITIES In 2000, LG&E classified marketable securities as "trading securities" under the provisions of SFAS No. 115, ACCOUNTING FOR CERTAIN INVESTMENTS IN DEBT AND EQUITY SECURITIES. Prior to that, LG&E's marketable securities had been determined to be "available-for-sale." All unrealized holding gains and losses were immediately recognized in earnings on the date of transfer. Proceeds from sales of trading securities in 2000 were approximately $4.1 million. Proceeds from sales of available-for-sale securities in 1999 were approximately $11.7 million. The sales for both years resulted in immaterial net realized gains and losses, calculated using the specific identification method. Approximate cost, fair value, and other required information pertaining to LG&E's securities by major security type, as of December 31, 2000 and 1999, follow (in thousands of $):
Fixed Equity Income Total ------ ------ ----- 2000: Cost $ 4,403 $ -- $ 4,403 Realized losses (347) -- (347) ------- ------- ------- Fair values $ 4,056 $ -- $ 4,056 ======= ======= ======= Fair values: No maturity $ 4,056 $ -- $ 4,056 ------- ------- ------- Total fair values $ 4,056 $ -- $ 4,056 ======= ======= ======= 1999: Cost $ 4,385 $ 2,868 $ 7,253 Unrealized gains 90 3 93 Unrealized losses (304) (106) (410) ------- ------- ------- Fair values $ 4,171 $ 2,765 $ 6,936 ======= ======= ======= Fair values: No maturity $ 4,171 $ -- $ 4,171 Contractual maturities: Less than one year -- 2,134 2,134 One to five years -- 631 631 ------- ------- ------- Total fair values $ 4,171 $ 2,765 $ 6,936 ======= ======= =======
NOTE 7 - PENSION PLANS AND RETIREMENT BENEFITS PENSION PLANS. LG&E sponsors several qualified and non-qualified pension plans and other postretirement benefit plans for its employees. The following tables provide a reconciliation of the changes in the plans' benefit obligations and fair value of assets over the three-year period ending December 31, 2000, and a statement of the funded status as of December 31 for each of the last three years (in thousands of $): 61
2000 1999 1998 ---- ---- ---- PENSION PLANS: Change in benefit obligation Benefit obligation at beginning of year $ 283,267 $ 311,935 $ 274,095 Service cost 3,408 5,005 6,333 Interest cost 22,698 21,014 19,873 Plan amendments 17,042 (2,397) 3,724 Curtailment (gain) or loss -- -- (2,218) Special termination benefits -- -- 18,295 Benefits paid (16,656) (15,471) (10,866) Actuarial (gain) or loss and other 1,063 (36,819) 2,699 --------- --------- --------- Benefit obligation at end of year $ 310,822 $ 283,267 $ 311,935 ========= ========= ========= Change in plan assets Fair value of plan assets at beginning of year $ 360,095 $ 308,660 $ 280,238 Actual return on plan assets (6,150) 51,995 38,913 Employer contributions and plan transfers (1,804) 16,142 375 Benefits paid (16,656) (15,471) (10,866) Administrative expenses (2,107) (1,231) -- --------- --------- --------- Fair value of plan assets at end of year $ 333,378 $ 360,095 $ 308,660 ========= ========= ========= Reconciliation of funded status Funded status $ 22,556 $ 76,828 $ (3,275) Unrecognized actuarial (gain) or loss (74,086) (126,554) (72,037) Unrecognized transition (asset) or obligation (5,853) (6,965) (8,076) Unrecognized prior service cost 47,984 35,588 41,447 --------- --------- --------- Net amount recognized at end of year $ (9,399) $ (21,103) $ (41,941) ========= ========= ========= OTHER BENEFITS: Change in benefit obligation Benefit obligation at beginning of year $ 44,997 $ 44,964 $ 43,373 Service cost 822 1,205 761 Interest cost 4,225 3,270 2,946 Plan amendments 5,826 2,377 599 Curtailment (gain) or loss -- -- 344 Special termination benefits -- -- 2,855 Benefits paid (4,889) (3,050) (2,634) Actuarial (gain) or loss 6,000 (3,769) (3,280) --------- --------- --------- Benefit obligation at end of year $ 56,981 $ 44,997 $ 44,964 ========= ========= ========= Change in plan assets Fair value of plan assets at beginning of year $ 10,526 $ 6,062 $ 4,384 Actual return on plan assets (92) 1,776 199 Employer contributions 1,621 4,681 3,207 Benefits paid (4,889) (1,993) (1,728) --------- --------- --------- Fair value of plan assets at end of year $ 7,166 $ 10,526 $ 6,062 ========= ========= ========= Reconciliation of funded status Funded status $ (49,815) $ (34,471) $ (38,902) Unrecognized actuarial (gain) or loss 5,623 (1,638) (285) Unrecognized transition (asset) or obligation 13,374 14,489 18,080 Unrecognized prior service cost 8,960 4,292 3,519 --------- --------- --------- Net amount recognized at end of year $ (21,858) $ (17,328) $ (17,588) ========= ========= =========
62 There are no plan assets in the nonqualified plan due to the nature of the plan. The following tables provide the amounts recognized in the balance sheet and information for plans with benefit obligations in excess of plan assets as of December 31, 2000, 1999 and 1998 (in thousands of $):
2000 1999 1998 ---- ---- ---- PENSION PLANS: Amounts recognized in the balance sheet consisted of: Prepaid benefits cost $ 18,880 $ 6,466 $ -- Accrued benefit liability (28,279) (27,569) (41,977) Intangible asset -- -- 36 --------- --------- --------- Net amount recognized at year-end $ (9,399) $ (21,103) $ (41,941) ========= ========= ========= Additional year-end information for plans with accumulated benefit obligations in excess of plan assets (1): Projected benefit obligation $ 4,088 $ 4,845 $ 148,005 Accumulated benefit obligation 3,501 4,327 131,430 Fair value of plan assets -- -- 107,988
(1) 1998 includes non-union plan and SERPs. 2000 and 1999 include SERPs only. OTHER BENEFITS: Amounts recognized in the balance sheet consisted of: Accrued benefit liability $(21,858) $(17,328) $(17,588) ======== ======== ======== Additional year-end information for plans with benefit obligations in excess of plan assets: Projected benefit obligation $ 56,981 $ 44,997 $ 44,964 Fair value of plan assets 7,166 10,526 6,062
The following table provides the components of net periodic benefit cost for the plans for 2000, 1999 and 1998 (in thousands of $):
2000 1999 1998 ---- ---- ---- PENSION PLANS: Components of net periodic benefit cost Service cost $ 3,408 $ 5,005 $ 6,333 Interest cost 22,698 21,014 19,873 Expected return on plan assets (33,025) (28,946) (23,701) Amortization of prior service cost 4,646 3,462 3,882 Amortization of transition (asset) or obligation (1,112) (1,112) (1,112) Recognized actuarial (gain) or loss (6,856) (2,621) (2,248) -------- -------- -------- Net periodic benefit cost $(10,241) $ (3,198) $ 3,027 ======== ======== ======== Special charges Curtailment gain $ -- $ -- $ (2,168) Prior service cost recognized -- -- 1,914 Special termination benefits -- -- 18,295 -------- -------- -------- Total charges $ -- $ -- $ 18,041 ======== ======== ======== OTHER BENEFITS: 63 Components of net periodic benefit cost Service cost $ 822 $ 1,205 $ 761 Interest cost 4,225 3,270 2,946 Expected return on plan assets (683) (401) (296) Amortization of prior service cost 1,158 473 367 Amortization of transition (asset) or obligation 1,114 1,114 1,315 Recognized actuarial gain (485) (183) - -------- -------- -------- Net periodic benefit cost $ 6,151 $ 5,478 $ 5,093 ======== ======== ======== Special charges Curtailment loss $ - $ - $ 1,005 Prior service cost recognized - - 124 Special termination benefits - - 2,855 --------- -------- -------- Total charges $ - $ - $ 3,984 ========= ======== ========
On May 4, 1998, LG&E Energy and KU Energy merged, with LG&E Energy as the surviving corporation. During 1998, LG&E invested approximately $18 million in special termination benefits as a result of its early retirement program offered to eligible employees post-merger. The assumptions used in the measurement of LG&E's pension benefit obligation are shown in the following table:
2000 1999 1998 ---- ---- ---- Weighted-average assumptions as of December 31: Discount rate 7.75% 8.00% 7.00% Expected long-term rate of return on plan assets 9.50% 9.50% 8.50% Rate of compensation increase 4.75% 5.00% 3.50%-4.00%
For measurement purposes, a 7.00% annual increase in the per capita cost of covered health care benefits was assumed for 2000. The rate was assumed to decrease gradually to 5.00% for 2005 and remain at that level thereafter. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A 1% change in assumed health care cost trend rates would have the following effects (in thousands of $):
1% Decrease 1% Increase ----------- ----------- Effect on total of service and interest cost components for 2000 $ (246) $ 279 Effect on year-end 2000 postretirement benefit obligations (1,781) 2,009
THRIFT SAVINGS PLANS. LG&E has a thrift savings plan under section 401(k) of the Internal Revenue Code. Under the plan, eligible employees may defer and contribute to the plan a portion of current compensation in order to provide future retirement benefits. LG&E makes contributions to the plan by matching a portion of the employee contributions. The costs were approximately $2.7 million, $2.7 million, and $2.4 million for 2000, 1999, and 1998, respectively. NOTE 8 - INCOME TAXES Components of income tax expense are shown in the table below (in thousands of $):
2000 1999 1998 ---- ---- ---- 64 Included in operating expenses: Current - federal $32,612 $53,981 $45,716 - state 5,018 13,680 11,895 Deferred - federal - net 24,272 (4,818) 2,276 - state - net 6,797 (780) 678 Deferred investment tax credit - - 55 Amortization of investment tax credit (4,274) (4,289) (4,313) -------- --------- -------- Total 64,425 57,774 56,307 -------- -------- -------- Included in other income - net: Current - federal (2,187) 217 660 - federal - merger costs - - (6,758) - state (568) (30) 6 - state - merger costs - - (1,737) Deferred - federal - net (39) 254 (165) - state - net (10) 65 (42) -------- -------- -------- Total (2,804) 506 (8,036) -------- -------- -------- Total income tax expense $61,621 $58,280 $48,271 ======= ======= =======
Net deferred tax liabilities resulting from book-tax temporary differences are shown below (in thousands of $):
2000 1999 ---- ---- Deferred tax liabilities: Depreciation and other plant-related items $329,836 $321,889 Other liabilities 22,621 5,324 ---------- ---------- 352,457 327,213 ---------- ---------- Deferred tax assets: Investment tax credit 25,444 27,145 Income taxes due to customers 22,086 22,588 Pension overfunding 5,595 2,193 Accrued liabilities not currently deductible and other 10,100 19,377 ---------- ---------- 63,225 71,303 ---------- ---------- Net deferred income tax liability $289,232 $255,910 ======== ========
A reconciliation of differences between the statutory U.S. federal income tax rate and LG&E's effective income tax rate follows:
2000 1999 1998 ---- ---- ---- Statutory federal income tax rate 35.0% 35.0% 35.0% State income taxes, net of federal benefit 4.3 5.1 5.5 Amortization of investment tax credit (2.6) (2.8) (3.4) Nondeductible merger expenses - - 2.4 Other differences - net (.9) (1.9) (1.3) ----- ----- ----- Effective income tax rate 35.8% 35.4% 38.2% ==== ==== ====
65 NOTE 9 - OTHER INCOME - NET Other income - net, consisted of the following at December 31 (in thousands of $):
2000 1999 1998 ---- ---- ---- Interest and dividend income $3,103 $ 4,086 $ 4,245 Gains on fixed asset disposals 1,014 2,394 530 Income taxes and other 804 (2,339) (2,279) Income tax benefit on merger costs - - 8,495 -------- ------- ------- Other income - net $4,921 $ 4,141 $10,991 ====== ======= =======
NOTE 10 - FIRST MORTGAGE BONDS AND POLLUTION CONTROL BONDS Long-term debt and the current portion of long-term debt, summarized below (in thousands of $), consists primarily of first mortgage bonds and pollution control bonds. Interest rates and maturities in the table below are for the amounts outstanding at December 31, 2000.
Weighted Average Stated Interest Principal Interest Rates Rate Maturities Amounts -------------- ---- ---------- ------- Noncurrent portion Variable - 6.55% 5.49% 2003 - 2030 $360,600 Current portion (pollution control bonds) Variable 4.74% 2013 - 2027 246,200
Under the provisions for LG&E's variable-rate pollution control bonds, the bonds are subject to tender for purchase at the option of the holder and to mandatory tender for purchase upon the occurrence of certain events, causing the bonds to be classified as current portion of long-term debt. The average annualized interest rate for these bonds during 2000 was 4.74%. LG&E's First Mortgage Bonds, 6% Series of $42.6 million is scheduled to mature in 2003. There are no scheduled maturities of Pollution Control Bonds for the five years subsequent to December 31, 2000. In January 2000, LG&E exercised its call option on its $20 million 7.50% First Mortgage Bonds due July 1, 2002. The bonds were redeemed utilizing proceeds from issuance of commercial paper. In May 2000, LG&E issued $25 million variable rate pollution control bonds due May 1, 2027 and exercised its call option on $25 million, 7.45%, pollution control bonds due June 15, 2015. In August 2000, LG&E issued $83 million in variable rate pollution control bonds due August 1, 2030 and exercised its call option on its $83 million, 7 5/8%, pollution control bonds due November 1, 2020. Annual requirements for the sinking funds of LG&E's First Mortgage Bonds (other than the First Mortgage Bonds issued in connection with certain 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. Substantially all of LG&E's utility plants are pledged as security for its first mortgage bonds. LG&E's indenture, as supplemented, provides that portions of retained earnings will not be available for the payment of 66 dividends on common stock, under certain specified conditions. No portion of retained earnings is presently restricted by this provision. NOTE 11 - NOTES PAYABLE LG&E had no outstanding commercial paper at December 31, 2000. LG&E had outstanding commercial paper totaling $120.1 million at an average rate of 6.02% at December 31, 1999. At December 31, 2000, LG&E had $114.6 million in notes payable to LG&E Energy Corp. The note payable is due on demand and has an average percentage rate at December 31, 2000 of 6.84%. The rate is based on the available borrowing rate as of the last day of the prior month. At December 31, 2000, LG&E had unused lines of credit of $200 million, for which it pays commitment fees. The credit facility provides support of commercial paper borrowings. The credit lines are scheduled to expire in 2001. Management expects to renegotiate these lines when they expire. NOTE 12 - COMMITMENTS AND CONTINGENCIES CONSTRUCTION PROGRAM. LG&E had commitments in connection with its construction program aggregating approximately $12.6 million at December 31, 2000. Construction expenditures for the years 2001 and 2002 are estimated to total approximately $413 million. Included in 2001 is $57 million for the purchase of 53% of two CTs currently under construction. One of the CTs is being built at LG&E's Paddy Run location and the other at KU's E.W. Brown location. KU will own 47% of the two CTs. LG&E has received approval from the Kentucky Commission for the purchase of the CTs. OPERATING LEASE. LG&E leases office space and accounts for all of its office space leases as operating leases. Total lease expense for 2000, 1999, and 1998, less amounts contributed by the parent company, was $.9 million, $1.5 million, and $1.6 million, respectively. The future minimum annual lease payments under lease agreements for years subsequent to December 31, 2000, are as follows (in thousands of $): 2001 $ 3,654 2002 3,594 2003 3,507 2004 3,507 2005 1,754 -------- Total $16,016 =======
In December 1999, LG&E and KU entered into an 18-year cross-border lease of its two jointly owned combustion turbines recently installed at KU's Brown facility. LG&E's obligation was defeased upon consummation of the cross-border lease. The transaction produced a pre-tax gain of approximately $1.2 million which was recorded in other income on the income statement in 2000, pursuant to a Kentucky Commission order. ENVIRONMENTAL. The Clean Air Act imposed stringent new SO2 and NOx emission limits on electric generating units. LG&E previously had installed scrubbers on all of its generating units. LG&E's strategy for Phase II SO2 reductions, which commenced January 1, 2000, is to increase scrubber removal efficiency to delay additional capital expenditures and may also include fuel switching or upgrading scrubbers. LG&E met the NOx emission requirements of the Act through installation of low-NOx burner systems. LG&E's compliance plans are subject to many factors including developments in the emission allowance and fuel markets, future regulatory and legislative initiatives, and advances in clean air control technology. LG&E will continue to 67 monitor these developments to ensure that its environmental obligations are met in the most efficient and cost-effective manner. In September 1998, the EPA announced its final "NOx SIP Call" rule requiring states to impose significant additional reductions in NOx emissions by May 2003, in order to mitigate alleged ozone transport impacts on the Northeast region. The Commonwealth of Kentucky is currently in the process of revising its State Implementation Plan or "SIP" to require reductions in NOx emissions from coal-fired generating units to the 0.15 lb./Mmbtu level on a system-wide basis. In related proceedings in response to petitions filed by various Northeast states, in December 1999, EPA issued a final rule pursuant to Section 126 of the Clean Air Act directing similar NOx reductions from a number of specifically targeted generating units including all LG&E units. Both rules were appealed to the U.S. Court of Appeals for the D.C. Circuit. The D.C. Circuit subsequently upheld most provisions of the NOx SIP Call rule, but extended the compliance date to May 2004. As the court has yet to issue a final ruling on the Section 126 rule, all LG&E generating units remain subject to the May 2003 compliance date under that rule. LG&E continues to monitor the status of various appeals pending in the D.C. Circuit and U.S. Supreme Court. LG&E is currently implementing a plan for adding significant additional NOx controls to its generating units. Installation of additional NOx controls will proceed on a phased basis, with installation of controls commencing in late 2000 and continuing through the final compliance date. LG&E estimates that it will incur total capital costs of approximately $160 million to reduce its NOx emissions to the 0.15 lb./Mmbtu level on a company-wide basis. In addition, LG&E will incur additional operating and maintenance costs in operating new NOx controls. LG&E believes its costs in this regard to be comparable to those of similarly situated utilities with like generation assets. LG&E anticipates that such capital and operating costs are the type of costs that are eligible for recovery from customers under its environmental surcharge mechanism and believes that a significant portion of such costs could be recovered. However, Kentucky Commission approval is necessary and there can be no guarantee of recovery. LG&E is also monitoring several other air quality issues which may potentially impact coal-fired power plants, including the appeal of the D.C. Circuit's remand of the EPA's revised air quality standards for ozone and particulate matter, measures to implement EPA's regional haze rule, and EPA's December 2000 determination to regulate mercury emissions from power plants. In addition, LG&E is currently working with local regulatory authorities to review the effectiveness of remedial measures aimed at controlling particulate matter emissions from its Mill Creek Station. LG&E previously settled a number of property damage claims from adjacent residents and completed significant remedial measures as part of its ongoing capital construction program. LG&E owns or formerly owned three properties which are the location of past MGP operations. Various contaminants are typically found at such former MGP sites and environmental remediation measures are frequently required. With respect to the sites, LG&E has completed cleanups, obtained regulatory approval of site management plans, or reached agreements for other parties to assume responsibility for cleanup. Based on currently available information, management estimates that it will incur additional costs of $400,000. Accordingly, an accrual of $400,000 has been recorded in the accompanying financial statements. NOTE 13 - JOINTLY OWNED ELECTRIC UTILITY PLANT LG&E owns a 75% undivided interest in Trimble County Unit 1 which the Kentucky Commission has allowed to be reflected in customer rates. Of the remaining 25% of the Unit, IMEA owns a 12.12% undivided interest, and IMPA owns a 12.88% undivided interest. Each company is responsible for its proportionate ownership share of fuel cost, operation and maintenance expenses, and incremental assets. 68 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 60.00 495.00 (in thousands of $): Cost $555,829 Accumulated depreciation 157,252 -------- Net book value $398,577 ======== Construction work in progress (included above) $12,704
In July 1999, following approval from the Kentucky Commission, LG&E purchased for $45.7 million a 38% interest in two 164.5 Mw natural gas turbines installed at KU's E.W. Brown facility (Units 6 and 7) from Capital Corp. See also Note 12, Construction Program, for LG&E's purchase of two jointly owned CTs in 2001. NOTE 14 - SEGMENTS OF BUSINESS AND RELATED INFORMATION Effective December 31, 1998, LG&E adopted SFAS No. 131, DISCLOSURE ABOUT SEGMENTS OF AN ENTERPRISE AND RELATED INFORMATION. LG&E is a regulated public utility engaged in the generation, transmission, distribution, and sale of electricity and the storage, distribution, and sale of natural gas. Financial data for business segments, follow (in thousands of $):
Electric Gas Total -------- --- ----- 2000 Operating revenues $710,958(a) $272,489 $983,447 Depreciation and amortization 84,761 13,530 98,291 Interest income 2,551 552 3,103 Interest expense 35,604 7,614 43,218 Operating income taxes 57,869 6,556 64,425 Net income 100,395 10,178 110,573 Total assets 1,760,305 465,779 2,226,084 Construction expenditures 109,798 34,418 144,216 1999 Operating revenues $ 790,670(b) $177,579 $ 968,249 Depreciation and amortization 83,619 13,602 97,221 Interest income 3,435 651 4,086 Interest expense 31,558 6,404 37,962 Operating income taxes 56,883 891 57,774 Net income 104,853 1,417 106,270 Total assets 1,775,498 395,954 2,171,452 Construction expenditures 160,844 33,800 194,644 1998 69 Operating revenues $ 658,511(c) $191,545 $ 850,056 Depreciation and amortization 79,866 13,312 93,178 Interest income 3,566 679 4,245 Interest expense 30,389 5,933 36,322 Merger costs 32,072 - 32,072 Operating income taxes 56,401 (94) 56,307 Net income 75,368 2,752 78,120 Total assets 1,727,463 377,174 2,104,637 Construction expenditures 105,836 32,509 138,345
(a) Net of provision for rate refunds of $2.5 million. (b) Net of provision for rate refunds of $1.7 million. (c) Net of provision for rate refunds of $4.5 million. NOTE 15 - SELECTED QUARTERLY DATA (UNAUDITED) Selected financial data for the four quarters of 2000 and 1999 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 ----- ---- --------- -------- (Thousands of $) 2000 Operating revenues $249,642 $209,731 $229,640 $294,434 Net operating income 26,592 37,285 48,161 36,832 Net income 17,421 28,009 38,117 27,026 Net income available for common stock 16,256 26,692 36,756 25,659 1999 Operating revenues $226,620 $214,097 $296,395 $231,137 Net operating income 27,016 30,596 51,036 31,443 Net income 18,916 22,040 41,704 23,610 Net income available for common stock 17,826 20,954 40,614 22,375
NOTE 16 - SUBSEQUENT EVENTS On January 9, 2001, LG&E Energy announced a voluntary workforce separation program for non-union employees. On January 18, 2001, the union members at LG&E voted to approve a similar voluntary separation package. LG&E targeted areas where reductions were necessary and employees in these targeted areas had a one-time opportunity to accept the separation package. Employees began leaving LG&E at the end of February 2001 and will continue through the end of the year. LG&E estimates that the separation program will result in a workforce reduction of approximately 700 employees. On February 1, 2001, Roger Hale, Chairman of the Board and Chief Executive Officer announced his retirement from LG&E Energy, LG&E, and KU effective April 30, 2001. Victor A. Staffieri will replace Roger Hale as Chairman and Chief Executive Officer of LG&E Energy, LG&E, and KU. On February 6, 2001, LG&E sold accounts receivables to a wholly-owned special purpose subsidiary. 70 Simultaneously, the subsidiary entered into three-year accounts receivables securitization facilities with two financial institutions whereby an undivided interest in certain receivables are sold, on a revolving basis, for up to $75 million, at a cost of funds linked to commercial paper rates. Under the program LG&E pays fees for administrative and credit support services. 71 Louisville Gas and Electric Company 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. LG&E's financial statements have been audited by Arthur Andersen LLP, independent public accountants. Management has made available to Arthur Andersen LLP all LG&E'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 provides 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 LG&E'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, 2000, did not identify any material weaknesses in the design and operation of LG&E'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 LG&E, the Audit Committee meets regularly with LG&E'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. 72 Louisville Gas and Electric Company REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Shareholders of 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, 2000 and 1999, and the related statements of income, retained earnings, cash flows and comprehensive income for each of the three years in the period ended December 31, 2000. These financial statements are the responsibility of LG&E's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. 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, 2000 and 1999, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States. 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 the audit 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 26, 2001 (Except with respect to the matters discussed in Note 16, as to which the date is February 6, 2001.) 73 Kentucky Utilities Company Statements of Income (Thousands of $)
Years Ended December 31 2000 1999 1998 ---- ---- ---- OPERATING REVENUES: Electric (Note 1)............................ $851,941 $943,210 $831,614 Provision for rate refunds (Note 3).......... - (5,900) (21,500) --------- ---------- ---------- Total operating revenues................... 851,941 937,310 810,114 --------- ---------- --------- OPERATING EXPENSES: Fuel for electric generation................. 219,923 219,883 217,401 Power purchased.............................. 166,918 242,315 126,584 Other operation expenses..................... 108,072 116,521 121,275 Maintenance.................................. 61,643 57,318 63,608 Depreciation and amortization................ 98,256 89,922 86,657 Federal and state income taxes (Note 7)...... 51,963 60,380 53,256 Property and other taxes..................... 17,030 14,955 15,945 --------- ---------- ---------- Total operating expenses................... 723,805 801,294 684,726 --------- ---------- ---------- Net operating income............................ 128,136 136,016 125,388 Merger costs (Note 2)........................... - - 21,830 Other income - net (Note 8)..................... 6,843 9,437 7,846 Interest charges................................ 39,455 38,895 38,640 --------- ---------- ---------- Net income...................................... 95,524 106,558 72,764 Preferred stock dividends....................... 2,256 2,256 2,256 --------- ---------- ---------- Net income available for common stock........... $ 93,268 $104,302 $ 70,508 ========= ========= ==========
Statements of Retained Earnings (Thousands of $)
Years Ended December 31 2000 1999 1998 ---- ---- ---- Balance January 1............................... $329,470 $299,167 $304,750 Add net income.................................. 95,524 106,558 72,764 --------- --------- --------- 424,994 405,725 377,514 --------- --------- --------- Deduct: Cash dividends declared on stock: 4.75% cumulative preferred............. 950 950 950 6.53% cumulative preferred............. 1,306 1,306 1,306 Common................................. 75,500 73,999 76,091 ---------- ---------- ---------- 77,756 76,255 78,347 ---------- ---------- ---------- Balance December 31............................. $347,238 $329,470 $299,167 ======== ======== ========
The accompanying notes are an integral part of these financial statements. 74 Kentucky Utilities Company Balance Sheets (Thousands of $)
December 31 2000 1999 ---- ---- ASSETS: Utility plant, at original cost (Note 1)............... $2,826,383 $2,744,380 Less: reserve for depreciation........................ 1,378,283 1,288,819 ----------- ----------- 1,448,100 1,455,561 Construction work in progress.......................... 106,380 106,686 ------------ ------------ 1,554,480 1,562,247 ------------ ------------ Other property and investments - less reserve.......... 14,538 14,349 Current assets: Cash and temporary cash investments................. 314 6,793 Accounts receivable - less reserve of $800 in 2000 and 1999....................................... 90,419 88,549 Materials and supplies - at average cost: Fuel (predominantly coal)......................... 12,495 30,225 Other............................................. 25,812 26,213 Prepayments and other............................... 1,899 3,743 -------------- -------------- 130,939 155,523 ------------ ------------ Deferred debits and other assets: Unamortized debt expense............................ 4,651 4,827 Regulatory assets (Note 3).......................... 26,441 23,033 Other............................................... 8,469 25,111 ---------- ----------- 39,561 52,971 ---------- ----------- $1,739,518 $1,785,090 ========== =========== CAPITAL AND LIABILITIES: Capitalization (see statements of capitalization): Common equity....................................... $ 669,783 $ 637,015 Cumulative preferred stock.......................... 40,000 40,000 Long-term debt (Note 9)............................. 430,830 430,830 ------------ ------------ 1,140,613 1,107,845 ------------ ------------ Current liabilities: Current portion of long-term debt (Note 9).......... 54,000 115,500 Notes payable (Note 10)............................. 61,239 - Accounts payable.................................... 76,339 116,546 Provision for rate refunds.......................... - 20,567 Dividends declared.................................. 188 19,150 Accrued taxes....................................... 19,622 10,502 Accrued interest.................................... 6,373 7,329 Other............................................... 18,579 18,617 ------------ ------------ 236,340 308,211 ------------ ------------ Deferred credits and other liabilities: Accumulated deferred income taxes (Notes 1 and 7)... 246,680 243,620 Investment tax credit, in process of amortization... 14,901 18,575 Accumulated provision for pensions and related benefits (Note 6).................................. 47,495 48,285 Customers' advances for construction................ 1,540 1,174 Regulatory liabilities (Note 3)..................... 38,392 46,069 Other............................................... 13,557 11,311 ------------ ------------ 362,565 369,034 ------------ ------------ Commitments and contingencies (Note 11) $1,739,518 $1,785,090 ============ ============
The accompanying notes are an integral part of these financial statements. 75 Kentucky Utilities Company Statements of Cash Flows (Thousands of $)
Years Ended December 31 2000 1999 1998 ---- ---- ---- CASH FLOWS FROM OPERATING ACTIVITIES: Net income....................................... $ 95,524 $ 106,558 $ 72,764 Items not requiring cash currently: Depreciation and amortization.................. 98,256 89,922 86,657 Deferred income taxes - net.................... (2,449) (3,763) (2,437) Investment tax credit - net.................... (3,674) (3,727) (3,829) Change in certain net current assets: Accounts receivable............................ (1,870) 17,576 (31,482) Materials and supplies......................... 18,131 (8,263) 3,272 Accounts payable............................... (40,207) 6,514 71,162 Provision for rate refunds..................... (20,567) (933) 21,500 Accrued taxes.................................. 9,120 (6,231) 9,260 Accrued interest............................... (956) (781) (173) Prepayments and other.......................... 1,806 (3,042) (53) Other............................................ 23,136 10,346 12,776 --------- --------- --------- Net cash flows from operating activities....... 176,250 204,176 239,417 --------- --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Proceeds from insurance reimbursement............ 259 206 179 Construction expenditures........................ (100,587) (181,341) (91,992) --------- --------- --------- Net cash flows used for investing activities... (100,328) (181,135) (91,813) --------- --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: Short-term borrowings............................ 61,239 - 381,500 Repayments of short-term borrowings.............. - - (415,100) Retirement of long-term debt..................... (74,784) - (42) Issuance of long-term debt....................... 12,900 - - Additional paid-in capital....................... 15,000 - - Payment of dividends............................. (96,756) (75,197) (60,347) --------- --------- --------- Net cash flows used for financing activities.................................... (82,401) (75,197) (93,989) --------- --------- --------- Change in cash and temporary cash investments....... (6,479) (52,156) 53,615 Cash and temporary cash investments at beginning of year.................................. 6,793 58,949 5,334 --------- --------- --------- Cash and temporary cash investments at end of year............................................... $ 314 $ 6,793 $ 58,949 ========= ========= ======== Supplemental disclosures of cash flow information: Cash paid during the year for: Income taxes................................ $ 49,871 $ 71,258 $ 46,490 Interest on borrowed money.................. 35,196 35,508 36,008
The accompanying notes are an integral part of these financial statements. 76 Kentucky Utilities Company Statements of Capitalization (Thousands of $)
December 31 2000 1999 ---- ---- COMMON EQUITY: Common stock, without par value - outstanding 37,817,878 shares....................... $ 308,140 $ 308,140 Additional paid-in capital............................ 15,000 - Retained earnings..................................... 347,238 329,470 Other................................................. (595) (595) ---------- ---------- 669,783 637,015 ---------- ---------- CUMULATIVE PREFERRED STOCK: Shares Current Outstanding Redemption Price ----------- ---------------- Without par value, 5,300,000 shares authorized - 4.75% series, $100 stated value Redeemable on 30 days notice by KU ....................... 200,000 $101.00 20,000 20,000 6.53% series, $100 stated value .. 200,000 Not redeemable 20,000 20,000 ------------ ----------- 40,000 40,000 ------------ ----------- LONG-TERM DEBT - first mortgage bonds (Note 9): Q due June 15, 2000, 5.95%............................ - 61,500 Q due June 15, 2003, 6.32%............................ 62,000 62,000 S due January 15, 2006, 5.99%......................... 36,000 36,000 P due May 15, 2007, 7.92%............................. 53,000 53,000 R due June 1, 2025, 7.55%............................. 50,000 50,000 P due May 15, 2027, 8.55%............................. 33,000 33,000 Pollution control series: 1B due February 1, 2018, 6.25%...................... 20,930 20,930 2B due February 1, 2018, 6.25%...................... 2,400 2,400 3B due February 1, 2018, 6.25%...................... 7,200 7,200 4B due February 1, 2018, 6.25%...................... 7,400 7,400 7, due May 1, 2010, 7.375%.......................... - 4,000 7, due May 1, 2020, 7.60%........................... - 8,900 8, due September 15, 2016, 7.45%.................... 96,000 96,000 9, due December 1, 2023, 5.75%...................... 50,000 50,000 10, due November 1, 2024, variable.................. 54,000 54,000 A, due May 1, 2023, variable........................ 12,900 - ------------- ----------- Total bonds outstanding............................. 484,830 546,330 Less current portion of long-term debt.............. 54,000 115,500 ------------- ------------ Long-term debt...................................... 430,830 430,830 ------------- ------------ Total capitalization................................ $1,140,613 $1,107,845 ========== ==========
The accompanying notes are an integral part of these financial statements. 77 Kentucky Utilities Company Notes to Financial Statements NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES KU, a subsidiary of LG&E Energy and an indirect subsidiary of Powergen, is a regulated public utility engaged in the generation, transmission, distribution, and sale of electric energy. LG&E Energy is an exempt public utility holding company with wholly-owned subsidiaries including LG&E, KU, Capital Corp., LEM, and LG&E Services. All of the KU's Common Stock is held by LG&E Energy. On December 11, 2000, LG&E Energy Corp. and Powergen plc completed the merger involving the two companies. Powergen is a registered public utility holding company under PUHCA. No costs associated with the Powergen merger nor any of the effects of purchase accounting have been reflected in the financial statements of KU. CASH AND TEMPORARY CASH INVESTMENTS. KU 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. UTILITY PLANT. KU's utility 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 for determining retail customer rates. KU has not recorded any significant 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 AND AMORTIZATION. Depreciation is provided on the straight-line method over the estimated service lives of depreciable plant. The amounts provided for KU approximated 3.5% in 2000, 1999 and 1998. Pursuant to a recently completed depreciation study, KU will implement the new depreciation rates effective January 1, 2001. The new rate is expected to be 3%. FINANCIAL INSTRUMENTS. KU uses over-the-counter interest-rate swap agreements to hedge its exposure to interest rates. Gains and losses on interest-rate swaps used to hedge interest rate risk are reflected in interest charges monthly. See Note 4, Financial Instruments. DEBT EXPENSE. Debt expense is amortized over the lives of the related bond issues, consistent with regulatory practices. DEFERRED INCOME TAXES. Deferred income taxes have been provided for all material book-tax temporary differences. INVESTMENT TAX CREDITS. Investment tax credits resulted from provisions of the tax law that permitted a reduction of KU's tax liability based on credits for certain construction expenditures. Deferred investment tax credits are being amortized to income over the estimated lives of the related property that gave rise to the credits. 78 REVENUE RECOGNITION. Revenues are recorded based on service rendered to customers through month-end. KU accrues an estimate for unbilled revenues from each meter reading date to the end of the accounting period. The unbilled revenue estimates included in accounts receivable for KU equaled approximately $34.8 million and $29.6 million at December 31, 2000 and 1999, respectively. FUEL COSTS. The cost of fuel for electric generation is charged to expense as used. MANAGEMENT'S USE OF ESTIMATES. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported assets and liabilities and disclosure of contingent items at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. See Note 11, Commitments and Contingencies, for a further discussion. NEW ACCOUNTING PRONOUNCEMENTS. During 2000 and 1999, the following accounting pronouncements were issued that affect KU: SFAS No. 133, ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES, establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or a liability measured at its fair value. SFAS No. 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that KU must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. SFAS No. 133 could increase the volatility in earnings and other comprehensive income. SFAS No. 137, ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES -- DEFERRAL OF THE EFFECTIVE DATE OF SFAS NO. 133, deferred the effective date of SFAS No. 133 until January 1, 2001. KU adopted SFAS No. 133 on January 1, 2001. The effect of this statement will result in a credit of $1.6 million to cumulative effect of change in accounting principle (net of tax) in other comprehensive income. EITF No. 98-10, ACCOUNTING FOR ENERGY TRADING AND RISK MANAGEMENT ACTIVITIES was adopted effective January 1, 1999. The pronouncement requires energy trading contracts to be marked to market on the balance sheet, with the gains and losses shown net in the income statement. EITF No. 98-10 more broadly defines what represents energy trading to include economic activities related to physical assets which were not previously marked to market by established industry practice. Adoption of EITF No. 98-10 did not have a material impact on KU's results of operations or financial position. NOTE 2 - MERGERS AND ACQUISITIONS On December 11, 2000, LG&E Energy Corp. and Powergen plc successfully completed the merger transaction involving the two companies. LG&E Energy had announced on February 28, 2000, that its Board of Directors accepted the offer to be acquired by Powergen for cash of approximately $3.2 billion or $24.85 per share and the assumption of $2.2 billion of LG&E Energy's debt. Pursuant to the acquisition agreement, LG&E Energy became a wholly owned subsidiary of Powergen and, as a result, KU became an indirect subsidiary of Powergen. KU will continue its separate identity and serve customers in Kentucky and Virginia under its existing name. The preferred stock and debt securities of KU were not affected by this transaction and KU will continue to file SEC reports. Following the merger, Powergen became a registered holding company under PUHCA and KU, as a subsidiary of a registered holding company, became subject to additional regulations under PUHCA. LG&E Energy and KU Energy merged on May 4, 1998, with LG&E Energy as the surviving corporation. As a 79 result of the merger, the LG&E Energy, which is the parent of LG&E, became the parent company of KU. The operating utility subsidiaries (LG&E and KU) have continued to maintain their separate corporate identities and serve customers in Kentucky and Virginia under their present names. LG&E Energy has estimated approximately $760 million in gross non-fuel savings over a ten-year period following the merger. Costs to achieve these savings for KU of $42.3 million were recorded in the second quarter of 1998, $20.5 million of which were initially deferred and are being amortized over a five-year period pursuant to regulatory orders. Primary components of the merger costs were separation benefits, relocation costs, and transaction fees, the majority of which were paid by December 31, 1998. KU expensed the remaining costs associated with the merger ($21.8 million) at the time of the merger in the second quarter of 1998. In regulatory filings associated with approval of the merger, KU committed not to seek increases in existing base rates and proposed reductions in their retail customers' bills in amounts based on one-half of the savings, net of the deferred and amortized amount, over a five-year period. The preferred stock and debt securities of KU were not affected by the merger. Management has accounted for the LG&E Energy - KU Energy merger as a pooling of interests and as a tax-free reorganization under the Internal Revenue Code. As part of its LG&E Energy - KU Energy merger order, the Kentucky Commission approved a surcredit whereby 50% of the net non-fuel cost savings estimated to be achieved from the merger, less $38.6 million or 50% of the originally estimated costs to achieve such savings, be applied to reduce customer rates through a surcredit on customers' bills and the remaining 50% be retained by the companies. The surcredit is allocated 53% to KU and 47% to LG&E pursuant to Kentucky Commission order. The surcredit will be about 2% of customer bills through mid 2003 and will amount to approximately $63 million in net non-fuel savings to KU. Any fuel cost savings are passed to Kentucky customers through the companies' fuel adjustment clauses. See Note 3 for more information about KU's rates and regulatory matters. NOTE 3 - UTILITY RATES AND REGULATORY MATTERS Accounting for the regulated utility business conforms with generally accepted accounting principles as applied to regulated public utilities and as prescribed by FERC, the Kentucky Commission and the Virginia Commission. KU is subject to SFAS No. 71, ACCOUNTING FOR THE EFFECTS OF CERTAIN TYPES OF REGULATION, under which 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 return to customers in future rates. KU's current or expected recovery of deferred costs and expected return of deferred credits is generally based on specific ratemaking decisions or precedent for each item. The following regulatory assets and liabilities were included in KU's balance sheets as of December 31 (in thousands of $):
2000 1999 ---- ---- Unamortized loss on bonds $ 7,011 $ 7,594 Merger costs 10,232 14,324 Other 925 1,115 One utility costs 8,273 - ----------- --------- Total regulatory assets 26,441 23,033 --------- --------- Deferred income taxes - net (37,484) (42,992) Other (908) (3,077) ----------- ---------- Total regulatory liabilities (38,392) (46,069) --------- --------- Regulatory liabilities - net $(11,951) $(23,036) ======== ========
80 PUHCA. Following the merger transaction involving LG&E Energy and Powergen, Powergen became a registered holding company under PUHCA. As a result, Powergen, its utility subsidiaries, including KU, and certain of its non-utility subsidiaries are subject to extensive regulation by the SEC under PUHCA with respect to issuances and sales of securities, acquisitions and sales of certain utility properties, and intra-system sales of certain goods and services. In addition, PUHCA generally limits the ability of registered holding companies to acquire additional public utility systems and to acquire and retain businesses unrelated to the utility operations of the holding company. Powergen believes that it has adequate authority (including financing authority) under existing SEC orders and regulations for it and its subsidiaries to conduct their businesses as proposed during 2001. Powergen will seek additional authorization when necessary. ENVIRONMENTAL COST RECOVERY. In August 1999, a final order of the Kentucky Commission approved KU's settlement agreement concerning the refund of the recovery of costs associated with pre-1993 environmental projects. KU began applying the refund to customers' bills in October 1999 and completed the refund process in the month of November 2000. All aspects of the original litigation of this issue have now been resolved. In March 2000, KU filed an application with the Kentucky Commission to obtain a CCN to construct up to four SCRs NOx reduction facilities. The construction and subsequent operation of the SCRs is intended to reduce NOx emission levels to meet the EPA's mandated NOx emission level of 0.15 lbs./ Mmbtu by May 2003. Following a period of discovery in the proceeding, the Kentucky Commission granted KU's request for a CCN in June 2000. In its order, the Kentucky Commission ruled that KU's proposed plan for construction was "reasonable, cost-effective and will not result in the wasteful duplication of facilities." In October 2000, KU filed an application with the Kentucky Commission to amend its Environmental Compliance Plan to reflect the addition of the proposed NOx reduction technology projects and to amend its Environmental Cost Recovery Tariff to include an overall rate of return on capital investments. Approval of KU's application will allow KU to begin to recover the costs associated with these new projects, subject to Kentucky Commission oversight during normal six-month and two-year reviews. Following the completion of hearings in March 2001, a ruling is expected by May 2001. ELECTRIC PBR/ESM. In October 1998, KU filed an application with the Kentucky Commission for approval of a new method of determining electric rates that sought to provide financial incentives for KU to further reduce customers' rates. The filing was made pursuant to the September 1997 Kentucky Commission order approving the merger of LG&E Energy and KU Energy, wherein the Kentucky Commission directed KU to indicate whether they desired to remain under traditional rate of return regulation or commence non-traditional regulation. The proposed ratemaking method, known as PBR, included financial incentives for KU to reduce fuel costs and increase generating efficiency, and to share any resulting savings with customers. Additionally, the PBR proposal provided for financial penalties and rewards to assure continued high quality service and reliability. In April 1999, KU filed a joint agreement with LG&E and the Kentucky Attorney General to adopt the PBR plan subject to certain amendments. The Kentucky Commission issued initial orders implementing the amended PBR plan, effective July 1999, and subject to modification. The Kentucky Commission also consolidated into the continuing PBR proceedings an earlier March 1999, rate complaint by a group of industrial intervenors, KIUC, in which KIUC requested significant reductions in electric rates. Hearings were conducted before the Kentucky Commission on KU's amended PBR plans and the KIUC rate reduction petitions in August and September 1999. In January 2000, the Kentucky Commission issued orders for KU in the subject cases, ruling that KU should reduce base rates by $36.5 million effective with bills rendered beginning March 1, 2000. The Kentucky Commission eliminated KU's proposal to operate under its PBR plan and reinstated the FAC mechanism effective March 1, 2000. The Kentucky Commission offered KU the opportunity to operate under an ESM for 81 the next three years. Under this mechanism, incremental annual earnings for KU resulting in a rate of return on equity either above or below a range of 10.5% to 12.5% would be shared 60% with shareholders and 40% with ratepayers. Later in January 2000, KU filed motions for correction to the January 2000 orders for computational and other errors made in the Kentucky Commission's orders which produced overstatements in the base rate reductions to KU of $7.7 million. In February 2000, KU accepted the Kentucky Commission's opportunity to use an ESM by filing an ESM tariff, which contains the provisions operating under such mechanism. In June 2000, the Kentucky Commission ruled that the final rate reduction should be $30.4 million, a change of approximately $6.1 million from the original order and ordered KU to implement the revised rates effective with service rendered beginning June 1, 2000. KU reinstated its FAC beginning with March 2000 billings. The first ESM filing was made on March 1, 2001, for year ended December 31, 2000. By order of the Kentucky Commission rate changes prompted by the ESM filing go into effect in April of each year. At December 31, 2000, KU expects to fall within the range, therefore no adjustment was made to the financial statements. DSM. In September 2000, KU filed a plan with the Kentucky Commission that would expand LG&E's current DSM programs into the service territory served by KU. The filing includes a rate mechanism that provides for concurrent recovery of DSM costs, provides an incentive for implementing DSM programs, and recovers revenues from lost sales associated with the DSM program. The Kentucky Commission has not issued an order in this case. KU expects a ruling by mid-2001. FAC. Prior to implementation of the PBR in July 1999, and following its termination in March 2000, KU employed an FAC mechanism, which under Kentucky law allowed the utilities to recover from customers the actual fuel costs associated with retail electric sales. In July 1999, the Kentucky Commission issued a series of orders requiring KU to refund approximately $10.1 million resulting from reviews of the FAC from November 1994 to October 1998. The orders changed KU's method of computing fuel costs associated with electric line losses on off-system sales appropriate for recovery through the FAC, and KU's method for computing system line losses for the purpose of calculating the system sales component of the FAC charge. At KU's request, in July 1999, the Kentucky Commission stayed the refund requirement pending the Kentucky Commission's final determination of any rehearing request that KU may file. In August 1999, KU filed its request for rehearing of the July orders. In August 1999, the Kentucky Commission issued a final order in the KU proceedings, agreeing, in part, with KU's arguments outlined in its petition for rehearing. While the Kentucky Commission confirmed that KU should change its method of computing the fuel costs associated with electric line losses, it agreed with KU that the line loss percentage should be based on KU's actual line losses incurred in making wholesale sales rather than the percentage used in its Open Access Transmission Tariff. The Kentucky Commission also upheld its previous ruling concerning the computation of system line losses in the calculation of the FAC. The net effect of the Kentucky Commission's final order was to reduce the refund obligation to $6.7 million ($5.8 million on Kentucky jurisdictional basis) from the original order amount of $10.1 million. In August 1999, KU recorded its estimated share of anticipated FAC refunds. KU began implementing the refund in October and completed the refund in September 2000. Both KU and the KIUC appealed the order to the Franklin Circuit Court. In October 2000, the Court affirmed the Kentucky Commission's orders concerning all issues except interest, with respect to which it held that KU will be required to pay interest on the amount disallowed "if the Commission within its discretion so determines", and ordered the case be remanded to the Kentucky Commission on that issue. In November 2000, KU appealed the Circuit Court's decision to the Kentucky Court of Appeals. A decision is not expected until late 2001 or early 2002. 82 KENTUCKY COMMISSION ADMINISTRATIVE CASE FOR AFFILIATE TRANSACTIONS. In December 1997, the Kentucky Commission opened Administrative Case No. 369 to consider Kentucky Commission policy regarding cost allocations, affiliate transactions and codes of conduct governing the relationship between utilities and their non-utility operations and affiliates. The Kentucky Commission intends to address two major areas in the proceedings: the tools and conditions needed to prevent cost shifting and cross-subsidization between regulated and non-utility operations; and whether a code of conduct should be established to assure that non-utility segments of the holding company are not engaged in practices that could result in unfair competition caused by cost shifting from the non-utility affiliate to the utility. In September 1998, the Kentucky Commission issued a draft code of conduct and cost allocation guidelines. In January 1999, KU, as well as all parties to the proceeding, filed comments on the Kentucky Commission draft proposals. In December 1999, the Kentucky Commission issued guidelines on cost allocation and held a hearing in January 2000, on the draft code of conduct. In February 2000, the Kentucky Commission issued its ruling in the case, including a draft Code of Conduct for the purpose of further consideration in the process to promulgate a regulation. In early 2000, the Kentucky General Assembly enacted legislation, House Bill 897, which authorized the Kentucky Commission to require utilities who provide nonregulated activities to keep separate accounts and allocate costs in accordance with procedures established by the Kentucky Commission. On February 14, 2001, the Kentucky Commission published notice of their intent to promulgate new administrative regulations. In the same Bill, the General Assembly set forth provisions to govern a utilities activities related to the sharing of information, databases, and resources between its employees or an affiliate involved in the marketing or the provision of nonregulated activities and its employees or an affiliate involved in the provision of regulated services. The legislation became law in July 2000 and KU has been operating pursuant thereto since that time. NOTE 4 - FINANCIAL INSTRUMENTS The cost and estimated fair values of the KU's non-trading financial instruments as of December 31, 2000, and 1999 follow (in thousands of $):
2000 1999 ---- ---- Fair Fair Cost Value Cost Value ---- ----- ---- ----- Long-term debt (including current portion) $484,830 $491,277 $546,330 $542,242 Interest-rate swaps - 3,559 - (1,951)
All of the above valuations reflect prices quoted by exchanges except for the swaps. The fair values of the swaps reflect price quotes from dealers or amounts calculated using accepted pricing models. INTEREST RATE SWAPS. KU is party to three interest rate swaps with notional amounts totaling $153 million. In each case, KU pays a variable rate based on either LIBOR or the Bond Market Association's municipal swap index. In return, KU receives a fixed rate equal to the rate on underlying long-term debt of Series P, R, and PCS-9. At year end, KU paid an average rate of 6.69% and received an average rate of 7.13%. The swaps mature on dates ranging from 2007 to 2025. NOTE 5 - CONCENTRATIONS OF CREDIT AND OTHER RISK Credit risk represents the accounting loss that would be recognized at the reporting date if counterparties failed 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 83 to meet contractual obligations to be similarly affected by changes in economic or other conditions. KU's customer receivables and revenues arise from deliveries of electricity to about 464,000 customers in over 600 communities and adjacent suburban and rural areas in 77 counties in central, southeastern and western Kentucky and to about 29,000 customers in five counties in southwestern Virginia. For the year ended December 31, 2000, 100% of total utility revenue was derived from electric operations. In August 2000, KU and their employees represented by IBEW Local 2100 entered into a one-year collective bargaining agreement. At the same time, KU and their employees represented by USWA Local 9447-01 entered into a two year collective bargaining agreement with a reopener for wages only to be effective August 1, 2001. The employees represented by these two bargaining units makeup approximately 15% of KU's workforce. NOTE 6 - PENSION PLANS AND RETIREMENT BENEFITS PENSION PLANS. KU sponsors qualified and non-qualified pension plans and other postretirement benefit plans for its employees. The following tables provide a reconciliation of the changes in the plans' benefit obligations and fair value of assets over the three-year period ending December 31, 2000, and a statement of the funded status as of December 31 for each of the last three years (in thousands of $):
2000 1999 1998 ---- ---- ---- PENSION PLANS: Change in benefit obligation Benefit obligation at beginning of year $219,628 $233,288 $214,657 Service cost 4,312 6,210 6,672 Interest cost 17,205 15,564 15,043 Plan amendment 11,757 - 2,226 Acquisitions/divestitures - - (2,243) Curtailment (gain) or loss - - 1,901 Special termination benefits - - 5,427 Benefits paid (16,512) (12,822) (12,762) Actuarial (gain) or loss and other (3,356) (22,612) 2,367 -------- -------- -------- Benefit obligation at end of year $233,034 $219,628 $233,288 ======== ======== ======== Change in plan assets Fair value of plan assets at beginning of year $274,109 $238,124 $217,500 Actual return on plan assets (10,943) 49,883 31,209 Employer contributions and plan transfers (994) - 2,273 Benefits paid (16,512) (12,822) (12,762) Administrative expenses (983) (1,076) (96) -------- -------- -------- Fair value of plan assets at end of year $244,677 $274,109 $238,124 ======== ======== ======== Reconciliation of funded status Funded status $ 11,643 $ 54,481 $ 4,835 Unrecognized actuarial (gain) or loss (36,435) (74,579) (26,487) Unrecognized transition (asset) or obligation (847) (988) (1,128) Unrecognized prior service cost 14,176 3,564 4,943 -------- --------- -------- Net amount recognized at year-end $(11,463) $ (17,522) $(17,837) ======== ========= ======== OTHER BENEFITS: Change in benefit obligation Benefit obligation at beginning of year $ 54,201 $ 79,650 $ 72,139
84 Service cost 757 1,596 2,012 Interest cost 4,781 3,837 5,207 Plan amendments 7,127 (24,488) - Curtailment (gain) or loss - - 3,240 Special termination benefits - - - Benefits paid (4,318) (4,646) (2,617) Actuarial (gain) or loss 1,665 (1,748) (331) -------- -------- -------- Benefit obligation at end of year $ 64,213 $ 54,201 $ 79,650 ======== ======== ======== Change in plan assets Fair value of plan assets at beginning of year $ 28,720 $ 24,337 $ 17,763 Actual return on plan assets (1,162) 5,322 5,117 Employer contributions 522 3,520 3,805 Benefits paid (4,318) (4,459) (2,348) -------- -------- -------- Fair value of plan assets at end of year $ 23,762 $ 28,720 $ 24,337 ======== ======== ======== Reconciliation of funded status Funded status $(40,451) $(25,481) $(55,313) Unrecognized actuarial (gain) or loss (23,561) (28,976) (19,944) Unrecognized transition (asset) or obligation 21,871 23,694 45,701 Unrecognized prior service cost 6,109 - - -------- -------- -------- Net amount recognized at year-end $(36,032) $(30,763) $(29,556) ======== ======== ========
There are no plan assets in the non-qualified plan due to the nature of the plan. The following tables provide the amounts recognized in the balance sheet and information for plans with benefit obligations in excess of plan assets as of December 31, 2000, 1999 and 1998 (in thousands of $):
2000 1999 1998 ---- ---- ---- PENSION PLANS: Amounts recognized in the balance sheet consisted of: Accrued benefit liability $(11,463) $(17,522) $(17,837) Other - - (22) -------- -------- -------- Net amount recognized at year-end $(11,463) $(17,522) $(17,859) ======== ======== ======== Additional year-end information for plans with accumulated benefit obligations in excess of plan assets: Projected benefit obligation $ 1,505 $ 1,132 $ 2,300 Accumulated benefit obligation 336 40 99 OTHER BENEFITS: Amounts recognized in the balance sheet consisted of: Accrued benefit liability $(36,032) $ (30,763) $(29,556) Other - - (2,817) -------- -------- -------- Net amount recognized at year-end $(36,032) $ (30,763) $(32,373) ======== ======== ======== Additional year-end information for plans with benefit obligations in excess of plan assets: Projected benefit obligation $ 64,213 $ 54,201 $ 79,650 Fair value of plan assets 23,762 28,720 24,337
The following table provides the components of net periodic benefit cost for the plans for 2000, 1999 and 1998 85 (in thousands of $):
2000 1999 1998 ---- ---- ---- PENSION PLANS: Components of net periodic benefit cost Service cost $ 4,312 $ 6,211 $ 6,673 Interest cost 17,205 15,564 15,043 Expected return on plan assets (25,170) (21,957) (18,264) Amortization of transition (asset) or obligation (141) (141) 435 Amortization of prior service cost 1,145 410 (146) Amortization of net (gain) loss (3,410) (319) (151) -------- -------- -------- Net periodic benefit cost $ (6,059) $ (232) $ 3,590 ======== ======== ======== Special charges Prior service cost recognized $ - $ - $ 67 Special termination benefits - - 5,427 -------- -------- -------- Total charges $ - $ - $ 5,494 ======== ======== ======== OTHER BENEFITS: Components of net periodic benefit cost Service cost $ 757 $ 1,596 $ 2,012 Interest cost 4,781 3,837 5,207 Expected return on plan assets (1,768) (1,897) (1,424) Amortization of prior service cost 1,018 - - Amortization of transition (asset) or obligation 1,823 1,823 3,303 Amortization of net (gain) loss (820) (445) (536) -------- -------- -------- Net periodic benefit cost $ 5,791 $ 4,914 $ 8,562 ======== ======== ======== Special charges Curtailment loss $ - $ - $ 1,114 ======== ======== ========
On May 4, 1998 LG&E Energy and KU Energy merged, with LG&E Energy as the surviving corporation. At the time of the merger KU had both qualified and nonqualified pension plans. Effective May 4, 1998, due to the change in control, the present value balance of KU's SERP of $4.9 million was transferred and allocated between LG&E Energy's Nonqualified Savings Plan and KU's Nonqualified Savings plan of $2.2 million and $2.7 million, respectively. The plan is an unfunded, pretax deferred compensation program which provides officers and senior managers of KU the opportunity to defer earnings above the qualified savings plan limits. As an "Unfunded" plan the money is not specifically invested or secured and future distributions will be made from the general assets of KU. Currently interest is credited at a rate equal to the average yield on five-year Treasury notes. During 1998, KU invested approximately $6.6 million in special termination benefits as a result of its early retirement program offered to eligible employees post-merger. KU provides nonpension postretirement benefits for eligible retired employees. The assumptions used in the measurement of the KU's benefit obligation are shown in the following table:
2000 1999 1998 ---- ---- ---- Weighted-average assumptions as of December 31: 86 Discount rate 7.75% 8.00% 7.00% Expected long-term rate of return on plan assets 9.50% 9.50% 8.25% Rate of compensation increase 4.75% 5.00% 4.00%
For measurement purposes, a 7.00% annual increase in the per capita cost of covered health care benefits was assumed for 2000. The rate was assumed to decrease gradually to 5.00% for 2005 and remain at that level thereafter. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A 1% change in assumed health care cost trend rates would have the following effects (in thousands of $):
1% Decrease 1% Increase ----------- ----------- Effect on total of service and interest cost components for 2000 $ (426) $ 483 Effect on year-end 2000 postretirement benefit obligations (4,085) 4,640
THRIFT SAVINGS PLANS. KU has a thrift savings plan under section 401(k) of the Internal Revenue Code. Under the plan, eligible employees may defer and contribute to the plan a portion of current compensation in order to provide future retirement benefits. KU makes contributions to the plan by matching a portion of the employee contributions. The costs of this matching were approximately $2.5 million for 2000, $2.3 million for 1999 and $2.2 million for 1998. NOTE 7 - INCOME TAXES Components of income tax expense are shown in the table below (in thousands of $):
2000 1999 1998 ---- ---- ---- Included in operating expenses: Current - federal $44,927 $50,969 $46,321 - state 9,333 13,459 10,245 Deferred - federal - net (3,254) (4,833) (3,186) - state - net 957 785 (124) ------- ------- ------- Total 51,963 60,380 53,256 ------- ------- ------- Included in other income - net: Current - federal 349 1,028 (617) - state 67 54 (237) Deferred - federal - net (122) 182 694 - state - net (30) 102 178 Amortization of investment tax credit (3,674) (3,727) (3,829) ------- ------- ------- Total (3,410) (2,361) (3,811) ------- ------- ------- Total income tax expense $48,553 $58,019 $49,445 ======= ======= =======
Net deferred tax liabilities resulting from book-tax temporary differences are shown below (in thousands of $):
2000 1999 Deferred tax liabilities: Depreciation and other plant-related items $279,047 $313,202 Other liabilities 13,718 11,286 -------- --------
87 292,765 324,488 -------- -------- Deferred tax assets: Investment tax credit 6,014 7,497 Income taxes due to customers 15,124 16,712 Pension overfunding 3,974 5,797 Accrued liabilities not currently deductible and other 20,973 50,862 -------- -------- 46,085 80,868 -------- -------- Net deferred income tax liability $246,680 $243,620 ======== ========
A reconciliation of differences between the statutory U.S. federal income tax rate and KU's effective income tax rate follows:
2000 1999 1998 ---- ---- ---- Statutory federal income tax rate 35.0% 35.0% 35.0% State income taxes, net of federal benefit 4.9 5.7 5.4 Amortization of investment tax credit (2.6) (2.9) (3.1) Nondeductible merger expenses - - 6.4 Other differences - net (3.6) (2.5) (2.2) ----- ----- ----- Effective income tax rate 33.7% 35.3% 41.5% ==== ==== ====
NOTE 8 - OTHER INCOME - NET Other income - net, consisted of the following at December 31 (in thousands of $):
2000 1999 1998 ---- ---- ---- Equity in earnings - subsidiary company $ 2,242 $ 2,334 $ 2,167 Interest and dividend income 1,206 4,293 1,811 Gains on fixed asset disposals 5 759 272 Income taxes and other 3,390 2,051 3,596 -------- -------- -------- Other income - net $ 6,843 $9,437 $ 7,846 ======= ====== =======
NOTE 9 - FIRST MORTGAGE BONDS AND POLLUTION CONTROL BONDS Long-term debt and the current portion of long-term debt, summarized below in thousands of $, consists primarily of first mortgage bonds and pollution control bonds. Interest rates and maturities in the table below are for the amounts outstanding at December 31, 2000. Stated interest rates Variable, 5.75% - 8.55% Weighted-average interest rate 6.64% Maturities 2003 - 2027 Noncurrent portion $430,830 Current portion $54,000
Under the provisions for KU's variable-rate pollution control bonds, the bonds are subject to tender for purchase at the option of the holder and to mandatory tender for purchase upon the occurrence of certain events, causing 88 the bonds to be classified as current portion of long-term debt. The average annualized interest rate for these bonds during 2000 was 4.36%. In May 2000, KU issued the Mercer County Solid Waste Disposal Facility Revenue Bonds, 2000 Series A variable rate debt, for $12.9 million. These proceeds were used to redeem $4 million PCB Series 7, 7.38% bonds and $8.9 million of PCB Series 7, 7.6% bonds. In June 2000, $61.5 million Series Q, 5.95% First Mortgage Bonds matured and was paid in full. KU's First Mortgage Bond, 6.32% Series Q of $62 million is scheduled to mature in 2003. There are no scheduled maturities of Pollution Control Bonds for the five years subsequent to December 31, 2000. Substantially all of KU's utility plant is pledged as security for its First Mortgage Bonds. NOTE 10 - NOTES PAYABLE At December 31, 2000, KU had $61.2 million in notes payable to LG&E Energy Corp. The note payable is due on demand and has an average percentage rate at December 31, 2000 of 6.68%. The rate is based on the available borrowing rate as of the last day of the prior month. KU had no short-term borrowings at December 31, 1999. KU maintains an uncommitted line of credit which totaled $100 million at December 31, 2000. There was no outstanding balance as of that date. NOTE 11 - COMMITMENTS AND CONTINGENCIES CONSTRUCTION PROGRAM. KU had $11.5 million of commitments in connection with its construction program at December 31, 2000. Construction expenditures for the years 2001 and 2002 are estimated to total approximately $300 million. Included in 2001 is $51 million for the purchase of 47% of two CTs currently under construction. One of the CTs is being built at KU's E.W. Brown location and the other at LG&E's Paddy Run location. LG&E will own 53% of the two CTs. KU has received approval from the Kentucky Commission for the purchase of the CTs. KU is still waiting for confirmation of certain matters from the Virginia Commission. OPERATING LEASES. KU leases office space, office equipment, and vehicles. KU accounts for these leases as operating leases. Total lease expense for 2000, 1999, and 1998, was $2.3 million, $1.7 million, and $1.9 million, respectively. In December 1999, LG&E and KU entered into an 18-year cross-border lease of its two jointly owned combustion turbines recently installed at KU's Brown facility. KU's obligation was defeased upon consummation of the cross-border lease. The transaction produced a pre-tax gain of approximately $1.9 million which was recorded in other income on the income statement in 2000, pursuant to a Kentucky Commission order. ENVIRONMENTAL. The Clean Air Act imposed stringent new SO2 and NOx emission limits on electric generating units. KU met its Phase I SO2 requirements primarily through installation of a scrubber on Ghent Unit 1. KU's strategy for Phase II SO2 reductions, which commenced January 1, 2000, is to use accumulated emissions allowances to delay additional capital expenditures and may also include fuel switching or the installation of additional scrubbers. KU met the NOx emission requirements of the Act through installation of low-NOx burner systems. KU's compliance plans are subject to many factors including developments in the emission allowance and fuel markets, future regulatory and legislative initiatives, and advances in clean air control technology. KU will continue to monitor these developments to ensure that its environmental 89 obligations are met in the most efficient and cost-effective manner. In September 1998, the EPA announced its final "NOx SIP Call" rule requiring states to impose significant additional reductions in NOx emissions by May 2003, in order to mitigate alleged ozone transport impacts on the Northeast region. The Commonwealth of Kentucky is currently in the process of revising its State Implementation Plan or "SIP" to require reductions in NOx emissions from coal-fired generating units to the 0.15 lb./Mmbtu level on a system-wide basis. In related proceedings in response to petitions filed by various Northeast states, in December 1999, EPA issued a final rule pursuant to Section 126 of the Clean Air Act directing similar NOx reductions from a number of specifically targeted generating units including all KU units in the eastern half of Kentucky. Additional petitions currently pending before EPA may potentially result in rules encompassing KU's remaining generating units. Both rules were appealed to the U.S. Court of Appeals for the D.C. Circuit. The D.C. Circuit subsequently upheld most provisions of the NOx SIP Call rule, but extended the compliance date to May, 2004. As the court has yet to issue a final ruling on the Section 126 rule, all KU generating units, except for KU's Green River generating station, remain subject to the May 2003 compliance date under that rule. As KU's Green River station is not covered by the Section 126 rule, those facilities are subject to the May 2004 compliance date as extended by the D.C. Circuit. KU continues to monitor the status of various appeals pending in the D.C. Circuit and U.S. Supreme Court. KU is currently implementing a plan for adding significant additional NOx controls to its generating units. Installation of additional NOx controls will proceed on a phased basis, with installation of controls commencing in late 2000 and continuing through the final compliance date. KU estimates that it will incur total capital costs of approximately $195 million to reduce its NOx emissions to the 0.15 lb./Mmbtu level on a company-wide basis. In addition, KU will incur additional operation and maintenance costs in operating new NOx controls. KU believes its costs in this regard to be comparable to those of similarly situated utilities with like generation assets. KU anticipates that such capital and operating costs are the type of costs that are eligible for recovery from customers under its environmental surcharge mechanism and believes that a significant portion of such costs could be recovered. However, Kentucky Commission approval is necessary and there can be no guarantee of recovery. KU is also addressing other air quality issues. First, KU is monitoring the status of EPA's revised NAAQS for ozone and particulate matter. In May 1999, the Washington D.C. Circuit remanded the final rule and directed EPA to undertake additional rulemaking efforts. KU continues to monitor EPA actions to challenge that ruling. KU owns or formerly owned several properties which contained past MGP operations. Various contaminants are typically found at such former MGP sites and environmental remediation measures are frequently required. KU has completed the cleanup of a site owned by KU. With respect to other former MGP sites no longer owned by KU, KU is unaware of what, if any, additional exposure or liability it may have. In October 1999, approximately 38,000 gallons of diesel fuel leaked from a cracked valve in an underground pipeline at KU's E.W. Brown Station. Under the oversight of EPA and state officials, KU commenced immediate spill containment and recovery measures which prevented the spill from reaching the Kentucky River. KU ultimately recovered approximately 34,000 gallons of diesel fuel. In November 1999, the Kentucky Division of Water issued a notice of violation for the incident. KU is currently negotiating with the state in an effort to reach a complete resolution of this matter. KU expects to incur costs of approximately $1.5 million. PURCHASED POWER. KU has purchase power arrangements with OMU, EEI and other parties. Under the OMU agreement, which expires on January 1, 2020, KU purchases all of the output of a 400-Mw generating station not required by OMU. The amount of purchased power available to KU during 2001-2005, which is expected to be approximately 10% of KU's total kWh requirements, is dependent upon a number of factors including the units' availability, maintenance schedules, fuel costs and OMU requirements. Payments are based on the total 90 costs of the station allocated per terms of the OMU agreement, which generally follows delivered kWh. Included in the total costs is KU's proportionate share of debt service requirements on $164 million of OMU bonds outstanding at December 31, 2000. The debt service is allocated to KU based on its annual allocated share of capacity, which averaged approximately 46% in 2000. KU has a 20% equity ownership in EEI, which is accounted for on the equity method of accounting. KU's entitlement is 20% of the available capacity of a 1,000 Mw station. Payments are based on the total costs of the station allocated per terms of an agreement among the owners, which generally follows delivered kWh. KU has several other contracts for purchased power during 2001 - 2005 of various Mw capacities and for varying periods with a maximum entitlement at any time of 62 Mw. The estimated future minimum annual payments under purchased power agreements for the five years ended December 31, 2005, are as follows (in thousands of $): 2001 $ 31,545 2002 30,683 2003 30,946 2004 31,155 2005 31,310 -------- Total $155,639 ========
NOTE 12 - JOINTLY OWNED ELECTRIC UTILITY PLANT In July 1999, following approval from the Kentucky Commission, KU purchased for $76.7 million a 62% interest in two 164.5 Mw natural gas turbines installed at the E.W. Brown facility (Units 6 and 7) from Capital Corp. See also Note 11, Construction Program, for KU's purchase of two jointly owned CTs in 2001. NOTE 13 - SELECTED QUARTERLY DATA (UNAUDITED) Selected financial data for the four quarters of 2000 and 1999 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 ----- ---- --------- -------- (Thousands of $) 2000 Revenues $217,778 $205,324 $215,984 $212,855 Operating income 28,753 28,912 37,161 33,310 Net income 20,174 21,532 28,483 25,335 Net income available for common stock 19,610 20,968 27,919 24,771 1999 Revenues $217,349 $225,794 $281,503 $212,664 Operating income 36,966 34,997 32,529 31,524 Net income (loss) 29,628 27,757 24,426 24,747 Net income (loss) available for common stock 29,064 27,193 23,862 24,183
91 NOTE 14 - SUBSEQUENT EVENTS On January 9, 2001, LG&E Energy announced a voluntary workforce separation program for non-union employees. On January 18, 2001, the union members at KU voted to approve a similar voluntary separation package. KU targeted areas where reductions were necessary and employees in these targeted areas had a one-time opportunity to accept the separation package. Employees began leaving KU at the end of February 2001 and will continue through the end of the year. KU estimates that the separation program will result in a workforce reduction of approximately 250 employees. On February 1, 2001, Roger Hale, Chairman of the Board and Chief Executive Officer announced his retirement from LG&E Energy, LG&E, and KU effective April 30, 2001. Victor A. Staffieri will replace Roger Hale as Chairman and Chief Executive Officer of LG&E Energy, LG&E, and KU. On February 6, 2001, KU sold accounts receivables to a wholly-owned special purpose subsidiary. Simultaneously, the subsidiary entered into three-year accounts receivables securitization facilities with two financial institutions whereby an undivided interest in certain receivables are sold, on a revolving basis, for up to $50 million, at a cost of funds linked to commercial paper rates. Under the program, KU pays fees for administrative and credit support services. 92 Kentucky Utilities Company REPORT OF MANAGEMENT The management of Kentucky Utilities 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. KU's financial statements have been audited by Arthur Andersen LLP, independent public accountants. Management has made available to Arthur Andersen LLP all KU'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 KU'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, 2000, did not identify any material weaknesses in the design and operation of KU'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 KU, the Audit Committee meets regularly with KU'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. Kentucky Utilities 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. 93 Kentucky Utilities Company REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Shareholders of Kentucky Utilities Company: We have audited the accompanying balance sheets and statements of capitalization of Kentucky Utilities Company (a Kentucky and Virginia corporation and a wholly-owned subsidiary of LG&E Energy Corp.) as of December 31, 2000 and 1999, and the related statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 2000. These financial statements are the responsibility of KU's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. 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 Kentucky Utilities Company as of December 31, 2000 and 1999, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States. 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 the audit 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 26, 2001 (Except with respect to the matters discussed in Note 14, as to which the date is February 6, 2001.) 94 ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. None. PART III ITEMS 10, 11, 12 and 13 are omitted pursuant to General Instruction G of Form 10-K. The information required by ITEMS 10, 11, 12 and 13 for LG&E and KU are incorporated herein by reference to their definitive proxy statements anticipated to be filed during April 2001 with the Commission pursuant to Regulation 14A of the Securities and Exchange Act of 1934. Additionally, in accordance with General Instruction G, the information required by ITEM 10 relating to executive officers of LG&E and KU has been included in Part I of this Form 10-K. PART IV ITEM 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K. (a) 1. Financial Statements (included in Item 8): LG&E: Statements of income for the three years ended December 31, 2000 (page 49). Statements of retained earnings for the three years ended December 31, 2000 (page 49). Statements of comprehensive income for the three years ended December 31, 2000 (page 50). Balance sheets - December 31, 2000, and 1999 (page 51). Statements of cash flows for the three years ended December 31, 2000 (page 52). Statements of capitalization - December 31, 2000, and 1999 (page 53). Notes to financial statements (pages 54-71). Report of management (page 72). Report of independent public accountants (page 73). KU: Statements of income for the three years ended December 31, 2000 (page 74). Statements of retained earnings for the three years ended December 31, 2000 (page 74). Balance sheets - December 31, 2000, and 1999 (page 75). Statements of cash flows for the three years ended December 31, 2000 (page 76). Statements of capitalization - December 31, 2000, and 1999 (page 77). Notes to financial statements (pages 78-92). Report of management (page 93). Report of independent public accountants (page 94). 2. Financial Statement Schedules (included in Part IV): Schedule II Valuation and Qualifying Accounts for the three years ended December 31, 2000, for LG&E (page 114), and KU (page 115). 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. 95 3. Exhibits: Exhibit Applicable to Form 10-K of No. LG&E KU Description --- ---- -- ----------- 2.01 x x Copy of Agreement and Plan of Merger, dated as of February 27, 2000, by and among Powergen plc, LG&E Energy Corp., US Subholdco2 and Merger Sub, including certain exhibits thereto. [Filed as Exhibit 1 to LG&E's and KU's Current Report on Form 8-K filed February 29, 2000 and incorporated by reference herein] 2.02 x x Amendment No. 1 to Agreement and Plan of Merger, dated as of December 8, 2000, among LG&E Energy Corp., Powergen plc, Powergen US Investments Corp. and Powergen Acquisition Corp. [Filed as Exhibit 2.01 to LG&E's and KU's Current Report on Form 8-K filed December 11, 2000 and incorporated by reference herein] 2.03 x x Copy of Agreement and Plan of Merger, dated as of May 20, 1997, by and between LG&E Energy and KU Energy, including certain exhibits thereto. [Filed as Exhibit 2 to LG&E's and KU's Current Report on Form 8-K filed May 30, 1997 and incorporated by reference herein] 3.01 x Copy of Restated Articles of Incorporation of LG&E, dated November 6, 1996. [Filed as Exhibit 3.06 to LG&E's Quarterly Report on Form 10-Q for the quarter ended September 30, 1996, and incorporated by reference herein] 3.02 x Copy of By-Laws of LG&E, as amended through June 2, 1999. [Filed as Exhibit 3.02 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1999 and incorporated by reference herein.] 3.03 x Copy of Amended and Restated Articles of Incorporation of KU [Filed as Exhibits 4.03 and 4.04 to Form 8-K Current Report of KU, dated December 10, 1993, and incorporated by reference herein] 3.04 x Copy of By-laws of KU, as amended through June 2, 1999. [Filed as Exhibit 3.04 to KU's Annual Report on Form 10-K for the year ended December 31, 1999 and incorporated by reference herein.] 4.01 x Copy of Trust Indenture dated November 1, 1949, from LG&E to Harris Trust and Savings Bank, Trustee. [Filed as Exhibit 7.01 to LG&E's Registration Statement 2-8283 and incorporated by reference herein] 4.02 x Copy of Supplemental Indenture dated February 1, 1952, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.05 to LG&E's Registration Statement 2-9371 and incorporated by reference herein] 4.03 x Copy of Supplemental Indenture dated February 1, 1954, which is a 96 supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.03 to LG&E's Registration Statement 2-11923 and incorporated by reference herein] 4.04 x Copy of Supplemental Indenture dated September 1, 1957, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.04 to LG&E's Registration Statement 2-17047 and incorporated by reference herein] 4.05 x Copy of Supplemental Indenture dated October 1, 1960, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.05 to LG&E's Registration Statement 2-24920 and incorporated by reference herein] 4.06 x Copy of Supplemental Indenture dated June 1, 1966, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.06 to LG&E's Registration Statement 2-28865 and incorporated by reference herein] 4.07 x Copy of Supplemental Indenture dated June 1, 1968, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.07 to LG&E's Registration Statement 2-37368 and incorporated by reference herein] 4.08 x Copy of Supplemental Indenture dated June 1, 1970, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.08 to LG&E's Registration Statement 2-37368 and incorporated by reference herein] 4.09 x Copy of Supplemental Indenture dated August 1, 1971, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.09 to LG&E's Registration Statement 2-44295 and incorporated by reference herein] 4.10 x Copy of Supplemental Indenture dated June 1, 1972, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.10 to LG&E's Registration Statement 2-52643 and incorporated by reference herein] 4.11 x Copy of Supplemental Indenture dated February 1, 1975, which is a supplemental instrument to exhibit 4.01 hereto. [Filed as Exhibit 2.11 to LG&E's Registration Statement 2-57252 and incorporated by reference herein] 97 4.12 x Copy of Supplemental Indenture dated September 1, 1975, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.12 to LG&E's Registration Statement 2-57252 and incorporated by reference herein] 4.13 x Copy of Supplemental Indenture dated September 1, 1976, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.13 to LG&E's Registration Statement 2-57252 and incorporated by reference herein] 4.14 x Copy of Supplemental Indenture dated October 1, 1976, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.14 to LG&E's Registration Statement 2-65271 and incorporated by reference herein] 4.15 x Copy of Supplemental Indenture dated June 1, 1978, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.15 to LG&E's Registration Statement 2-65271 and incorporated by reference herein] 4.16 x Copy of Supplemental Indenture dated February 15, 1979, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.16 to LG&E's Registration Statement 2-65271 and incorporated by reference herein] 4.17 x Copy of Supplemental Indenture dated September 1, 1979, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.17 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1980, and incorporated by reference herein] 4.18 x Copy of Supplemental Indenture dated September 15, 1979, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.18 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1980, and incorporated by reference herein] 4.19 x Copy of Supplemental Indenture dated September 15, 1981, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.19 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1981, and incorporated by reference herein] 4.20 x Copy of Supplemental Indenture dated March 1, 1982, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.20 to 98 LG&E's Annual Report on Form 10-K for the year ended December 31, 1982, and incorporated by reference herein] 4.21 x Copy of Supplemental Indenture dated March 15, 1982, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.21 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1982, and incorporated by reference herein] 4.22 x Copy of Supplemental Indenture dated September 15, 1982, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.22 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1982, and incorporated by reference herein] 4.23 x Copy of Supplemental Indenture dated February 15, 1984, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.23 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1984, and incorporated by reference herein] 4.24 x Copy of Supplemental Indenture dated July 1, 1985, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.24 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1985, and incorporated by reference herein] 4.25 x Copy of Supplemental Indenture dated November 15, 1986, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.25 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1986, and incorporated by reference herein] 4.26 x Copy of Supplemental Indenture dated November 16, 1986, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.26 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1986, and incorporated by reference herein] 4.27 x Copy of Supplemental Indenture dated August 1, 1987, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.27 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1987, and incorporated by reference herein] 4.28 x Copy of Supplemental Indenture dated February 1, 1989, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.28 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1988, and incorporated by reference herein] 99 4.29 x Copy of Supplemental Indenture dated February 2, 1989, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.29 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1988, and incorporated by reference herein] 4.30 x Copy of Supplemental Indenture dated June 15, 1990, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.30 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1990, and incorporated by reference herein] 4.31 x Copy of Supplemental Indenture dated November 1, 1990, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.31 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1990, and incorporated by reference herein] 4.32 x Copy of Supplemental Indenture dated September 1, 1992, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.32 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein] 4.33 x Copy of Supplemental Indenture dated September 2, 1992, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.33 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein] 4.34 x Copy of Supplemental Indenture dated August 15, 1993, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.34 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein] 4.35 x Copy of Supplemental Indenture dated August 16, 1993, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.35 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein] 4.36 x Copy of Supplemental Indenture dated October 15, 1993, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.36 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein] 4.37 x Copy of Supplemental Indenture dated May 1, 2000, which is a supplemental instrument to Exhibit 4.01 hereto. [To be filed by amendment.] 100 4.38 x Copy of Supplemental Indenture dated August 1, 2000, which is a supplemental instrument to Exhibit 4.01 hereto. [To be filed by amendment.] 4.39 x Indenture of Mortgage or Deed of Trust dated May 1, 1947, between KU and First Trust National Association (successor Trustee) and a successor individual co-trustee, as Trustees (the Trustees) (Amended Exhibit 7(a) in File No. 2-7061), and Supplemental Indentures thereto dated, respectively, January 1, 1949 (Second Amended Exhibit 7.02 in File No. 2-7802), July 1, 1950 (Amended Exhibit 7.02 in File No. 2-8499), June 15, 1951 (Exhibit 7.02(a) in File No. 2-8499), June 1, 1952 (Amended Exhibit 4.02 in File No. 2-9658), April 1, 1953 (Amended Exhibit 4.02 in File No. 2-10120), April 1, 1955 (Amended Exhibit 4.02 in File No. 2-11476), April 1, 1956 (Amended Exhibit 2.02 in File No. 2-12322), May 1, 1969 (Amended Exhibit 2.02 in File No. 2-32602), April 1, 1970 (Amended Exhibit 2.02 in File No. 2-36410), September 1, 1971 (Amended Exhibit 2.02 in File No. 2-41467), December 1, 1972 (Amended Exhibit 2.02 in File No. 2-46161), April 1, 1974 (Amended Exhibit 2.02 in File No. 2-50344), September 1, 1974 (Exhibit 2.04 in File No. 2-59328), July 1, 1975 (Exhibit 2.05 in File No. 2-59328), May 15, 1976 (Amended Exhibit 2.02 in File No. 2-56126), April 15, 1977 (Exhibit 2.06 in File No. 2-59328), August 1, 1979 (Exhibit 2.04 in File No. 2-64969), May 1, 1980 (Exhibit 2 to Form 10-Q Quarterly Report of KU for the quarter ended June 30, 1980), September 15, 1982 (Exhibit 4.04 in File No. 2-79891), August 1, 1984 (Exhibit 4B to Form 10-K Annual Report of KU for the year ended December 31, 1984), June 1, 1985 (Exhibit 4 to Form 10-Q Quarterly Report of KU for the quarter ended June 30, 1985), May 1, 1990 (Exhibit 4 to Form 10-Q Quarterly Report of KU for the quarter ended June 30, 1990), May 1, 1991 (Exhibit 4 to Form 10-Q Quarterly Report of KU for the quarter ended June 30, 1991), May 15, 1992 (Exhibit 4.02 to Form 8-K of KU dated May 14, 1992), August 1, 1992 (Exhibit 4 to Form 10-Q Quarterly Report of KU for the quarter ended September 30, 1992), June 15, 1993 (Exhibit 4.02 to Form 8-K of KU dated June 15, 1993) and December 1, 1993 (Exhibit 4.01 to Form 8-K of KU dated December 10, 1993), November 1, 1994 (Exhibit 4.C to Form 10-K Annual Report of KU for the year ended December 31, 1994), June 1, 1995 (Exhibit 4 to Form 10-Q Quarterly Report of KU for the quarter ended June 30, 1995) and January 15, 1996 (Exhibit 4.E to Form 10-K Annual Report of KU for the year ended December 31, 1995). Incorporated by reference. 4.40 x Supplemental Indenture dated March 1, 1992 between KU and the Trustees, providing for the conveyance of properties formerly held by Old Dominion Power Company [Filed as Exhibit 4B to Form 10-K Annual 101 Report of KU for the year ended December 31, 1992, and incorporated by reference herein] 4.41 x Copy of Supplemental Indenture dated May 1, 2000, which is a supplemental instrument to Exhibit 4.39 hereto. [To be filed by amendment.] 10.01 x 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 LG&E's Registration Statement 2-9975 and incorporated by reference herein] 10.02 x 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 LG&E's Registration Statement 2-24920 and incorporated by reference herein] 10.03 x Copy of Modification No. 2 dated March 15, 1964, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 5.02c to LG&E's Registration Statement 2-61607 and incorporated by reference herein] 10.04 x 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 LG&E's Registration Statement 2-26063 and incorporated by reference herein] 10.05 x 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 LG&E's Registration Statement 2-27316 and incorporated by reference herein] 10.06 x x 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 102 Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies; (iv) Inter-Company Bank Credit Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 5.02f to LG&E's Registration Statement 2-61607 and incorporated by reference herein] 10.07 x x 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 LG&E's Registration Statement 2-26063 and incorporated by reference herein] 10.08 x Copies of Amendments to Agreements (iii) and (iv) referred to under 10.06 above as follows: (i) Amendment to Inter-Company Bond Agreement and (ii) Amendment to Inter-Company Bank Credit Agreement. [Filed as Exhibit 5.02h to LG&E's Registration Statement 2-61607 and incorporated by reference herein] 10.09 x Copy of Modification No. 1, dated August 20, 1958, to First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 5.02i to LG&E's Registration Statement 2-61607 and incorporated by reference herein] 10.10 x Copy of Modification No. 2, dated April 1, 1965, to the First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 5.02j to LG&E's Registration Statement 2-61607 and incorporated by reference herein] 10.11 x Copy of Modification No. 3, dated January 20, 1967, to First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 4(a)(7) to LG&E's Registration Statement 2-26063 and incorporated by reference herein] 10.12 x 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 LG&E's Registration Statement 2-28524 and incorporated by reference herein] 10.13 x x Copy of Modification No. 3 dated November 15, 1967, to the Inter-Company Power Agreement dated July 10, 1953. [Filed as Exhibit 4.02m to LG&E's Registration Statement 2-37368 and incorporated by reference 103 herein] 10.14 x Copy of Modification No. 7 dated November 5, 1975, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 5.02n to LG&E's Registration Statement 2-56357 and incorporated by reference herein] 10.15 x x Copy of Modification No. 4 dated November 5, 1975, to the Inter-Company Power Agreement dated July 10, 1953. [Filed as Exhibit 5.02o to LG&E's Registration Statement 2-56357 and incorporated by reference herein] 10.16 x Copy of Modification No. 4 dated April 30, 1976, to First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 5.02p to LG&E's Registration Statement 2-61607 and incorporated by reference herein] 10.17 x Copy of Modification No. 8 dated June 23, 1977, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 5.02q to LG&E's Registration Statement 2-61607 and incorporated by reference herein] 10.18 x Copy of Modification No. 9 dated July 1, 1978, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 5.02r to LG&E's Registration Statement 2-63149 and incorporated by reference herein] 10.19 x 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 LG&E's Annual Report on Form 10-K for the year ended December 31, 1979, and incorporated by reference herein] 10.20 x 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 LG&E's Annual Report on Form 10-K for the year ended December 31, 1979, and incorporated by reference herein] 10.21 x x Copy of Modification No. 5 dated September 1, 1979, to Inter-Company Power Agreement dated July 5, 1953, among Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 4 to LG&E's 104 Annual Report on Form 10-K for the year ended December 31, 1979, and incorporated by reference herein] 10.22 x 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 LG&E's Annual Report on Form 10-K for the year ended December 31, 1981, and incorporated by reference herein] 10.23 x x Copy of Modification No. 6 dated August 1, 1981, to Inter-Company Power Agreement dated July 5, 1953, among Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 10.26 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1981, and incorporated by reference herein] 10.24 [Not used.] 10.25 x * Copy of Supplemental Executive Retirement Plan for R. W. Hale, effective June 1, 1989. [Filed as Exhibit 10.42 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein] 10.26 x * Copy of Nonqualified Savings Plan covering officers of the Company, effective January 1, 1992. [Filed as Exhibit 10.43 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein] 10.27 x 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 LG&E's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein] 10.28 x 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 LG&E's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein] 10.29 x x Copy of Modification No. 7 dated January 15, 1992, to Inter-Company Power Agreement dated July 10, 1953, among Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 10.44 to LG&E's Annual Report on Form 10-K for the year ended December 31, 105 1993, and incorporated by reference herein] 10.30 x 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 LG&E's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein] 10.31 x Copy of Firm No Notice Transportation Agreement effective November 1, 1993, between Texas Gas Transmission Corporation and LG&E (expires October 31, 2001) covering the transmission of natural gas. Copy of Firm No Notice Transportation Agreement effective November 1, 1993, between Texas Gas Transmission Corporation and LG&E (expires October 31, 2000) covering the transmission of natural gas. Copy of Firm No Notice Transportation Agreement effective November 1, 1993, between Texas Gas Transmission Corporation and LG&E (expires October 31, 2003) covering the transmission of natural gas. [Filed as Exhibit 10.47 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein] 10.32 [Not used.] 10.33 x x Copy of Modification No. 8 dated January 19, 1994, to Intercompany Power Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 10.43 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein] 10.34 x Copy of Amendment dated March 1, 1995, to Firm No-Notice Transportation Agreements dated November 1, 1993 (2-Year, 5-Year and 8-Year), between Texas Gas Transmission Corporation and LG&E covering the transmission of natural gas. [Filed as Exhibit 10.44 of LG&E's Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein] 10.35 x x Copy of Modification No. 9, dated August 17, 1995, to the Inter-Company Power Agreement dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 10.39 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1996, and incorporated by reference herein] 106 10.36 x Copy of Agreement and Plan of Merger, dated February 10, 1995, between LG&E Natural Inc., formerly known as Hadson Corporation, Carousel Acquisition Corporation and the Company. [Filed as Exhibit 2 of Schedule 13D by the Company on February 21, 1995, and incorporated by reference herein] 10.37 x Copy of Firm Transportation Agreement, dated March 1, 1995, between Texas Gas Transmission Corporation and LG&E (expires October 31, 2003) covering the transportation of natural gas. Copy of Firm Transportation Agreement, dated March 1, 1995, between Texas Gas Transmission Corporation and LG&E (expires October 31, 2001) covering the transportation of natural gas. [Filed as Exhibit 10.45 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein] 10.38 x Copy of Firm Transportation Agreement, dated March 1, 1995, between Texas Gas Transmission Corporation and LG&E (expires October 31, 2000) covering the transportation of natural gas [Filed as Exhibit 10.41 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1996, and incorporated by reference herein] 10.39 [Not used.] 10.40 [Not used.] 10.41 x * Copy of Amendment to the Non-Qualified Savings Plan, effective January 1, 1992. [Filed as Exhibit 10.55 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein] 10.42 x * Copy of Amendment to the Non-Qualified Savings Plan, effective January 1, 1995. [Filed as Exhibit 10.56 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein] 10.43 x * Copy of Amendment to the Non-Qualified Savings Plan, effective January 1, 1995. [Filed as Exhibit 10.57 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein] 10.44 x Copy of Form of Master Gas Purchase Agreement, dated December 14, 107 1993, among Santa Fe, SFEOP and AGPC. [Filed as Exhibit 10.23 to LG&E Natural Inc.'s, formerly known as Hadson Corporation, Registration Statement on Form S-4, File No. 33-68224, and incorporated by reference herein] 10.45 x Copy of Credit Agreement, dated as of December 18, 1995, among LG&E, as Borrower, the Banks named therein, PNC Bank, Kentucky, Inc. as Agent and Bank of Montreal as Co-Agent. [Filed as Exhibit 10.01 to the LG&E's Quarterly Report on Form 10-Q/A for the quarter ended March 31, 1996, and incorporated by reference herein] 10.46 x Copy of Firm Transportation Agreement, dated November 1, 1996, between LG&E and Tennessee Gas Pipeline Company for 30,000 Mmbtu per day in Firm Transportation Service under Tennessee's Rate FT-A (expires October 31, 2001). [Filed as Exhibit 10.42 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1996, and incorporated by reference herein] 10.47 x Copy of Amendment No. 1, dated as of November 5, 1996, to Credit Agreement dated as of December 18, 1995, by and among Louisville Gas and Electric Company, the Banks party thereto, and PNC Bank, Kentucky, Inc. as Agent and Bank of Montreal as Co-Agent. [Filed as Exhibit 10.59 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1996, and incorporated by reference herein] 10.48 - [Not used.] 10.55 10.56 x * Copy of LG&E Energy Corp. and Louisville Gas and Electric Company Non-Officer Senior Management Pension Restoration Plan, effective May 1, 1996. [Filed as Exhibit 10.69 to LG&E Energy's Annual Report on Form 10-K for the year ended December 31, 1996, and incorporated by reference herein] 10.57 - [Not used.] 10.58 10.59 x x * Copy of Supplemental Executive Retirement Plan as amended through January 1, 1998, covering officers of LG&E Energy. [Filed as Exhibit 10.74 to LG&E Energy's Annual Report on Form 10-K for the year ended December 31, 1997, and incorporated by reference herein] 10.60 [Not used.] 108 10.61 x Copy of Coal Supply Agreement between LG&E and Kindill Mining, Inc., dated July 1, 1997. [Filed as Exhibit 10.76 to LG&E Energy's Annual Report on Form 10-K for the year ended December 31, 1997, and incorporated by reference herein] 10.62 x Copy of Coal Supply Agreement between LG&E and Warrior Coal Corp. dated January 1, 1997, and Amendments #1 and #2 dated May 1, 1997, and December 1, 1997, thereto. [Filed as Exhibit 10.79 to LG&E Energy's Annual Report on Form 10-K for the year ended December 31, 1997, and incorporated by reference herein] 10.63 x Copies of Amendments dated September 23, 1997, to Firm No-Notice Transportation Agreements dated November 1, 1993, between Texas Gas Transmission Corporation and LG&E, as amended. [Filed as Exhibit 10.81 to LG&E Energy's Annual Report on Form 10-K for the year ended December 31, 1997, and incorporated by reference herein] 10.64 x Copies of Amendments dated September 23, 1997, to Firm Transportation Agreements dated March 1, 1995, between Texas Gas Transmission Corporation and LG&E, as amended. [Filed as Exhibit 10.82 to LG&E Energy's Annual Report on Form 10-K for the year ended December 31, 1997, and incorporated by reference herein] 10.65 x Copy of Gas Transportation Agreement dated November 1, 1996, between Tennessee Gas Pipeline Company and LG&E and amendments dated February 4, 1997, thereto. [Filed as Exhibit 10.83 to LG&E Energy's Annual Report on Form 10-K for the year ended December 31, 1997, and incorporated by reference herein] [Certain portions of this exhibit have been omitted pursuant to a confidential treatment request filed with the Securities and Exchange Commission] 10.66 - [Not used.] 10.75 10.76 x Copy of Amended and Restated Coal Supply Agreement dated April 1, 1998 between LG&E and Hopkins County Coal LLC. [Filed as Exhibit 10.76 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1998 and incorporated by reference herein] 10.77 x Copy of Coal Supply Agreement dated January 1, 1999 between LG&E and Peabody COALSALES Company. [Filed as Exhibit 10.77 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1998 and 109 incorporated by reference herein] 10.78 [Not used.] 10.79 [Not used.] 10.80 x Copy of Assignment and Assumption Agreement dated November 16, 1998 between KU, Leslie Resources, Inc. and AEI Coal Sales Company, Inc. regarding Coal Supply Agreement dated December 31, 1997. [Filed as Exhibit 10.80 to KU's Annual Report on Form 10-K for the year ended December 31, 1998 and incorporated by reference herein] 10.81 x Copy of Coal Supply Agreement dated April 1, 1995 between KU and Consolidation Coal Company, Quarto Mining Company, McElroy Coal Company, Consol Pennsylvania Coal Company, Greenon Coal Company and Nineveh Coal Company. [Filed as Exhibit 10.81 to KU's Annual Report on Form 10-K for the year ended December 31, 1998 and incorporated by reference herein] 10.82 x Copy of Amendment to Coal Supply Agreement dated October 1, 1996 between KU and Consolidation Coal Company, Quarto Mining Company, McElroy Coal Company, Consol Pennsylvania Coal Company, Greenon Coal Company and Nineveh Coal Company regarding Coal Supply Agreement dated April 1, 1995. [Filed as Exhibit 10.82 to KU's Annual Report on Form 10-K for the year ended December 31, 1998 and incorporated by reference herein] 10.83 - [Not used.] 10.89 10.90 x x * Copy of Amendment to LG&E Energy's Supplemental Executive Retirement Plan, effective September 2, 1998. [Filed as Exhibit 10.90 to LG&E Energy's Annual Report on Form 10-K for the year ended December 31, 1998 and incorporated by reference herein] 10.91 x x * Copy of Amendment effective September 2, 1998 to Supplemental Executive Retirement Plan for R. W. Hale effective June 1, 1989. [Filed as Exhibit 10.91 to LG&E Energy's Annual Report on Form 10-K for the year ended December 31, 1998 and incorporated by reference herein] 10.92 [Not used.] 10.93 x x * Copy of Employment Agreement, dated as of February 25, 2000, by and among LG&E Energy, Powergen plc and Roger W. Hale. [Filed as Exhibit 1 to Appendix A of LG&E Energy's Preliminary Proxy Statement on Schedule 14A on March 13, 2000 and incorporated by reference herein] 110 10.94 x x * Copy of form of Employment and Severance Agreement, dated as of February 25, 2000, by and among LG&E Energy, Powergen plc and certain executive officers of the Company. [Filed as Exhibit 10.94 to LG&E's and KU's Annual Report on Form 10-K for the year ended December 31, 1999 and incorporated herein by reference.] 10.95 x x * Copy of form of First Amendment to Employment and Severance Agreement by and among LG&E Energy, Powergen plc and certain executive officers of the Company. [To be filed by amendment.] 10.96 x x * Copy of Amendment, effective October 1, 1999, to LG&E Energy's Non-Qualified Savings Plan. [Filed as Exhibit 10.96 to LG&E's and KU's Annual Report on Form 10-K for the year ended December 31, 1999 and incorporated herein by reference.] 10.97 x x * Copy of Amendment, effective December 1, 1999, to LG&E Energy's Non-Qualified Savings Plan. [Filed as Exhibit 10.97 to LG&E's and KU's Annual Report on Form 10-K for the year ended December 31, 1999 and incorporated herein by reference.] 10.98 - [Not used.] 10.101 10.102 x x Copy of Modification No. 10., dated January 1, 1998, to the Inter-Company Power Agreement dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 10.102 to LG&E's and KU's Annual Report on Form 10-K for the year ended December 31, 1999 and incorporated herein by reference.] 10.103 x x Copy of Modification No. 11, dated April 1, 1999, to the Inter-Company Power Agreement dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 10.103 to LG&E's and KU's Annual Report on Form 10-K for the year ended December 31, 1999 and incorporated herein by reference.] 10.104 x Copy of Amendment No. 1, dated January 1, 2000, to Amended and Restated Coal Supply Agreement, dated April 1, 1998, among LG&E, Hopkins County Coal, LLC and Webster County Coal, LLC. [Filed as Exhibit 10.104 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1999 and incorporated herein by reference.] 10.105 x Copy of Amendment No. 1, dated January 1, 2000, to Coal Supply Contract, dated January 1, 1999, between LG&E and Peabody CoalSales Company. [Filed as Exhibit 10.105 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1999 and incorporated herein by reference.] 10.106 x Copy of Letter Amendment, dated September 15, 1999, to Transportation Agreement, dated November 1, 1993, between LG&E and Texas Gas Transmission Corporation. [Filed as Exhibit 10.106 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1999 and incorporated herein by reference.] 10.107 x x * Copy of Powergen Long-Term Incentive Plan, effective December 11, 2000, applicable to certain employees of LG&E Energy Corp. and its subsidiaries. [To be filed by amendment.] 10.108 x x * Copy of Powergen Long-Term Incentive Plan - Roger Hale, effective December 11, 2000. [To be filed by amendment.] 10.109 x x * Copy of Powergen Short-Term Incentive Plan, effective January 1, 2001, applicable to certain employees of LG&E Energy Corp. and its subsidiaries. [To be filed by amendment.] 10.110 x x * Copy of two forms of Change-In-Control Agreement applicable to certain employees of LG&E Energy Corp. and its subsidiaries. [To be filed by amendment.] 12 x x Computation of Ratio of Earnings to Fixed Charges for LG&E and KU. 21 x x Subsidiaries of the Registrant. 23.01 x Consent of Independent Public Accountants for LG&E. 23.02 x Consent of Independent Public Accountants for KU. 111 24 x x Power of Attorney. 99.01 x x Cautionary Statement for purposes of the "Safe Harbor" provisions of the Private Securities Litigation Reform Act of 1995. (b) Executive Compensation Plans and Arrangements: Exhibits preceded by an asterisk ("*") above are management contracts, compensation plans or arrangements required to be filed as an exhibit pursuant to Item 14(c) of Form 10-K. (c) Reports on Form 8-K: On December 11, 2000, a report on Form 8-K was filed announcing that LG&E Energy and Powergen had completed the merger involving the two companies. (d) The following instruments defining the rights of holders of certain long- term debt of KU have not been filed with the Securities and Exchange Commission but will be furnished to the Commission upon request. 1. Loan Agreement dated as of May 1, 1990 between KU and the County of Mercer, Kentucky, in connection with $12,900,000 County of Mercer, Kentucky, Collateralized Solid Waste Disposal Facility Revenue Bonds (KU Project) 1990 Series A, due May 1, 2010 and May 1, 2020. 2. Loan Agreement dated as of May 1, 1991 between KU and the County of Carroll, Kentucky, in connection with $96,000,000 County of Carroll, Kentucky, Collateralized Pollution Control Revenue Bonds (KU Project) 1992 Series A, due September 15, 2016. 3. Loan Agreement dated as of August 1, 1992 between KU and the County of Carroll, Kentucky, in connection with $2,400,000 County of Carroll, Kentucky, Collateralized Pollution Control Revenue Bonds (KU Project) 1992 Series C, due February 1, 2018. 4. Loan Agreement dated as of August 1, 1992 between KU and the County of Muhlenberg, Kentucky, in connection with $7,200,000 County of Muhlenberg, Kentucky, Collateralized Pollution Control Revenue Bonds (KU Project) 1992 Series A, due February 1, 2018. 5. Loan Agreement dated as of August 1, 1992 between KU and the County of Mercer, Kentucky, in connection with $7,400,000 County of Mercer, Kentucky, Collateralized Pollution Control Revenue Bonds (KU Project) 1992 Series A, due February 1, 2018. 112 6. Loan Agreement dated as of August 1, 1992 between KU and the County of Carroll, Kentucky, in connection with $20,930,000 County of Carroll, Kentucky, Collateralized Pollution Control Revenue Bonds (KU Project) 1992 Series B, due February 1, 2018. 7. Loan Agreement dated as of December 1, 1993, between KU and the County of Carroll, Kentucky, in connection with $50,000,000 County of Carroll, Kentucky, Collateralized Solid Waste Disposal Facilities Revenue Bonds (KU Project) 1993 Series A, due December 1, 2023. 8. Loan Agreement dated as of November 1, 1994, between KU and the County of Carroll, Kentucky, in connection with $54,000,000 County of Carroll, Kentucky, Collateralized Solid Waste Disposal Facilities Revenue Bonds (KU Project) 1994 Series A, due November 1, 2024. 113 Louisville Gas and Electric Company Schedule II Schedule II - Valuation and Qualifying Accounts For the Three Years Ended December 31, 2000 (Thousands of $)
Other Accounts Property Receivable and (Uncollectible Investments Accounts) ----------- --------- Balance December 31, 1997 $ 63 $ 1,295 Additions: Charged to costs and expenses - 2,300 Deductions: Net charges of nature for which reserves were created - 2,196 ---------- ------- Balance December 31, 1998 63 1,399 Additions: Charged to costs and expenses - 1,925 Deductions: Net charges of nature for which reserves were created - 2,091 ---------- ------- Balance December 31, 1999 63 1,233 Additions: Charged to costs and expenses - 2,803 Deductions: Net charges of nature for which reserves were created - 2,750 ---------- ------- Balance December 31, 2000 $ 63 $ 1,286 ======== =======
114 Kentucky Utilities Company Schedule II Schedule II - Valuation and Qualifying Accounts For the Three Years Ended December 31, 2000 (Thousands of $)
Other Accounts Property Receivable and (Uncollectible Investments Accounts) ----------- --------- Balance December 31, 1997 $ 345 $ 520 Additions: Charged to costs and expenses 231 1,308 Deductions: Net charges of nature for which reserves were created - 1,308 ---------- ------- Balance December 31, 1998 576 520 Additions: Charged to costs and expenses 111 1,707 Deductions: Net charges of nature for which reserves were created - 1,427 ---------- ------- Balance December 31, 1999 687 800 Additions: Charged to costs and expenses 64 1,430 Deductions: Net charges of nature for which reserves were created - 1,430 ---------- ------- Balance December 31, 2000 $ 751 $ 800 ======= =======
115 SIGNATURES - LOUISVILLE GAS AND ELECTRIC COMPANY 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 30, 2001 /s/ S. Bradford Rives --------------- ---------------------------------- (Date) 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); Richard Aitken-Davies Chief Financial Officer (Principal Financial Officer); S. Bradford Rives Senior Vice President - Finance and Controller (Principal Accounting Officer); Sir Frederick Crawford Director; David J. Jackson Director; Sydney Gillibrand Director; Dr. David K-P Li Director; Paul Myners Director; Roberto Quarta Director; Edmund Wallis Director. By /s/ S. Bradford Rives March 30, 2001 --------------------------- (Attorney-In-Fact) 116 SIGNATURES - KENTUCKY UTILITIES COMPANY 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. KENTUCKY UTILITIES COMPANY Registrant March 30, 2001 /s/ S. Bradford Rives --------------- ----------------------------------- (Date) 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); Richard Aitken-Davies Chief Financial Officer (Principal Financial Officer); S. Bradford Rives Senior Vice President - Finance and Controller (Principal Accounting Officer); Sir Frederick Crawford Director; David J. Jackson Director; Sydney Gillibrand Director; Dr. David K-P Li Director; Paul Myners Director; Roberto Quarta Director; Edmund Wallis Director. By /s/ S. Bradford Rives March 30, 2001 ------------------------- (Attorney-In-Fact) 117