8-K 1 k8k1202.txt LGE AND KU AMENDMENT TO 10K FOR 2002 1 SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 8-K CURRENT REPORT Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 Date of Report (Date of earliest event reported): November 12, 2003 Commission Registrant, State of Incorporation, IRS Employer File Number Address, and Telephone Number Identification No. 2-26720 Louisville Gas and Electric Company 61-0264150 (A Kentucky Corporation) 220 West Main Street P.O. Box 32010 Louisville, Ky. 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 This combined Form 8-K is separately filed by Louisville Gas and Electric Company and Kentucky Utilities Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf and each registrant makes no representation as to information relating to the other registrant. Item 5. Other Events and Regulation FD Disclosure In the Annual Report for the year ended December 31, 2002 on Form 10-K ("2002 Annual Report") Louisville Gas and Electric Company ("LG&E") and Kentucky Utilities Company ("KU") reported revenues and related cost of sales in compliance with required accounting that was in effect at that time. LG&E and KU were required to adopt the net reporting requirements of Emerging Issues Task Force Issue No. 02-03, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities ("EITF 02-03") on January 1, 2003. Therefore, to comply with the net reporting requirements of EITF 02-03, LG&E and KU have reclassified revenues and related expenses previously reported in the 2002 Annual Report. EITF 02-03 rescinded EITF 98-10 and requires that revenue related to derivative instruments classified as trading, including certain energy sales transactions, be reported net of related cost of sales for all periods presented. EITF 02-03 also requires companies to retroactively reclassify previously reported revenues to conform with the new net reporting requirements. LG&E and KU are filing this Current Report on Form 8-K to present reclassified financial statements and other related information in response to the requirements of EITF 02-03. The reclassified financial statements are set forth in the attached exhibits to this Form 8-K. These exhibits contain information identical to the corresponding items of the 2002 Annual Report, except that the information contained in the exhibits has been updated to the extent necessary to report energy- trading contracts net of related cost of sales in the income statements for all periods presented. Accordingly, information in the corresponding items in the Companies' 2002 Annual Report should be considered in light of the updated information for such items as provided in this Current Report, which reflects the reclassification of financial data as explained above. No attempt has been made in this report to modify or update other disclosures except as required to reflect the effects of the reclassifications described above. These other disclosures are included in our annual, quarterly and current reports and other information filed with the SEC. Neither reported net operating income, net income, common equity, nor cash flows were impacted by the reclassification of revenue upon adoption of EITF 02-03. The Companies' 2000 consolidated financial statements were audited by Arthur Andersen LLP, independent public accountants, who expressed an unqualified opinion on those financial statements in their report dated January 26, 2001, excluding the revisions described above. Arthur Andersen LLP has ceased operations and, accordingly, LG&E and KU have been unable to obtain their consent to the use of their report. Therefore, 2000 consolidated financial statements, as reclassified, are omitted. The following are defined terms used in the Exhibits: Abbreviation or Acronym Definition Capital Corp. LG&E Capital Corp. Clean Air Act The Clean Air Act, as amended in 1990 CCN 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 E.ON E.ON AG EPA U.S. Environmental Protection Agency ESM Earnings Sharing Mechanism F Fahrenheit FAC Fuel Adjustment Clause FERC Federal Energy Regulatory Commission Page 3 FPA Federal Power Act FT and FT-A Firm Transportation GSC Gas Supply Clause 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 KU R KU Receivables LLC kV Kilovolts Kva Kilovolt-ampere KW Kilowatts Kwh Kilowatt hours LEM LG&E Energy Marketing Inc. LG&E Louisville Gas and Electric Company LG&E Energy LG&E Energy Corp. LG&E R LG&E Receivables LLC LG&E Services LG&E Energy Services Inc. Mcf Thousand Cubic Feet MGP Manufactured Gas Plant MISO Midwest Independent System Operator Mmbtu Million British thermal units Moody's Moody's Investor Services, Inc. Mw Megawatts Mwh Megawatt hours NNS No-Notice Service NOPR Notice of Proposed Rulemaking NOx Nitrogen Oxide OATT Open Access Transmission Tariff OMU Owensboro Municipal Utilities OVEC Ohio Valley Electric Corporation PBR Performance-Based Ratemaking PJM Pennsylvania, New Jersey,Maryland Interconnection Powergen Powergen Limited (formerly Powergen plc) PUHCA Public Utility Holding Company Act of 1935 ROE Return on Equity RTO Regional Transmission Organization 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 SMD Standard Market Design SO2 Sulfur Dioxide 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 VDT Value Delivery Team Process Virginia Commission Virginia State Corporation Commission Virginia Staff Virginia State Corporation Commission Staff Page 4 Item 7. Financial Statements and Exhibits (a) None (b) None (c) Exhibits 99(a) Form 10-K Item 1. Business 99(b) Form 10-K Item 6. Selected Financial Data 99(c) Form 10-K Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 99(d) Form 10-K Item 8. Financial Statements and Supplementary Data Page 5 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. Louisville Gas and Electric Company Dated: November 12, 2003 By: /s/ S. Bradford Rives Chief Financial Officer Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. Kentucky Utilities Company Dated: November 12, 2003 By: /s/ S. Bradford Rives Chief Financial Officer Exhibit Index to Current Report on Form 8-K Dated November 12, 2003 Exhibit Number 99(a) Form 10-K Item 1. Business 99(b) Form 10-K Item 6. Selected Financial Data 99(c) Form 10-K Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 99(d) Form 10-K Item 8. Financial Statements and Data Page 5 Exhibit 99(a) LG&E and KU are filing this Current Report on Form 8-K to present reclassified financial statements and other related information in response to the requirements of EITF 02-03. The reclassified financial statements are set forth in the other attached exhibits to this Form 8-K. The information set forth below from Item 1 from the 2002 Annual Report has been included because certain information presented therein was affected by the reclassifications. This exhibit, and the other exhibits to the Form 8- K, contain information identical to the corresponding items of the 2002 Annual Report, except that the information contained in the exhibits has been updated to the extent necessary to report revenues from energy- trading contracts net of related cost of sales for all activities that are trading and involved derivative instruments as defined by Financial Accounting Standards Board Statement No. 133, Accounting for Derivative Instruments and Hedging Activities and to conform the related disclosures for all periods presented. No attempt has been made in this report to modify or update other disclosures except as required to reflect the effects of the reclassifications described above. These other disclosures are included in our annual, quarterly and current reports and other information filed with the SEC. Neither reported net operating income, net income, common equity, nor cash flows were impacted by the reclassification of revenue upon adoption of EITF 02-03. ITEM 1. Business. LG&E and KU are each subsidiaries of LG&E Energy. On December 11, 2000, LG&E Energy was acquired by Powergen plc, now known as Powergen Limited, for cash of approximately $3.2 billion or $24.85 per share and the assumption of all of LG&E Energy's debt. As a result of the acquisition, 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, Virginia and Tennessee 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' obligations to continue to file SEC reports. Following the acquisition, 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 acquisition and in order to comply with PUHCA, LG&E Services was formed as a subsidiary of LG&E Energy effective on January 1, 2001. LG&E Services provides certain services to affiliated entities, including LG&E and KU, at cost as required under PUHCA. On January 1, 2001, approximately 1,000 employees, mainly from LG&E Energy, LG&E and KU, were moved to LG&E Services. On July 1, 2002, E.ON, a German company, completed its acquisition of Powergen following receipt of all necessary regulatory approvals. E.ON had announced its pre-conditional cash offer of 5.1 billion pounds sterling ($7.3 billion) for Powergen on April 9, 2001. LOUISVILLE GAS AND ELECTRIC COMPANY General Incorporated in 1913 in Kentucky, LG&E is a regulated public utility that supplies natural gas to approximately 310,000 customers and electricity to approximately 382,000 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 Page 1 systems. LG&E also provides gas service in limited additional areas. LG&E's coal-fired electric generating plants, 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. LG&E has one wholly owned consolidated subsidiary, LG&E R. LG&E R is a special purpose entity formed in September 2000 to enter into accounts receivable securitization transactions with LG&E. LG&E R started operations in 2001. LG&E is considering unwinding its accounts receivable securitization arrangements involving LG&E R during 2003. For the year ended December 31, 2002, 73% of total operating revenues were derived from electric operations and 27% from gas operations. Electric and gas operating revenues and the percentages by class of service on a combined basis for this period were as follows: (Thousands of $) Electric Gas Combined % Combined Residential $232,285 $160,733 $ 393,018 47% Commercial 185,112 61,036 246,148 30% Industrial 111,871 10,232 122,103 15% Public authorities 57,703 11,197 68,900 8% Total retail 586,971 243,198 830,169 100% Wholesale sales 120,553 16,384 136,937 Gas transported - net - 6,232 6,232 Provision for rate collections 12,267 - 12,267 Miscellaneous 16,251 1,879 18,130 Total $736,042 $267,693 $1,003,735 See Note 13 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, 2002. Electric Operations The sources of LG&E's electric operating revenues and the volumes of sales for the three years ended December 31, 2002, were as follows: 2002 2001 2000 ELECTRIC OPERATING REVENUES (Thousands of $) Residential $232,285 $205,926 $205,105 Commercial 185,112 171,540 171,414 Industrial 111,871 104,438 104,738 Public authorities 57,703 53,725 54,270 Total retail 586,971 535,629 535,527 Wholesale sales 120,553 127,253 113,337 Provision for rate collections (refunds) 12,267 (720) (2,500) Miscellaneous 16,251 11,610 12,851 Total $736,042 $673,772 $659,215 Page 2 ELECTRIC SALES (Thousands of Mwh): Residential 4,036 3,782 3,722 Commercial 3,493 3,395 3,350 Industrial 3,028 2,976 3,043 Public authorities 1,253 1,224 1,214 Total retail 11,810 11,377 11,329 Wholesale sales 6,387 5,989 5,343 Total 18,197 17,366 16,672 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 2002 was approximately 0.55 lbs./Mmbtu of heat input, with every generating unit below its emission limit established by the Kentucky Division for Air Quality. LG&E set a record local peak load of 2,623 Mw on Monday, August 5, 2002, when the peak daily temperature was 100 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 currently maintains a 13 - 15% reserve margin range. At December 31, 2002, LG&E owned steam and combustion turbine generating facilities with a net summer capability of 2,882 Mw and an 80 Mw nameplate rated hydroelectric facility on the Ohio River with a summer capability rate of 48 Mw. At December 31, 2002, LG&E's system net summer capability, including purchases from others and excluding the hydroelectric facility, was 3,037 Mw. See Item 2, Properties. LG&E and 11 other electric utilities are participating owners of OVEC located in Piketon, Ohio. OVEC owns and operates two power plants that burn coal to generate electricity, Kyger Creek Station in Ohio and Clifty Creek Station in Indiana. LG&E's share is 7%, representing approximately 155 Mw's of generation capacity. LG&E also has agreements with a number of entities throughout the United States for the purchase and/or sale of capacity and energy and for the utilization of their bulk transmission system. On February 1, 2002, LG&E (along with KU) turned over operational control of its high voltage transmission facilities (100kV and above) to MISO. LG&E (along with KU) is a founding member of MISO. Such membership was obtained in 1998 in response to and consistent with federal policy initiatives. MISO operates a single OATT over the facilities under its control. Currently MISO controls over 100,000 miles of transmission over 1.1 million square miles located in the northern Midwest between Manitoba, Canada and Kentucky. On September 18, 2002, FERC granted a 12.88% ROE on transmission facilities for LG&E, KU and the rest of the MISO owners. This ROE includes a 50 basis point increase because of operational independence. MISO plans to implement a Congestion Management System in December 2003, in compliance with FERC Order 2000. This system will be similar to the Locational Marginal Pricing (LMP) system currently used by the PJM RTO and contemplated in FERC's SMD NOPR, currently being discussed. MISO filed with FERC a mechanism for recovery of costs for the Congestion Management System, designated Schedule 16 and Schedule 17. The MISO transmission owners, including LG&E and KU, and others have objected to the allocation of costs between market participants and retail native load. This case is currently in a hearing at FERC. In October 2001, the FERC issued an order requiring that the bundled retail load and grandfathered wholesale load of each member transmission owner (including LG&E) be included in the current calculation of MISO's "cost- adder," a charge designed to recover MISO's costs of operation, including Page 3 start-up capital (debt) costs. LG&E, along with several other transmission owners, opposed the FERC's ruling in this regard, which opposition the FERC rejected in an order on rehearing issued in 2002. Later that year, MISO's transmission owners, including LG&E, appealed the FERC's decision to the United States Court of Appeals for the District of Columbia Circuit. In response, by petition filed November 25, 2002, the FERC requested that the Court issue a partial remand of its challenged orders to allow the FERC to revisit certain issues raised therein, and further requested that the case be held in abeyance pending the agency's resolution of such issues. The Court granted the FERC's petition by order dated December 6, 2002. On February 24, 2003, FERC issued an order reaffirming its position concerning the calculation of the "cost-adder". As a separate matter, MISO, its transmission owners and other interested industry segments reached a settlement in mid-2002 regarding the level of cost responsibility properly borne by bundled and grandfathered load under these FERC rulings (such settlement expressly not prejudicing the transmission owners' and LG&E's right to challenge the FERC's ruling imposing cost responsibility on bundled loads in the first instance). On February 24, 2003, FERC accepted a partial settlement between MISO and the transmission owners. FERC did not accept the only contested section of the settlement, which would have allowed the transmission owners to immediately treat unrecoverable Schedule 10 charges as regulatory assets. FERC will consider allowing regulatory asset treatment of unrecoverable Schedule 10 charges on a case-by-case basis. Gas Operations The sources of LG&E's gas operating revenues and the volumes of sales for the three years ended December 31, 2002, were as follows: 2002 2001 2000 GAS OPERATING REVENUES (Thousands of $) Residential $160,733 $177,387 $159,670 Commercial 61,036 70,296 61,888 Industrial 10,232 15,750 15,898 Public authorities 11,197 13,223 9,193 Total retail 243,198 276,656 246,649 Wholesale sales 16,384 5,702 17,344 Gas transported - net 6,232 6,042 6,922 Miscellaneous 1,879 2,375 1,574 Total $267,693 $290,775 $272,489 GAS SALES (Millions of cu. ft.): Residential 22,124 20,429 24,274 Commercial 9,074 8,587 10,132 Industrial 1,783 2,160 3,089 Public authorities 1,747 1,681 1,576 Total retail 34,728 32,857 39,071 Wholesale sales 5,345 1,882 5,115 Gas transported 13,939 13,108 14,729 Total 54,012 47,847 58,915 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 five underground natural gas storage fields that help provide economical and reliable gas service to ultimate consumers. By using gas Page 4 storage facilities, LG&E avoids the costs associated with typically more expensive pipeline transportation capacity to serve peak winter space- heating loads. LG&E stores gas in the summer season for withdrawal in the subsequent winter heating season. Without its storage capacity, LG&E would be forced to buy additional gas and pipeline transportation services when customer demand increases, likely to be when the price for those items are typically at their highest. Currently, LG&E buys competitively priced gas from several large suppliers under contracts of varying duration. LG&E's underground storage facilities, in combination with its purchasing practices, enable it to offer gas sales service at rates lower than state and national averages. At December 31, 2002, LG&E had an inventory balance of gas stored underground of 12.6 million Mcf valued at $50.3 million. A number of industrial customers purchase their natural gas requirements directly from alternate suppliers for delivery through LG&E's distribution system. These large industrial customers account for about one-fourth of LG&E's annual throughput. 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 2002, maximum day gas sendout was approximately 418,000 Mcf, occurring on February 27, 2002, when the average temperature for the day was 21 degrees F. Supply on that day consisted of approximately 130,000 Mcf from purchases, approximately 221,000 Mcf delivered from underground storage, and approximately 67,000 Mcf transported for industrial customers. For a further discussion, see Gas Supply under Item 1. Rates and Regulation Following the purchase of Powergen by E.ON, E.ON became a registered holding company under PUHCA. As a result, E.ON, 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. LG&E believes that it has adequate authority (including financing authority) under existing SEC orders and regulations to conduct its business. LG&E will seek additional authorization when necessary. No costs associated with the E.ON purchase of Powergen or the Powergen purchase of LG&E Energy nor any effects of purchase accounting have been reflected in the financial statements of LG&E. 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 FERC with respect to the matters covered in the FPA, including the sale of electric energy at wholesale in interstate commerce. 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 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 retail 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. Page 5 LG&E's retail electric rates are subject to an ESM. The ESM, initially 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, the excess earnings are shared 40% with ratepayers and 60% with shareholders; if earnings are below the lower limit, the earnings deficiency is recovered 40% from ratepayers and 60% from shareholders. By order of the Kentucky Commission, rate changes prompted by the ESM filing go into effect in April of each year subject to a balancing adjustment in successive periods. LG&E made its second ESM filing on March 1, 2002, for the calendar year 2001 reporting period. LG&E is in the process of refunding $441,000 to customers for the 2001 reporting period. LG&E estimated that the rate of return will fall below the lower limit, subject to Kentucky Commission approval, for the year ended December 31, 2002. The 2002 financial statements include an accrual to reflect the earnings deficiency of $12.5 million to be recovered from customers commencing in April 2003. On November 27, 2002, LG&E filed a revised ESM tariff which proposed continuance of the existing ESM through 2005. The Kentucky Commission issued an Order suspending the ESM tariff one day making the effective date January 2, 2003. In addition, the Kentucky Commission is conducting a management audit to review the ESM plan and reassess its reasonableness in 2003. LG&E and interested parties will have the opportunity to provide recommendations for modification and continuance of the ESM or other forms of alternative or incentive regulation. LG&E's retail 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 rates, subject to approval by 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. 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 load, capacity margins and demand-side management techniques. LG&E filed its most recent integrated resource plan on October 1, 2002. 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 this service territory 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, 2002, gross property additions amounted to approximately $950 million. Internally generated funds and external financings for the five-year period were utilized to provide for these gross additions. The gross additions during this period amounted to approximately 26% of total utility plant at December 31, 2002, and consisted of $798 million for electric properties and $152 million for gas properties. Gross retirements during the same period were $106 million, consisting of $74 million for electric properties and $32 million for gas properties. Page 6 Coal Supply Coal-fired generating units provided over 97% of LG&E's net kilowatt-hour generation for 2002. The remaining net generation was provided by a natural gas and oil fueled combustion turbine peaking units and a hydroelectric plant. 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 2003 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 1.5 million tons, or a 74-day supply, on hand at December 31, 2002. LG&E expects to continue purchasing most of its coal, with 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 electric service in compliance with existing environmental laws and regulations. Coal is delivered to LG&E's Mill Creek plant by rail and barge, Trimble County plant by barge and Cane Run plant by rail. The historical average delivered costs of coal purchased and the percentage of spot coal purchases were as follows: 2002 2001 2000 Per ton $25.30 $21.27 $20.96 Per Mmbtu $ 1.11 $ .93 $ .92 Spot purchases as % of all sources 2% 3% 1% The delivered cost of coal is expected to remain relatively flat during 2003. Slight increases in the cost of coal in multi-year contracts signed for 2002 are expected to be offset by lower prices negotiated in contracts signed for 2003. 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. On April 28, 2000, Texas Gas filed with FERC in Docket RP00-260 for an increase in its base rates effective June 1, 2000. This filing is part of a rate case Texas Gas was required to file pursuant to the settlement in its last rate case. On May 31, 2000, FERC issued an Order suspending the effectiveness of Texas Gas's proposed rates, subject to refund, until November 1, 2000, and establishing a hearing and settlement procedures. As the result of reaching various FERC-approved settlements, Texas Gas's higher motion rates were not billed after July 31, 2002, and its lower prospective rates went into effect on August 1, 2002. Refunds covering the period from November 1, 2000, through July 31, 2002, were received on September 17, 2002, and are currently being refunded to customers through the GSC. LG&E participates in rate and other proceedings affecting its regulated interstate pipeline services, as appropriate. LG&E transports on the Texas Gas system under NNS and FT rate schedules. During the winter months, LG&E has 184,900 Mmbtu/day in NNS service and Page 7 18,000 Mmbtu/day (increasing to 36,000 Mmbtu/day effective November 1, 2003) in FT service. LG&E's summer NNS levels are 60,000 Mmbtu/day and its summer FT levels are 54,000 Mmbtu/day. Each of these NNS and FT agreements with Texas Gas are subject to termination by LG&E in equal portions during 2005, 2006, and 2008. LG&E also transports on the Tennessee system under Tennessee's FT-A rate schedule. LG&E's contract levels with Tennessee are 51,000 Mmbtu/day throughout the year. The FT-A agreement with Tennessee, which was subject to termination by LG&E during 2002, has been successfully renegotiated for a minimum additional term of five years at a lower price. 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 gas supplies, in tandem with pipeline transportation services, provide the reliability and flexibility necessary to serve LG&E's customers. LG&E owns and operates five underground gas storage fields with a current working gas capacity of about 15.1 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. See Gas Operations under Item 1. The estimated maximum deliverability from storage during the early part of the heating season is typically about 373,000 Mcf/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 $4.19 in 2002, $5.27 in 2001 and $5.08 in 2000. Although natural gas prices in the unregulated wholesale market increased significantly throughout 2000 and early 2001, these prices decreased dramatically in early 2002 and then began to increase again. These increases in natural gas prices, caused in part by decreased natural gas production, decreased liquidity in the marketplace, increases in the price of oil, and increased reliance on natural gas as a fuel for electric generation were mitigated in part by higher national storage inventory levels, and decreased demand associated with a less robust economy. Environmental Matters Protection of the environment is a major priority for LG&E. Federal, state, and local regulatory 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 ending with 2002, expenditures for pollution control facilities represented $253.8 million or 27% of total construction expenditures. LG&E estimates that construction expenditures for the installation of NOx control equipment from 2003 through 2004 will be approximately $32 million. For a discussion of environmental matters, see Rates and Regulation for LG&E under Item 7 and Note 11 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. Page 8 KENTUCKY UTILITIES COMPANY General KU, incorporated in Kentucky in 1912 and incorporated in Virginia in 1991, is a regulated public utility engaged in producing, transmitting and selling electric energy. KU provides electric service to approximately 477,000 customers in over 600 communities and adjacent suburban and rural areas in 77 counties in central, southeastern and western Kentucky, to approximately 30,000 customers in 5 counties in southwestern Virginia and to less than 10 customers in Tennessee. 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. KU has one wholly owned consolidated subsidiary, KU R. KU R is a special purpose entity formed in September 2000 to enter into accounts receivable securitization transactions with KU. KU R began operations in 2001. KU is considering unwinding its accounts receivable securitization arrangements involving KU R during 2003. Electric Operations The sources of KU's electric operating revenues and the volumes of sales for the three years ended December 31, 2002, were as follows: 2002 2001 2000 ELECTRIC OPERATING REVENUES (Thousands of $): Residential $275,869 $244,004 $241,783 Commercial 179,157 165,389 161,291 Industrial 163,206 146,968 153,017 Mine power 29,453 28,196 27,089 Public authorities 62,649 58,770 57,979 Total retail 710,334 643,327 641,159 Wholesale sales 117,252 164,430 139,541 Provision for rate collections (refunds) 13,027 (954) - Miscellaneous 21,051 13,918 12,709 Total $861,664 $820,721 $793,409 ELECTRIC SALES (Thousands of Mwh): Residential 6,198 5,678 5,714 Commercial 4,161 3,990 3,954 Industrial 4,975 4,716 5,044 Mine power 766 771 767 Public authorities 1,533 1,481 1,495 Total retail 17,633 16,636 16,974 Wholesale sales 4,793 6,634 5,942 Total 22,426 23,270 22,916 KU's weighted-average system-wide emission rate for sulfur dioxide in 2002 was approximately 1.24 lbs./Mmbtu of heat input, with every generating unit below its emission limit established by the Kentucky Division for Air Quality. Page 9 KU set a record local peak load of 3,899 Mw on Monday, August 5, 2002, when the peak daily temperature was 100 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 KU's Results of Operations under Item 7. KU currently maintains a 13-15% reserve margin range. At December 31, 2002, KU owned steam and combustion turbine generating facilities with a net summer capability of 4,111 Mw and a hydroelectric facility with a summer capability of 24 Mw. See Item 2, Properties. KU obtains power from other utilities under bulk power purchase and interchange contracts. At December 31, 2002, KU's system net summer capability, including purchases from others and excluding the hydroelectric facility, was 4,630 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 equated to approximately 8% of KU's net generation system output during 2002. 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 equated to approximately 9% of KU's net generation system output in 2002. See Note 11 of KU's Notes to Financial Statements under Item 8. KU and 11 other electric utilities are participating owners of OVEC located in Piketon, Ohio. OVEC owns and operates two power plants that burn coal to generate electricity, Kyger Creek Station in Ohio and Clifty Creek Station in Indiana. KU's share is 2.5%, approximately 55 Mws of generation capacity. KU also has agreements with a 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 systems. On February 1, 2002, KU (along with LG&E) turned over operational control of its high voltage transmission facilities (100kV and above) to MISO. KU (along with LG&E) is a founding member of MISO. Such membership was obtained in 1998 in response to and consistent with federal policy initiatives. MISO operates a single OATT over the facilities under its control. Currently MISO controls over 100,000 miles of transmission over 1.1 million square miles located in the northern Midwest between Manitoba, Canada and Kentucky. On September 18, 2002, FERC granted a 12.88% ROE on transmission facilities for LG&E, KU and the rest of the MISO owners. This ROE includes a 50 basis point increase because of operational independence. MISO plans to implement a Congestion Management System in December 2003, in compliance with FERC Order 2000. This system will be similar to the Locational Marginal Pricing (LMP) system currently used by the PJM RTO and contemplated in FERC's SMD NOPR currently being discussed. MISO filed with FERC a mechanism for recovery of costs for the Congestion Management System, designated Schedule 16 and Schedule 17. MISO transmission owners, including LG&E and KU, and others have objected to the allocation of costs between market participants and retail native load. This case is currently in a hearing at FERC. In October 2001, the FERC issued an order requiring that the bundled retail load and grandfathered wholesale load of each member transmission owner (including KU) be included in the current calculation of MISO's "cost- adder," a charge designed to recover MISO's costs of operation, including start-up capital (debt) costs. KU, along with several other transmission Page 10 owners, opposed the FERC's ruling in this regard, which opposition the FERC rejected in an order on rehearing issued in 2002. Later that year, MISO's transmission owners, including KU, appealed the FERC's decision to the United States Court of Appeals for the District of Columbia Circuit. In response, by petition filed November 25, 2002, FERC requested that the Court issue a partial remand of its challenged orders to allow the FERC to revisit certain issues raised therein, and further requested that the case be held in abeyance pending the agency's resolution of such issues. The Court granted the FERC's petition by order dated December 6, 2002. On February 24, 2003, FERC issued an order reaffirming its position concerning the calculation of the "cost-adder". As a separate matter, MISO, its transmission owners and other interested industry segments reached a settlement in mid-2002 regarding the level of cost responsibility properly borne by bundled and grandfathered load under these FERC rulings (such settlement expressly not prejudicing the transmission owners' and KU's right to challenge the FERC's ruling imposing cost responsibility on bundled loads in the first instance). On February 24, 2003, FERC accepted a partial settlement between MISO and the transmission owners. FERC did not accept the only contested section of the settlement, which would have allowed the transmission owners to immediately treat unrecoverable Schedule 10 charges as regulatory assets. FERC will consider allowing regulatory asset treatment of unrecoverable Schedule 10 charges on a case-by-case basis. Rates and Regulation Following the purchase of Powergen by E.ON, E.ON became a registered holding company under PUHCA. As a result, E.ON, 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. KU believes that it has adequate authority (including financing authority) under existing SEC orders and regulations to conduct its business. KU will seek additional authorization when necessary. No costs associated with the E.ON purchase of Powergen or the Powergen purchase of LG&E Energy nor any effects of purchase accounting have been reflected in the financial statements of KU. 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 approximately $225,000) from which KU served five customers at December 31, 2002, 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 other respects as provided in the FPA. 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 retail 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. Page 11 KU's Kentucky retail electric rates are subject to an ESM. The ESM, initially 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, the excess earnings are shared 40% with ratepayers and 60% with shareholders; if earnings are below the lower limit, the earnings deficiency is recovered 40% from ratepayers and 60% from shareholders. By order of the Kentucky Commission, rate changes prompted by the ESM filing go into effect in April of each year subject to a balancing adjustment in successive periods. KU made its second ESM filing on March 1, 2002 for the calendar year 2001 reporting period. KU is in the process of refunding $1 million to customers for the 2001 reporting period. KU estimated that the rate of return will fall below the lower limit for the year ended December 31, 2002. The 2002 financial statements include an accrual to reflect the earnings, subject to Kentucky Commission approval, deficiency of $13.5 million to be recovered from customers commencing in April 2003. On November 27, 2002, KU filed a revised ESM tariff which proposed continuance of the existing ESM through 2005. The Kentucky Commission issued an Order suspending the ESM tariff one day making the effective date January 2, 2003. In addition, the Kentucky Commission is conducting a management audit to review the ESM plan and reassess its reasonableness in 2003. KU and interested parties will have the opportunity to provide recommendations for modification and continuance of the ESM or other forms of alternative or incentive regulation. KU's Kentucky retail 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 load, capacity margins and demand-side management techniques. KU filed its most recent integrated resource plan on October 1, 2002. 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 this service territory each such supplier has the exclusive right to render retail electric service. The state of Virginia passed the Virginia Electric Utility Restructuring Act in 1999. This act gives Virginia customers a choice for energy services. The change will be phased in gradually between January 2002 and January 2004. KU filed unbundled rates that became effective January 1, 2002. 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. The Virginia Staff will issue a Staff Report regarding the individual utility's financial performance during the historic 12-month period. The Staff Report can lead to an adjustment in rates, but through June 2007 will be limited to decreases. KU was granted a waiver from the Virginia Commission on October 29, 2002, exempting KU from retail choice through December 31, 2004. KU is also seeking a permanent legislative exemption from the Virginia Electric Utility Restructuring Act. The outcome of this legislative initiative is not expected be known until mid-2003. Construction Program and Financing 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. Page 12 During the five years ended December 31, 2002, gross property additions amounted to approximately $754 million. Internally generated funds and external financings for the five-year period were utilized to provide for these gross additions. The gross additions during this period amounted to approximately 23% of total utility plant at December 31, 2002. Gross retirements during the same period were $82 million. Coal Supply Coal-fired generating units provided over 97% of KU's net kilowatt-hour generation for 2002. The remaining net generation for 2002 was provided by natural gas and oil fueled combustion turbine peaking units and hydroelectric plants. Coal will be the predominant fuel used by KU in the foreseeable future, with natural gas and oil being used for capacity and flame stabilization in coal-fired boilers or in emergencies. KU has no nuclear generating units and has no plans to build any in the foreseeable future. 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 1.4 million tons, or a 67-day supply, on hand at December 31, 2002. KU expects to continue purchasing most of its coal, which has a sulfur content in the 0.7% - 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 and Green River locations are by truck. Delivery to E.W. Brown is by rail. The historical average delivered cost of coal purchased and the percentage of spot coal purchases were as follows: 2002 2001 2000 Per ton $31.44 $27.84 $25.63 Per Mmbtu $1.35 $1.20 $1.07 Spot purchases as % of all sources 18% 44% 51% 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. The delivered cost of coal is expected to increase during 2003. Environmental Matters Protection of the environment is a major priority for KU. Federal, state, and local regulatory 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 2002, expenditures for Page 13 pollution control facilities represented $63.5 million or 11% of total construction expenditures. KU estimates that construction expenditures for the installation of NOx control equipment from 2003 through 2004 will be approximately $178 million. For a discussion of environmental matters, see Rates and Regulation for KU under Item 7 and Note 11 of KU's Notes to Financial Statements under Item 8. Competition In the last several years, 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 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. KU will continue to take additional steps to better position itself for competition in the future. EMPLOYEES AND LABOR RELATIONS LG&E had 891 full-time regular employees and KU had 946 full-time regular employees at December 31, 2002. Of the LG&E total, 628 operating, maintenance, and construction employees were represented by IBEW Local 2100. LG&E and employees represented by IBEW Local 2100 signed a four-year collective bargaining agreement in November 2001. Of the KU total, 162 operating, maintenance, and construction employees were represented by IBEW Local 2100 and USWA Local 9447-01. In August 2001, KU and employees represented by IBEW Local 2100 entered into a two-year collective bargaining agreement. KU and employees represented by USWA Local 9447-01 entered into a three-year collective bargaining agreement effective August 2002 and expiring August 2005. As a result of the Powergen acquisition and in order to comply with PUHCA, LG&E Services was formed 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 3 of LG&E's Notes to Financial Statements and Note 3 of KU's Notes to Financial Statements under Item 8 for workforce separation program in effect for 2001. Page 14 Executive Officers of LG&E and KU at December 31, 2002: Effective Date of Election to Present Name Age Position Position Victor A. Staffieri 47 Chairman of the Board, May 1, 2001 President and Chief Executive Officer Richard Aitken-Davies 53 Chief Financial Officer January 31, 2001 John R. McCall 59 Executive Vice President, July 1, 1994 General Counsel and Corporate Secretary S. Bradford Rives 44 Senior Vice President - December 11, 2000 Finance and Controller Paul W. Thompson 45 Senior Vice President - June 7, 2000 Energy Services Chris Hermann 55 Senior Vice President - December 11, 2000 Distribution Operations Wendy C. Welsh 48 Senior Vice President - December 11, 2000 Information Technology Martyn Gallus 38 Senior Vice President - December 11, 2000 Energy Marketing A. Roger Smith 49 Senior Vice President December 11, 2000 Project Engineering David A. Vogel 36 Vice President - Retail December 11, 2000 Services Daniel K. Arbough 41 Treasurer December 11, 2000 Bruce D. Hamilton 47 Vice President December 11, 2000 Independent Power Operations Robert E. Henriques 61 Vice President September 30, 2001 Regulated Generation Michael S. Beer 44 Vice President-Rates February 1, 2001 and Regulatory George R. Siemens 53 Vice President-External January 11, 2001 Affairs Paula H. Pottinger 45 Vice President - June 1, 2002 Human Resources D. Ralph Bowling 45 Vice President - August 1, 2002 Power Operations WKE Page 15 R. W. Chip Keeling 46 Vice President - March 18, 2002 Communications The present term of office of each of the above executive officers extends to the meeting of the Board of Directors following the 2003 Annual Meeting of Shareholders. There are no family relationships between or among executive officers of LG&E and KU. The above tables indicate officers serving as executive officers of both LG&E and KU at December 31, 2002. Each of the above officers serves in the same capacity for LG&E and KU. Before he was elected to his current positions, Mr. Staffieri was President, Distribution Services Division 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, (including Chief Financial Officer of KU from May 1998 to February 1999); President and Chief Operating Officer of LG&E Energy Corp. from March 1999 to April 2001 (including President of LG&E and KU from June 2000 to April 2001); Chairman, President and CEO of LG&E Energy Corp., LG&E and KU from May 2001 to present. Before he was elected to his current positions, Mr. Aitken-Davies was Group Performance Director at Powergen from April 1998 to March 2000; Director - LG&E Transition Team at Powergen from March 2000 to January 2001. Mr. McCall has been Executive Vice President, General Counsel and Corporate Secretary of LG&E Energy Corp. and LG&E since July 1994. He became Executive Vice President, General Counsel and Corporate Secretary of KU in May 1998. Before he was elected to his current positions, Mr. Rives was 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; Vice President, Power Generation and Engineering Services, of LG&E from May 1998 to December 1999; and Vice President Supply Chain and Operating Services from December 1999 to December 2000. Before she was elected to her current positions, Ms. Welsh was Vice President - Information Services of LG&E from January 1994 to May 1997; Vice President, Administration of LG&E Energy Corp. from May 1997 to February 1998; and Vice President-Information Technology from February 1998 to December 2000. Before he was elected to his current positions, Mr. Gallus was Director, Trading and Risk Management from January 1996 to September 1996; Director, Product Development from September 1996 to April 1997; Vice President, Structured Products from April 1997 to May 1998; Senior Vice President, Trading, from May 1998 to August 1998 for LG&E Energy Marketing Inc.; and Vice President, Energy Marketing from August 1998 to December 2000 for LG&E Energy Corp. Page 16 Before he was elected to his current positions, Mr. Smith was Head of Construction Projects - Powergen from January 1996 to May 1999; Director of Projects - Powergen from May 1999 to December 1999; and Director of Engineering Projects for Powergen International from January 2000 to December 2000. Before he was elected to his current positions, Mr. Vogel served in management positions within the Distribution organization of LG&E and KU prior to December 2000. In his position prior to his current role he was responsible for statewide outage management and restoration of distribution network. Before he was elected to his current positions, Mr. Arbough was Manager, Corporate Finance of LG&E Energy Corp., and LG&E from August 1996 to May 1998; and he has held the position of Director, Corporate Finance of LG&E Energy Corp., LG&E and KU from May 1998 to present. Before he was elected to his current positions, Mr. Hamilton was Venture Manager from May 1992 to December 1995; Senior Venture Manager from December 1995 to September 1997 and Vice President, Asset Management from September 1997 to December 2000. Before he was elected to his current positions, Mr. Henriques was Senior Venture Manager for LG&E Power Inc. from May 1993 to September 1995, and Vice President-Plant Operations from September 1995 to September 2001. Before he was elected to his current positions, Mr. Beer was Director, Federal Regulatory Affairs, for Illinois Power Company in Decatur, Illinois, from February of 1997 to January of 1998; Senior Corporate Attorney from February 1998 to February 2000; and Senior Counsel Specialist, Regulatory from February 2000 to February 2001. Before he was elected to his current positions, Mr. Siemens held the position of Director of External Affairs for LG&E from August 1982 to January 2001. Before she was elected to her current positions as Vice President-Human Resources, Ms. Pottinger was Manager, Human Resources Development from May 1994 to May 1997; and Director, Human Resources from June 1997 to June 2002. Before he was elected to his current positions, Mr. Bowling was Plant General Manager at Western Kentucky Energy Corp. from July 1998 to December 2001; and General Manager Black Fossil Operations for Powergen in the United Kingdom from January 2002 to August 2002. Before he was elected to his current positions, Mr. Keeling was General Manager, Marketing Communications for General Electric Company from January 1998 to January 1999. He joined LG&E Energy Corp. and held the title Manager, Media Relations from January 1999 to February 2000; and Director, Corporate Communications for LG&E Energy from February 2000 to March 2002. Page 17 Exhibit 99(b) LG&E and KU are filing this Current Report on Form 8-K to present reclassified financial statements and other related information in response to the requirements of EITF 02-03. The reclassified financial statements are set forth in the other attached exhibits to this Form 8-K. The information set forth below from Item 6 from the 2002 Annual Report has been included because certain information presented therein was affected by the reclassifications. This exhibit, and the other exhibits to the Form 8- K, contain information identical to the corresponding items of the 2002 Annual Report, except that the information contained in the exhibits has been updated to the extent necessary to report revenues from energy-trading contracts net of related cost of sales for all activities that are trading and involved derivative instruments as defined by Financial Accounting Standards Board Statement No. 133, Accounting for Derivative Instruments and Hedging Activities and to conform the related disclosures for all periods presented. No attempt has been made in this report to modify or update other disclosures except as required to reflect the effects of the reclassifications described above. These other disclosures are included in our annual, quarterly and current reports and other information filed with the SEC. Neither reported net operating income, net income, common equity, nor cash flows were impacted by the reclassification of revenue upon adoption of EITF 02-03. The 2000, 1999 and 1998 consolidated financial data were derived from financial statements audited by Arthur Andersen LLP, independent public accountants, who expressed an unqualified opinion on those financial statements in their report dated January 26, 2001, before the revisions described in Note 1 to the Notes to Financial Statements filed as Exhibit 99(d). Arthur Andersen LLP has ceased operations. The amounts shown below for such periods, reclassified pursuant to the adoption of EITF 02-03, are unaudited. ITEM 6. Selected Financial Data. Years Ended December 31 (Thousands of $) 2002 2001 2000 1999 1998 LG&E: Operating revenues: Revenues $991,468 $965,267 $934,204 $847,879 $854,556 Provision for rate collections (refunds) 12,267 (720) (2,500) (1,735) (4,500) Total operating revenues 1,003,735 964,547 931,704 846,144 850,056 Net operating income 117,914 141,773 148,870 140,091 135,523 Net income 88,929 106,781 110,573 106,270 78,120 Net income available for common stock 84,683 102,042 105,363 101,769 73,552 Total assets 2,561,078 2,448,354 2,226,084 2,171,452 2,104,637 Long-term obligations (including amounts due within one year) $ 616,904 $ 616,904 $ 606,800 $ 626,800 $ 626,800 LG&E's Management's Discussion and Analysis of Financial Condition and Results of Operation and LG&E's Notes to Financial Statements should be read in conjunction with the above information. Page 1 Years Ended December 31 (Thousands of $) 2002 2001 2000 1999 1998 KU: Operating revenues: Revenues $ 848,637 $ 821,675 $ 793,409 $ 815,532 $ 807,786 Provision for rate collections (refunds) 13,027 (954) - (5,900) (21,500) Total operating revenues 861,664 820,721 793,409 809,632 786,286 Net operating income 108,643 121,370 128,136 136,016 125,388 Net income 93,384 96,414 95,524 106,558 72,764 Net income available for common stock 91,128 94,158 93,268 104,302 70,508 Total assets 1,998,383 1,826,902 1,739,518 1,785,090 1,761,201 Long-term obligations (including amounts due within one year) $ 500,492 $ 488,506 $ 484,830 $ 546,330 $ 546,330 KU's Management's Discussion and Analysis of Financial Condition and Results of Operation and KU's Notes to Financial Statements should be read in conjunction with the above information. Page 2 Exhibit 99(c) LG&E and KU are filing this Current Report on Form 8-K to present reclassified financial statements and other related information in response to the requirements of EITF 02-03. The reclassified financial statements are set forth in the other attached exhibits to this Form 8-K. The information set forth below from Item 7 from the 2002 Annual Report has been included because certain information presented therein was affected by the reclassifications. This exhibit, and the other exhibits to the Form 8- K, contain information identical to the corresponding items of the 2002 Annual Report, except that the information contained in the exhibits has been updated to the extent necessary to report revenues from energy-trading contracts net of related cost of sales for all activities that are trading and involved derivative instruments as defined by Financial Accounting Standards Board Statement No. 133, Accounting for Derivative Instruments and Hedging Activities and to conform the related disclosures for all periods presented. No attempt has been made in this report to modify or update other disclosures except as required to reflect the effects of the reclassifications described above. These other disclosures are included in our annual, quarterly and current reports and other information filed with the SEC. Neither reported net operating income, net income, common equity, nor cash flows were impacted by the reclassification of revenue upon adoption of EITF 02-03. ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. 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 2002, 2001, and 2000 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 materially vary. Factors that could cause actual results to materially differ 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; actions by credit rating agencies; and other factors described from time to time in LG&E's reports to the SEC, including Exhibit No. 99.01 to the Annual Report. MERGERS and ACQUISITIONS On December 11, 2000, LG&E Energy was acquired by Powergen for cash of approximately $3.2 billion or $24.85 per share and the assumption of all of LG&E Energy's debt. As a result of the acquisition, LG&E Energy became a wholly owned subsidiary of Powergen and, as a result, LG&E became an indirect subsidiary of Powergen. LG&E has continued its separate identity and serves 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 continues to file SEC reports. Following the acquisition, 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. On July 1, 2002, E.ON, a German company, completed its acquisition of Powergen plc (now Powergen Limited). As a result, LG&E and KU became indirect subsidiaries of E.ON. E.ON had announced its pre-conditional cash offer of 5.1 billion pounds sterling ($7.3 billion) for Powergen on April 9, 2001. Following the acquisition, E.ON became a registered holding company under PUHCA. Page 1 As contemplated in their regulatory filings in connection with the E.ON acquisition, E.ON, Powergen and LG&E Energy completed an administrative reorganization to move the LG&E Energy group from an indirect Powergen subsidiary to an indirect E.ON subsidiary. This reorganization was effective in March 2003. RESULTS OF OPERATIONS Net Income LG&E's net income in 2002 decreased $17.9 million as compared to 2001. The decrease resulted primarily from higher transmission operating expenses, an increase in amortization of VDT regulatory asset, and increased property insurance and pension expense, partially offset by an increase in electric sales to retail customers and lower interest expenses. LG&E's net income decreased $3.8 million for 2001, as compared to 2000. This decrease is mainly due to higher pension related expenses and amortization of VDT regulatory asset, partially offset by increased electric and gas net revenues (operating revenues less fuel for electric generation, power purchased and gas supply expenses) and decreased interest expenses. Revenues A comparison of operating revenues for the years 2002 and 2001, excluding the provisions recorded for rate collections (refunds), 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 2002 2001 2002 2001 Retail sales: Fuel and gas supply adjustments $ 19,449 $ (394) $(58,003) $ 79,627 LG&E/KU Merger surcredit (2,825) (2,456) - - Performance based rate - 1,962 - - Environmental cost recovery surcharge 9,694 1,246 - - Demand side management 1,381 - 938 - Electric rate reduction - (3,671) - - VDT surcredit (1,177) (1,014) (285) (68) Gas rate increase - - - 15,265 Weather normalization - - 2,234 - Variation in sales volumes and other 24,819 4,429 21,658 (64,817) Total retail sales 51,341 102 (33,458) 30,007 Wholesale sales (6,700) 13,916 10,683 (11,642) Gas transportation-net - - 189 (880) Other 4,642 (1,241) (496) 801 Total $ 49,283 $ 12,777 $(23,082) $ 18,286 Electric revenues increased in 2002 primarily due to an increase in retail sales due to warmer summer weather, an increase in the recovery of fuel costs passed through the FAC, partially offset by a decrease in wholesale sales due to lower market prices as compared to 2001. Cooling degree days Page 2 increased 20% compared to 2001. Electric revenues increased in 2001 primarily due to an increase in wholesale sales and retail sales volume, partially offset by the effects of an electric rate reduction ordered by the Kentucky Commission, and the LG&E/KU merger surcredit (See Note 2 of LG&E's Notes to Financial Statements under Item 8). In January 2000, the Kentucky Commission ordered an electric rate reduction and the termination of LG&E's proposed electric PBR mechanism. Gas revenues in 2002 decreased due to a lower gas supply cost billed to customers through the gas supply clause offset partially by increased gas retail sales due to cooler winter weather and an increase in wholesale sales volume. Heating degree days increased 17% as compared to 2001. Gas revenues in 2001 increased primarily as a result of higher gas supply costs billed to customers through the gas supply clause and the effects of a gas rate increase ordered by the Kentucky Commission in September 2000. The gas revenue increase was partially offset by a decrease in retail and wholesale gas sales in 2001 due to warmer weather. Heating degree days decreased 10.2% compared to 2000. Expenses Fuel for electric generation and gas supply expenses comprise a large component of LG&E's total operating costs. The retail electric rates contain a 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, and passed through to LG&E's retail customers. Fuel for electric generation increased $35.7 million (22.4%) in 2002 due to increased generation ($5.4 million) and higher cost of coal burned ($30.3 million). Fuel for electric generation decreased $0.2 million (.1%) in 2001 primarily due to decreased generation as a result of decreased electric sales ($2.2 million) partially offset by a higher cost of coal burned ($2.0 million). The average delivered cost per ton of coal purchased was $25.30 in 2002, $21.27 in 2001 and $20.96 in 2000. Power purchased expense increased $12.6 million (25.5%) in 2002 due to an increase in purchases to meet requirements for native load partially offset by a decrease in purchase price. Power purchased increased $4.2 million (9.2%) in 2001 primarily due to an increase in purchases to meet requirements for native load partially offset by a lower unit cost of the purchases. Gas supply expenses decreased $24.1 million (11.7%) in 2002 due to a decrease in cost of net gas supply ($36.6 million), partially offset by an increase in the volume of gas delivered to the distribution system ($12.5 million). Gas supply expenses increased $9.3 million (4.7%) in 2001 primarily due to an increase in cost of net gas supply ($36.2 million), partially offset by a decrease in the volume of gas delivered to the distribution system ($26.9 million). The average unit cost per Mcf of purchased gas was $4.19 in 2002, $5.27 in 2001 and $5.08 in 2000. Other operation expenses increased $40.5 million (24.1%) in 2002 primarily due to a full year amortization in 2002 of a regulatory asset created as a result of the workforce reduction costs associated with LG&E's VDT ($17.0 million), higher costs for electric transmission primarily resulting from increased MISO costs ($13.9 million), an increase in property and other insurance costs ($3.9 million), an increase in pension costs due to change in pension assumptions to reflect current market conditions and change in market value of plan assets at the measurement date ($3.7 million), and an increase in steam production costs ($3.4 million). Other operation expenses increased $31.9 million (23.4%) in 2001 primarily due to amortization of a regulatory asset resulting from workforce reduction costs associated with LG&E's VDT ($13.0 million), an increase in pension expense ($10.3 million) and an increase in outside services ($8.5 million). Outside services increased in part due to the reclassification of expenses as a result of the formation of LG&E Services, as required by the SEC to comply with PUHCA. Page 3 Maintenance expenses for 2002 increased $1.5 million (2.6%) primarily due to gas distribution expenses for main remediation work ($2.2 million). Maintenance expenses for 2001 decreased $5.0 million (7.9%) primarily due to decreases in scheduled outages ($2.8 million), and a decrease in software and communication equipment maintenance ($2.8 million). Depreciation and amortization increased $5.5 million (5.5%) in 2002 and $2.1 million (2.1%) in 2001 because of additional utility plant in service. The 2001 increase was offset by a decrease in depreciation rates resulting from a settlement order in December 2001 from the Kentucky Commission. Depreciation expenses decreased $5.6 million as a result of the settlement order. Variations in income tax expenses are largely attributable to changes in pre-tax income. LG&E's 2002 effective income tax rate increased to 37.2% from the 36.5% rate in 2001. See Note 7 of LG&E's Notes to Financial Statements under Item 8. Property and other taxes decreased $0.3 million (1.6%) in 2002. Property and other taxes decreased $1.2 million (6.5%) in 2001 primarily due to a reduction in payroll taxes related to fewer employees as a result of workforce reductions and transfers to LG&E Services. Other income - net decreased $2.1 million (72.0%) in 2002 primarily due to increased costs for non-utility areas, $1.3 million and decreases in the gain on sale of property $0.8 million. Other income - net decreased $2.0 million (40.5%) in 2001 primarily due to lower interest and dividend income. Interest charges for 2002 decreased $8.1 million (21.4%) primarily due to lower interest rates on variable rate debt ($5.6 million) a decrease in debt to associated companies ($0.8 million) and a decrease in interest associated with LG&E's accounts receivable securitization program ($1.5 million). Interest charges for 2001 decreased $5.3 million (12.2%) primarily due to lower interest rates on variable rate debt ($2.2 million) and the retirement of short-term borrowings ($8.1 million) partially offset by an increase in debt to associated companies ($2.5 million) and an increase in interest associated with LG&E's accounts receivable securitization program ($2.5 million). See Note 9 of LG&E's Notes to Financial Statements under Item 8. LG&E's weighted average cost of long-term debt, including amortization of debt expense and interest rate swaps, was 3.87% at December 31, 2002 compared to 4.17% at December 31, 2001. See Note 9 of LG&E's Notes to Financial Statements under Item 8. 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. CRITICAL ACCOUNTING POLICIES/ESTIMATES Preparation of financial statements and related disclosures in compliance with generally accepted accounting principles requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. The application of these policies necessarily involves Page 4 judgments regarding future events, including legal and regulatory challenges and anticipated recovery of costs. These judgments, in and of themselves, could materially impact the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment also may have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies applied has not changed. Specific risks for these critical accounting policies are described in the following paragraphs. Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions. Events rarely develop exactly as forecast and the best estimates routinely require adjustment. See also Note 1 of LG&E's Notes to Financial Statements under Item 8. Unbilled Revenue - At each month end LG&E prepares a financial estimate that projects electric and gas usage that has been used by customers, but not billed. The estimated usage is based on known weather and days not billed. At December 31, 2002, a 10% change in these estimated quantities would cause revenue and accounts receivable to change by approximately $5.0 million, including $2.3 million for electric usage and $2.7 million for gas usage. See also Note 1 of LG&E's Notes to Financial Statements under Item 8. Benefit Plan Accounting - Judgments and uncertainties in benefit plan accounting include future rate of returns on pension plan assets, interest rates used in valuing benefit obligation, healthcare cost trend rates, and other actuarial assumptions. LG&E's costs of providing defined-benefit pension retirement plans is dependent upon a number of factors, such as the rates of return on plan assets, discount rate, and contributions made to the plan. The market value of LG&E plan assets has been affected by declines in the equity market since the beginning of the fiscal year. As a result, at December 31, 2002, LG&E was required to recognize an additional minimum liability as prescribed by SFAS No. 87 Employers' Accounting for Pensions. The liability was recorded as a reduction to other comprehensive income, and did not affect net income for 2002. The amount of the liability depended upon the asset returns experienced in 2002 and contributions made by LG&E to the plan during 2002. Also, pension cost and cash contributions to the plan could increase in future years without a substantial recovery in the equity market. If the fair value of the plan assets exceeds the accumulated benefit obligation, the recorded liability will be reduced and other comprehensive income will be restored in the consolidated balance sheet. The combination of poor market performance and a decrease in short-term corporate bond interest rates has created a divergence in the potential value of the pension liability and the actual value of the pension assets. These conditions could result in an increase in LG&E's funded accumulated benefit obligation and future pension expense. The primary assumptions that drive the value of the unfunded accumulated benefit obligation are the discount rate and expected return on plan assets. LG&E made a contribution to the pension plan of $83.1 million in January 2003. A 1% increase or decrease in the assumed discount rate could have an approximate $37.0 million positive or negative impact to the accumulated benefit obligation of LG&E. See also Note 6 of LG&E's Notes to Financial Statements under Item 8. Regulatory Mechanisms - Judgments and uncertainties include future regulatory decisions, impact of deregulation and competition on ratemaking process, and external regulator decisions. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates based upon Kentucky Commission orders. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections based upon orders by the Kentucky Commission. Management believes, based on orders, the existing regulatory assets and liabilities are probable of recovery. This determination reflects the current regulatory climate in the state. If future recovery of costs ceases to be probable the assets would be required to be recognized in current period earnings. Page 5 LG&E has accrued in the financial statements an estimate of $12.5 million for 2002 ESM, with collection from customer commencing in April 2003. The ESM is subject to Kentucky Commission approval. See also Note 3 of LG&E's Notes to Financial Statements under Item 8. NEW ACCOUNTING PRONOUNCEMENTS SFAS No. 143, Accounting for Asset Retirement Obligations was issued in 2001. SFAS No. 143 establishes accounting and reporting standards for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The effective implementation date for SFAS No. 143 is January 1, 2003. Management has calculated the impact of SFAS No. 143 and the recently released FERC NOPR No. RM02-7, Accounting, Financial Reporting, and Rate Filing Requirements for Asset Retirement Obligations. As of January 1, 2003, LG&E recorded asset retirement obligation (ARO) assets in the amount of $4.6 million and liabilities in the amount of $9.3 million. LG&E also recorded a cumulative effect adjustment in the amount of $5.3 million to reflect the accumulated depreciation and accretion of ARO assets at the transition date less amounts previously accrued under regulatory depreciation. LG&E recorded offsetting regulatory assets of $5.3 million, pursuant to regulatory treatment prescribed under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. Also pursuant to SFAS No. 71, LG&E recorded regulatory liabilities in the amount of $60,000 offsetting removal costs previously accrued under regulatory accounting in excess of amounts allowed under SFAS No. 143. LG&E also expects to record ARO accretion expense of approximately $617,000, ARO depreciation expense of approximately $117,000 and an offsetting regulatory credit in the income statement of approximately $734,000 in 2003, pursuant to regulatory treatment prescribed under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. The accretion, depreciation and regulatory credit will be annual adjustments. SFAS No. 143 will have no impact on the results of the operation of LG&E. LG&E asset retirement obligations are primarily related to the final retirement of generating units. LG&E transmission and distribution lines largely operate under perpetual property easement agreements which do not generally require restoration upon removal of the property. Therefore, under SFAS No. 143, no material asset retirement obligations will be recorded for transmission and distribution assets. LG&E adopted EITF No. 98-10, Accounting for Energy Trading and Risk Management Activities, effective January 1, 1999. This pronouncement required that energy trading contracts be marked to market on the balance sheet, with the gains and losses shown net in the income statement. The EITF clarified accounting standards related to energy trading activities under EITF Issue 02-03, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities. EITF No. 02-03 established the following: - Rescinded EITF No. 98-10, - Contracts that do not meet the definition of a derivative under SFAS No. 133 should not be marked to fair market value, and - Revenues should be shown in the income statement net of costs associated with trading activities, whether or not the trades are physically settled. Page 6 With the rescission of EITF No. 98-10, energy trading contracts that do not also meet the definition of a derivative under SFAS No. 133 must be accounted for as executory contracts. Contracts previously recorded at fair value under EITF No. 98-10 that are not also derivatives under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, must be restated to historical cost through a cumulative effect adjustment. The rescission of this standard had no impact on financial position or results of operations of LG&E since all contracts marked to market under EITF No. 98-10 are also within the scope of SFAS No. 133. As a result of EITF No. 02-03, LG&E has netted the power purchased expense for trading activities against electric operating revenue to reflect this accounting change. LG&E applied this guidance to all prior periods, which had no impact on previously reported net income or common equity. 2002 2001 Gross electric operating revenues $746,224 $706,645 Less costs reclassified from power purchased 22,449 32,153 Net electric operating revenues reported $723,775 $674,492 Gross power purchased $ 84,330 $ 81,475 Less costs reclassified to revenues 22,449 32,153 Net power purchased reported $ 61,881 $ 49,332 In January 2003, the Financial Accounting Standards Board issued Financial Accounting Standards Board Interpretation No. 46, Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51 (FIN 46). FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. FIN 46 is effective immediately for all new variable interest entities created or acquired after January 31, 2003. For variable interest entities created or acquired prior to February 1, 2003, the provisions of FIN 46 must be applied for the first interim or annual period beginning after June 15, 2003. LG&E does not expect the adoption of this standard to have any impact on the financial position or results of operations. 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 $212.4 million, $287.1 million and $156.2 million in 2002, 2001, and 2000, respectively. The 2002 decrease compared to 2001 of $74.7 million resulted primarily from the change in accounts receivable balances, including the sale of accounts receivable through the accounts receivable securitization program and a decrease in accounts payable and accrued taxes. The 2001 increase of $130.9 million resulted primarily from an increase in accounts receivable, and a decrease in accrued taxes. See Note 1 of LG&E's Notes to Financial Statements under Item 8 for a discussion of accounts receivable securitization. Investing Activities LG&E's primary use of funds for investing activities continues to be for capital expenditures. Capital expenditures were $220.4 million, $253.0 million and $144.2 million in 2002, 2001, and 2000, respectively. LG&E expects its capital expenditures for 2003 and 2004 to total approximately $340.0 million, which consists primarily of construction estimates associated with installation of NOx equipment as described in the section titled "Environmental Matters," purchase of jointly owned CTs with KU and on-going construction for the distribution systems. Page 7 Net cash used for investment activities decreased $28.7 million in 2002 compared to 2001 primarily due to the level of construction expenditures. CT expenditures were approximately $35.9 million in 2002 and $57.8 million in 2001. The $107.9 million increase in net cash used in 2001 as compared to 2000 was due to NOx expenditures and the purchase of CTs. Financing Activities Net cash inflows for financing activities were $22.5 million in 2002 and outflows of $38.7 million and $67.7 million in 2001 and 2000, respectively. In 2002, short-term borrowings increased $98.9 million which were used in part for dividend payments of $73.3 million. During 2001, short-term borrowings decreased $20.4 million from 2000 and LG&E paid $28.0 million in dividends. During 2001, LG&E issued $10.1 million of pollution control bonds resulting in net proceeds of $9.7 million after issuance costs. On March 6, 2002, LG&E refinanced its $22.5 million and $27.5 million unsecured pollution control bonds, both due September 1, 2026. The replacement bonds, due September 1, 2026, are variable rate bonds and are secured by first mortgage bonds. On March 22, 2002, LG&E refinanced its two $35 million unsecured pollution control bonds due November 1, 2027. The replacement variable rate bonds are secured by first mortgage bonds and will mature November 1, 2027. In October 2002, LG&E issued $41.7 million variable rate pollution bonds due October 1, 2032, and exercised its call option on $41.7 million, 6.55% pollution control bonds due November 1, 2020. Under the provisions for LG&E's variable-rate pollution control bonds totaling $246.2 million, 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. 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 future capital requirements through operating cash flow, debt, and/or infusions of capital from its parent. LG&E's debt ratings as of December 31, 2002, were: Moody's S&P Fitch First mortgage bonds A1 A A+ Preferred stock Baa1 BBB A- Commercial paper P-1 A-2 F-1 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. Page 8 Contractual Obligations The following is provided to summarize LG&E's contractual cash obligations for periods after December 31, 2002 (in thousands of $): Payments Due by Period Contractual cash 2004- 2006- After Obligations 2003 2005 2007 2007 Total Short-term debt (a) $193,053 $ - $ - $ - $193,053 Long-term debt (b) 288,800 - - 328,104 616,904 Operating lease (c) 3,371 6,866 7,143 29,794 47,174 Unconditional purchase obligations (d) 10,773 20,268 21,632 184,544 237,217 Other long-term obligations (e) 28,401 95,151 - - 123,552 Total contractual cash obligations (f) $524,398 $122,285 $28,775 $542,442 $1,217,900 (a) Represents borrowings from parent company due within one year. (b) Includes long-term debt of $246.2 million classified as current liabilities because these 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. Maturity dates for these bonds range from 2017 to 2027. (c) Operating lease represents the lease of LG&E's administrative office building. (d) Represents future minimum payments under purchased power agreements through 2020. (e) Represents construction commitments. (f) LG&E does not expect to pay the $246.2 million of long-term debt classified as a current liability in the consolidated balance sheets in 2003 as explained in (b) above. LG&E anticipates cash from operations and external financing will be sufficient to fund future obligations. LG&E anticipates refinancing a portion of its short-term debt with long-term debt in 2003. 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. See Note 1 and 4 of LG&E's Notes to Financial Statements under Item 8. Interest Rate Sensitivity LG&E has short-term and long-term variable rate debt obligations outstanding. At December 31, 2002, the potential change in interest expense associated with a 1% change in base interest rates of LG&E's unhedged debt is estimated at $5.5 million after impact of interest rate swaps. Interest rate swaps are used to hedge LG&E's underlying variable-rate debt obligations. These swaps hedge specific debt issuances and, consistent with management's designation, are accorded hedge accounting treatment. See Note 4 of LG&E's Notes to Financial Statements under Item 8. Page 9 As of December 31, 2002, LG&E had swaps with a combined notional value of $117.3 million. The swaps exchange floating-rate interest payments for fixed rate interest payments to reduce the impact of interest rate changes on LG&E's Pollution Control Bonds. The potential loss in fair value resulting from a hypothetical 1% adverse movement in base interest rates is estimated at $10.8 million as of December 31, 2002. This estimate is derived from third party valuations. Changes in the market value of these swaps if held to maturity, as LG&E intends to do, will have no 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, since its retail tariffs include the FAC and GSC commodity price pass-through mechanisms. LG&E is exposed to market price volatility of fuel and electricity in its wholesale activities. Energy Trading & Risk Management Activities LG&E conducts energy trading and risk management activities to maximize the value of power sales from physical assets it owns, in addition to the wholesale sale of excess asset capacity. Certain energy trading activities are accounted for on a mark-to-market basis in accordance with EITF 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities, SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities. Wholesale sales of excess asset capacity and wholesale purchases are treated as normal sales and purchases under SFAS No. 133 and SFAS No. 138 and are not marked-to-market. The consensus reached by the EITF on EITF No. 02-03, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities, to rescind EITF 98-10, effective for fiscal years after December 15, 2002, had no impact on LG&E's energy trading and risk management reporting as all contracts marked to market under EITF 98-10 are also within the scope of SFAS No. 133 The table below summarizes LG&E's energy trading and risk management activities for 2002 and 2001 (in thousands of $). 2002 2001 Fair value of contracts at beginning of period, net liability $ (186) $ (17) Fair value of contracts when entered into during the period (65) 3,441 Contracts realized or otherwise settled during the period 448 (2,894) Changes in fair values due to changes in assumptions (353) (716) Fair value of contracts at end of period, net liability $ (156) $ (186) No changes to valuation techniques for energy trading and risk management activities occurred during 2002. Changes in market pricing, interest rate and volatility assumptions were made during both years. All contracts outstanding at December 31, 2002, have a maturity of less than one year and are valued using prices actively quoted for proposed or executed transactions or quoted by brokers. LG&E maintains policies intended to minimize credit risk and revalues credit exposures daily to monitor compliance with those policies. At December 31, 2002, 86% of the trading and risk management commitments were with counterparties rated BBB- equivalent or better. Page 10 Accounts Receivable Securitization On February 6, 2001, LG&E implemented an accounts receivable securitization program. The purpose of this program is to enable LG&E to accelerate the receipt of cash from the collection of retail accounts receivable, thereby reducing dependence upon more costly sources of working capital. The securitization program allows for a percentage of eligible receivables to be sold. Eligible receivables are generally all receivables associated with retail sales that have standard terms and are not past due. LG&E is able to terminate the program at any time without penalty. If there is a significant deterioration in the payment record of the receivables by the retail customers or if LG&E fails to meet certain covenants regarding the program, the program may terminate at the election of the financial institutions. In this case, payments from retail customers would first be used to repay the financial institutions participating in the program, and would then be available for use by LG&E. As part of the program, LG&E sold retail accounts receivables to a wholly owned subsidiary, LG&E R. Simultaneously, LG&E R entered into two separate three-year accounts receivable securitization facilities with two financial institutions and their affiliates whereby LG&E R can sell, on a revolving basis, an undivided interest in certain of its receivables and receive up to $75 million from an unrelated third party purchaser. The effective cost of the receivables programs is comparable to LG&E's lowest cost source of capital, and is based on prime rated commercial paper. LG&E retains servicing rights of the sold receivables through two separate servicing agreements with the third party purchaser. LG&E has obtained an opinion from independent legal counsel indicating these transactions qualify as a true sale of receivables. As of December 31, 2002, the outstanding program balance was $63.2 million. LG&E is considering unwinding its accounts receivable securitization arrangements involving LG&E R during 2003. The allowance for doubtful accounts associated with the eligible securitized receivables was $2.1 million at December 31, 2002. This allowance is based on historical experience of LG&E. Each securitization facility contains a fully funded reserve for uncollectible receivables. RATES AND REGULATION Following the purchase of Powergen by E.ON, E.ON became a registered holding company under PUHCA. As a result, E.ON, 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. LG&E believes that it has adequate authority (including financing authority) under existing SEC orders and regulations to conduct its business. LG&E 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, its accounting is subject to SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. Given LG&E's competitive position in the marketplace 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. Page 11 Kentucky Commission Settlement Order - VDT Costs, ESM and Depreciation During the first quarter 2001, LG&E recorded a $144 million charge for a workforce reduction program. Primary components of the charge were separation benefits, enhanced early retirement benefits, and health care benefits. The result of this workforce reduction was the elimination of approximately 700 positions, accomplished primarily through a voluntary enhanced severance program. On June 1, 2001, LG&E filed an application (VDT case) with the Kentucky Commission to create a regulatory asset relating to these first quarter 2001 charges. The application requested permission to amortize these costs over a four-year period. The Kentucky Commission also opened a case to review a new depreciation study and resulting depreciation rates implemented in 2001. LG&E reached a settlement in the VDT case as well as the other cases involving depreciation rates and ESM with all intervening parties. The settlement agreement was approved by Kentucky Commission Order on December 3, 2001. The order allowed LG&E to set up a regulatory asset of $141 million for the workforce reduction costs and begin amortizing these costs over a five-year period starting in April 2001. The first quarter 2001 charge of $144 million represented all employees who had accepted a voluntary enhanced severance program. Some employees rescinded their participation in the voluntary enhanced severance program, thereby decreasing the original charge from $144 million to $141 million. The settlement will also reduce revenues approximately $26 million through a surcredit on future bills to customers over the same five-year period. The surcredit represents stipulated net savings LG&E is expected to realize from implementation of best practices through the VDT. The agreement also established LG&E's new depreciation rates in effect December 2001, retroactive to January 1, 2001. The new depreciation rates decreased depreciation expense by $5.6 million in 2001. Environmental Cost Recovery In June 2000, the Kentucky Commission approved LG&E's application for a CCN to construct up to three SCR 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 2004. 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 in April 2001 allowed 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. In May 2002, the Kentucky Commission initiated a periodic two-year review of LG&E's environmental surcharge. The review included the operation of the surcharge mechanism, determination of the appropriateness of costs included in the surcharge mechanism, recalculation of the cost of debt to reflect actual costs for the period under review, final determination of the amount of environmental revenues over-collected from customers, and a final determination of the amount of environmental costs and revenues to be "rolled-in" to base rates. A final order was issued on October 22, 2002, in which LG&E was ordered to refund $325,000 to customers over the four- month period beginning November 2002 and ending February 2003. Additionally, LG&E was ordered to roll $4.1 million into base rates and make corresponding adjustments to the monthly environmental surcharge filings to reflect that portion of environmental rate base now included in base rates on a going-forward basis. In August 2002, LG&E filed an application with the Kentucky Commission to amend its compliance plan to allow recovery of the cost of new and additional environmental compliance facilities. The estimated capital cost of the additional facilities is $71.1 million. The Kentucky Commission Page 12 conducted a public hearing on the case on December 20, 2002, final briefs were filed on January 15, 2003, and a final order was issued February 11, 2003. The final order approved recovery of four new environmental compliance facilities totaling $43.1 million. A fifth project, expansion of the land fill facility at the Mill Creek Station, was denied without prejudice with an invitation to reapply for recovery when required construction permits are approved. Cost recovery through the environmental surcharge of the four approved projects will begin with the bills rendered in April 2003. ESM LG&E's electric rates are subject to an ESM. The ESM, initially 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, the excess earnings are shared 40% with ratepayers and 60% with shareholders; if earnings are below the lower limit, the earnings deficiency is recovered 40% from ratepayers and 60% from shareholders. By order of the Kentucky Commission, rate changes prompted by the ESM filing go into effect in April of each year subject to a balancing adjustment in successive periods. LG&E made its second ESM filing on March 1, 2002, for the calendar year 2001 reporting period. LG&E is in the process of refunding $441,000 to customers for the 2001 reporting period. LG&E estimated that the rate of return will fall below the lower limit, subject to Kentucky Commission approval, for the year ended December 31, 2002. The 2002 financial statements include an accrual to reflect the earnings deficiency of $12.5 million to be recovered from customers commencing in April 2003. On November 27, 2002, LG&E filed a revised ESM tariff which proposed continuance of the existing ESM through December 2005. The Kentucky Commission issued an Order suspending the ESM tariff one day making the effective date January 2, 2003. In addition, the Kentucky Commission is conducting a management audit to review the ESM plan and reassess its reasonableness in 2003. LG&E and interested parties will have the opportunity to provide recommendations for modification and continuance of the ESM or other forms of alternative or incentive regulation. 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. In May 2001, the Kentucky Commission approved LG&E's plan to continue DSM programs. This filing called for the expansion of the DSM programs into the service territory served by KU and proposed 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 November 1, 1997, LG&E has operated under an experimental PBR mechanism related to its gas procurement activities. For each of the last five years, LG&E's rates have been adjusted to recover its portion of the savings (or expenses) incurred during each of the five 12-month periods beginning November 1 and ending October 31. Since its implementation on November 1, 1997, through October 31, 2002, LG&E has achieved $38.1 million in savings. Of the total savings, LG&E has retained $16.5 million, and the remaining portion of $21.6 million has been distributed to 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 as a result of the benefits provided to both LG&E and its customers during the experimental period. Following the discovery and hearing process, the Kentucky Commission issued an order effective November 1, 2001, extending the experimental PBR program for an additional four years, and making other modifications, including changes to the sharing levels applicable to Page 13 savings or expenses incurred under the PBR. Specifically, the Kentucky Commission modified the sharing mechanism to a 25%/75% Company/Customer sharing for all savings (and expenses) up to 4.5% of the benchmarked gas costs. Savings (and expenses) in excess of 4.5% of the benchmarked gas costs are shared at a 50%/50% level. FAC Prior to implementation of the electric 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. While legal challenges to the Kentucky Commission order were pending a comprehensive settlement was reached by all parties and approved by the Kentucky Commission on May 17, 2002. Thereunder, LG&E agreed to credit its fuel clause in the amount of $720,000 (such credit provided over the course of June and July 2002), and the parties agreed on a prospective interpretation of the state's fuel adjustment clause regulation to ensure consistent and mutually acceptable application on a going-forward basis. In December 2002, the Kentucky Commission initiated a two-year review of the operation of LG&E's FAC for the period November 2000 through October 2002. Testimony in the review case was filed on January 20, 2003 and a public hearing was held February 18, 2003. Issues addressed at that time included the establishment of the current base fuel factor to be included in LG&E's base rates, verification of proper treatment of purchased power costs during unit outages, and compliance with fuel procurement policies and practices. Gas Rate Case In March 2000, LG&E filed an application with the Kentucky Commission requesting an adjustment in LG&E's gas rates. 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 base gas revenues from gas sales. Wholesale Natural Gas Prices On September 12, 2000, the Kentucky Commission issued an order establishing Administrative Case No. 384 - "An Investigation of Increasing Wholesale Natural Gas Prices and the Impacts of such Increase on the Retail Customers Served by Kentucky's Jurisdictional Natural Gas Distribution Companies". The impetus for this administrative proceeding was the escalation of wholesale natural gas prices during the summer of 2000. The Kentucky Commission directed Kentucky's natural gas distribution companies, including LG&E, to file selected information regarding the individual companies' natural gas purchasing practices, expectations for the then-approaching winter heating season of 2000-2001, and potential actions which these companies might take to mitigate price volatility. On July 17, 2001, the Kentucky Commission issued an order encouraging the natural gas distribution companies in Kentucky to take various actions, among them to propose a natural gas hedge plan, consider performance-based ratemaking mechanisms, and to increase the use of storage. In April 2002, in Case No. 2002-00136, LG&E proposed a hedging plan for the 2002/2003 winter heating season with three alternatives, the first two using a combination of storage and financial hedge instruments and the third relying upon storage alone. LG&E and the Attorney General, who represents Kentucky consumers, entered into a settlement which selected the third option. In August 2002, the Kentucky Commission approved the plan contemplated in the settlement. The Kentucky Commission validated the effectiveness of storage to mitigate potentially high winter gas prices by approving this natural gas hedging plan. Page 14 The Kentucky Commission also decided in Administrative Case No. 384 to engage a consultant to conduct a forward-looking audit of the gas procurement and supply procedures of Kentucky's largest natural gas distribution companies. The Kentucky Commission completed its audit in late 2002. The audit recognized LG&E as "efficient and effective [in the] procurement and management of significant quantities of natural gas supplies." The auditors also recognized that "the Company's residential gas prices have long been below averages for the U. S. and for the Commonwealth of Kentucky" which "demonstrates [LG&E's] effectiveness in [the] procurement and management of natural gas supplies." The audit also stated that the "Company's very impressive record in keeping its rates down provides sound evidence on the excellent job done in the area of gas supply procurement and management." 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 intended 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. During the period September 1998 to February 2000, the Kentucky Commission issued draft codes of conduct and cost allocation guidelines. 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. In the same bill, the General Assembly set forth provisions to govern a utility's 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. On February 14, 2001, the Kentucky Commission published notice of their intent to promulgate new administrative regulations under the auspices of the new law. This effort is still on going. Kentucky Commission Administrative Case for System Adequacy On June 19, 2001, Kentucky Governor Paul E. Patton issued Executive Order 2001-771, which directed the Kentucky Commission to review and study issues relating to the need for and development of new electric generating capacity in Kentucky. The issues to be considered included the impact of new power plants on the electric supply grid, facility citing issues, and economic development matters, with the goal of ensuring a continued, reliable source of supply of electricity for the citizens of Kentucky and the continued environmental and economic vitality of Kentucky and its communities. In response to that Executive Order, in July 2001 the Kentucky Commission opened Administrative Case No. 387 to review the adequacy of Kentucky's generation capacity and transmission system. Specifically, the items reviewed were the appropriate level of reliance on purchased power, the appropriate reserve margins to meet existing and future electric demand, the impact of spikes in natural gas prices on electric utility planning strategies, and the adequacy of Kentucky's electric transmission facilities. LG&E, as a party to this proceeding, filed written testimony and responded to two requests for information. Public hearings were held and in October 2001, LG&E filed a final brief in the case. In December 2001, the Kentucky Commission issued an order in which it noted that LG&E is responsibly addressing the long-term supply needs of native load customers and that current reserve margins are appropriate. However, due to the rapid pace of change in the industry, the order also requires LG&E to provide an annual assessment of supply resources, future demand, reserve margin, and the need for new resources. Page 15 Regarding the transmission system, the Kentucky Commission concluded that the transmission system within Kentucky can reliably serve native load and a significant portion of the proposed new unregulated power plants. However, it will not be able to handle the volume of transactions envisioned by FERC without future upgrades, the costs of which should be borne by those for whom the upgrades are required. The Kentucky Commission pledged to continue to monitor all relevant issues and advocate Kentucky's interests at all opportunities. FERC SMD NOPR On July 31, 2002, FERC issued a NOPR in Docket No. RM01-12-000 which would substantially alter the regulations governing the nation's wholesale electricity markets by establishing a common set of rules -- SMD. The SMD NOPR would require each public utility that owns, operates, or controls interstate transmission facilities to become an Independent Transmission Provider (ITP), belong to an RTO that is an ITP, or contract with an ITP for operation of its transmission assets. It would also establish a standardized congestion management system, real-time and day-ahead energy markets, and a single transmission service for network and point-to-point transmission customers. Review of the proposed rulemaking is underway and a final rule is expected during 2003. While it is expected that the SMD final rule will affect LG&E revenues and expenses, the specific impact of the rulemaking is not known at this time. MISO LG&E is a member of the MISO, which began commercial operations on February 1, 2002. MISO now has operational control over LG&E's high-voltage transmission facilities (100 kV and greater), while LG&E continues to control and operate the lower voltage transmission subject to the terms and conditions of the MISO OATT. As a transmission-owning member of MISO, LG&E also incurs administrative costs of MISO pursuant to Schedule 10 of the MISO OATT. MISO also proposed to implement a congestion management system. FERC directed the MISO to coordinate its efforts with FERC's Rulemaking on SMD. On September 24, 2002, the MISO filed new rate schedules designated as Schedules 16 and 17, which provide for the collection of costs incurred by the MISO to establish day-ahead and real-time energy markets. The MISO proposed to recover these costs under Schedules 16 and 17 once service commences. If approved by FERC, these schedules will cause LG&E to incur additional costs. LG&E opposes the establishment of Schedules 16 and 17. This effort is still on-going and the ultimate impact of the two schedules, if approved, is not known at this time. Merger Surcredit As part of the LG&E Energy merger with KU Energy in 1998, LG&E Energy estimated 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 was deferred and 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 approving the merger, the Kentucky Commission adopted LG&E's proposal to reduce its retail customers' bills based on one-half of the estimated merger-related savings, net of deferred and amortized amounts, over a five- year period. The surcredit mechanism provides that 50% of the net non-fuel cost savings estimated to be achieved from the merger be provided to ratepayers through a monthly bill credit, and 50% be retained by the Companies, over a five-year period. The surcredit was allocated 53% to KU and 47% to LG&E. In that same order, the Commission required LG&E and KU, Page 16 after the end of the five-year period, to present a plan for sharing with customers the then-projected non-fuel savings associated with the merger. The Companies submitted this filing on January 13, 2003, proposing to continue to share with customers, on a 50%/50% basis, the estimated fifth- year gross level of non-fuel savings associated with the merger. The filing is currently under review. Any fuel cost savings are passed to Kentucky customers through the fuel adjustment clause. See FAC above. 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 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. As a result of appeals to both rules, the compliance date was extended to May 2004. All LG&E generating units are subject to the May 2004 compliance date under these NOx emissions reduction rules. 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 $178 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 had anticipated that such capital and operating costs are the type of costs that are eligible for recovery from customers under its environmental surcharge mechanism and believed that a significant portion of such costs could be recovered. In April 2001, the Kentucky Commission granted recovery of these costs for LG&E. 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 is in the process of converting the Mill Creek Station to wet stack operation in an effort to resolve all outstanding issues related to particulate matter emissions. Page 17 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 at December 31, 2002 and 2001. See Note 11 of LG&E's Notes to Financial Statements under Item 8 for an additional discussion of environmental issues. Deferred Income Taxes LG&E expects to have adequate levels of taxable income to realize its recorded deferred tax assets. At December 31, 2002, deferred tax assets totaled $98.2 million and were principally related to expenses attributable to LG&E's pension plans and post retirement benefit obligations. FUTURE OUTLOOK Competition and Customer Choice LG&E has moved aggressively over the past decade to be positioned for 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 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. 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. No general restructuring actions have been taken to date by the legislature. 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. Page 18 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 2002, 2001, and 2000 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 materially vary. Factors that could cause actual results to materially differ 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; actions by credit rating agencies; and other factors described from time to time in KU's reports to the SEC, including Exhibit No. 99.01 to the Annual Report. MERGERS and ACQUISITIONS On December 11, 2000, LG&E Energy was acquired by Powergen for cash of approximately $3.2 billion or $24.85 per share and the assumption of all of LG&E Energy's debt. As a result of the acquisition, LG&E Energy became a wholly owned subsidiary of Powergen and, as a result, KU became an indirect subsidiary of Powergen. KU has continued its separate identity and serves customers in Kentucky, Virginia and Tennessee under its existing name. The preferred stock and debt securities of KU were not affected by this transaction and KU continued to file SEC reports. Following the acquisition, 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. On July 1, 2002, E.ON, a German company, completed its acquisition of Powergen plc (now Powergen Limited). As a result, LG&E and KU became indirect subsidiaries of E.ON. E.ON had announced its pre-conditional cash offer of 5.1 billion pounds sterling ($7.3 billion) for Powergen on April 9, 2001. Following the acquisition, E.ON became a registered holding company under PUHCA. As contemplated in their regulatory filings in connection with the E.ON acquisition, E.ON, Powergen and LG&E Energy completed an administrative reorganization to move the LG&E Energy group from an indirect Powergen subsidiary to an indirect E.ON subsidiary. This reorganization was effective in March 2003. RESULTS OF OPERATIONS Net Income KU's net income in 2002 decreased $3.0 million compared to 2001. The decrease resulted primarily from higher transmission operating expenses, an increase in amortization of regulatory assets, and increased property insurance, partially offset by an increase in sales to retail customers and lower interest expenses. Page 19 KU's net income in 2001 was relatively flat as compared to 2000 with an increase of $.9 million. The increase resulted primarily from decreased depreciation, interest expenses and property and other taxes, partially offset by higher pension related expenses and amortization of regulatory assets. Revenues A comparison of operating revenues for the years 2002 and 2001, excluding the provision for rate collections (refunds), 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 2002 2001 Retail sales: Fuel clause adjustments $ 18,223 $ 10,220 KU/LG&E Merger surcredit (2,641) (3,856) Environmental cost recovery surcharge 3,781 1,458 Demand side management 1,570 - Performance based rate - 1,747 Electric rate reduction - (5,395) VDT surcredit (527) (372) Variation in sales volumes, and other 46,601 (1,627) Total retail sales 67,007 2,175 Wholesale sales (47,178) 24,889 Other 7,132 1,202 Total $ 26,961 $ 28,266 Electric revenues increased in 2002 primarily due to an increase in retail sales due to warmer weather and an increase in the recovery of fuel costs passed through the FAC. Cooling degree days for 2002 increased 26% over 2001. The increase in retail sales was partially offset by a decrease in wholesale sales volumes. The decrease in wholesale sales was due in large part to fewer megawatts available due to increased retail sales. Electric revenues increased in 2001 primarily due to an increase in wholesale activity and an increase in the recovery of fuel costs passed through the FAC partially offset by a rate reduction ordered by Kentucky Commission in 2000 and lower sales volumes. Expenses Fuel for electric generation comprises a large component of KU's total operating expenses. KU's Kentucky jurisdictional electric rates are subject to a FAC whereby increases or decreases are reflected in the FAC factor, subject to the approval of the Kentucky Commission. 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 FERC and the Virginia Commission, respectively. Fuel for electric generation increased $13.1 million (5.5%) in 2002 because of an increase in the cost of coal burned ($29.7 million), partially offset by a decrease in generation ($16.5 million). Fuel for electric generation increased $17.1 million (7.8%) in 2001 because of an increase in the cost of coal burned ($21.8 million), partially offset by a decrease in generation ($4.7 million). The average delivered cost per ton of coal purchased was $31.44 in 2002, $27.84 in 2001 and $25.63 in 2000. Power purchased expense increased $13.0 million (11.0%) in 2002 primarily due to an increase in purchases to meet requirements for native load partially offset by a decrease in purchase price. Power purchased expense increased $10.0 million (9.3%) in 2001 primarily due to an increase in purchases to meet requirements for native load partially offset by a decrease in purchase price. Page 20 Other operation expenses increased $25.8 million (21.8%) in 2002. The primary cause for the increase was the full year amortization in 2002 of a regulatory asset created as a result of the workforce reduction associated with KU's VDT of $6.5 million, higher costs for electric transmission primarily resulting from increased MISO costs of $7.4 million, an increase in property insurance costs of $2.8 million, an increase in employee benefit costs due to changes in pension assumptions to reflect current market conditions and changes in market value of plan assets at the measurement date of $1.7 million, and an increase in outside services of $4.9 million. Other operation expenses increased $10.3 million (9.5%) in 2001. The primary cause for the increase was the amortization of a regulatory asset as a result of the workforce reduction associated with KU's VDT of $5.0 million and an increase in pension expense of $5.5 million. Maintenance expenses increased $5.9 million (10.3%) in 2002 primarily due to increases in steam maintenance of $6.1 million related to annual outages at the Ghent, Green River, and Tyrone steam facilities. Maintenance expenses for 2001 decreased $4.6 million (7.5%) primarily due to decreased repairs to steam facilities ($6.5 million). Depreciation and amortization increased $5.2 million (5.7%) in 2002 primarily due to an increase in plant in service. Depreciation and amortization decreased $8.0 million (8.1%) in 2001 primarily due to a reduction in depreciation rates as a result of a settlement order in December 2001 from the Kentucky Commission. Depreciation expenses decreased by $6.0 million as a result of the settlement order. Variations in income tax expense are largely attributable to changes in pre- tax income. The 2002 effective income tax rate decreased to 34.9% from the 35.9% rate in 2001. See Note 7 of KU's Notes to Financial Statements under Item 8. Property and other taxes increased $1.1 million (7.6%) in 2002 due to higher property taxes and payroll taxes. Property and other taxes decreased $3.1 million (18.2%) in 2001 due to decreases in payroll taxes related to fewer employees as a result of workforce reductions and transfers to LG&E Energy Services Company. Other income-net increased $1.5 million (16.8%) in 2002 primarily due to a non-recurring increase in earnings from KU's equity earnings in a minority interest of $5.2 million, partially offset by a gain on disposition of property in 2001, $1.8 million, lower interest and dividend income from investments, $0.7 million, and higher benefit and other costs, $1.4 million. The increased equity earnings in 2002 are due to the gain on the sale of emissions allowances. Other income-net increased $2.1 million (30.5%) in 2001 due to an increase in the gain on sale of assets. Interest charges decreased $8.3 million (24.5%) in 2002 as compared to 2001 due to lower interest rates on variable rate debt and refinancing of long term debt with lower interest rates, $8.0 million. Interest charges decreased $5.4 million (13.7%) in 2001 from 2000 due to lower interest rates on variable rate debt, $4.6 million, the retirement of short-term borrowings, $1.6 million, lower interest on debt to parent company, $1.2 million, partially offset by an increase in interest associated with KU's accounts receivable securitization program, $1.8 million. KU's weighted average cost of long-term debt, including amortization of debt expense and interest rate swaps, was 3.30% at December 31, 2002 compared to 4.91% at December 31, 2001. See Note 9 of KU's Notes to Financial Statements under Item 8. 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. Page 21 CRITICAL ACCOUNTING POLICIES/ESTIMATES Preparation of financial statements and related disclosures in compliance with generally accepted accounting principles requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. The application of these policies necessarily involves judgments regarding future events, including legal and regulatory challenges and anticipated recovery of costs. These judgments, in and of themselves, could materially impact the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment also may have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies applied has not changed. Specific risks for these critical accounting policies are described in the following paragraphs. Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions. Events rarely develop exactly as forecast and the best estimates routinely require adjustment. See also Note 1 of KU's Notes to Financial Statements under Item 8. Unbilled Revenue - At each month end KU prepares a financial estimate that projects electric usage that has been used by customers, but not billed. The estimated usage is based on known weather and days not billed. At December 31, 2002, a 10% change in these estimated quantities would cause revenue and accounts receivable to change by approximately $4.2 million. See also Note 1 of KU's Notes to Financial Statements under Item 8. Benefit Plan Accounting - Judgments and uncertainties in benefit plan accounting include future rate of returns on pension plan assets, interest rates used in valuing benefit obligation, healthcare cost trend rates and other actuarial assumptions. KU's costs of providing defined-benefit pension retirement plans is dependent upon a number of factors, such as the rates of return on plan assets, discount rate, and contributions made to the plan. The market value of KU plan assets has been affected by declines in the equity market since the beginning of the fiscal year. As a result, at December 31, 2002, KU was required to recognize an additional minimum liability as prescribed by SFAS No. 87 Employers' Accounting for Pensions. The liability was recorded as a reduction to other comprehensive income, and did not affect net income for 2002. The amount of the liability depended upon the asset returns experienced in 2002 and contributions made by KU to the plan during 2002. Also, pension cost and cash contributions to the plan could increase in future years without a substantial recovery in the equity market. If the fair value of the plan assets exceeds the accumulated benefit obligation, the recorded liability will be reduced and other comprehensive income will be restored in the consolidated balance sheet. The combination of poor market performance and a decrease in short-term corporate bond interest rates has created a divergence in the potential value of the pension liability and the actual value of the pension assets. These conditions could result in an increase in KU's funded accumulated benefit obligation and future pension expense. The primary assumptions that drive the value of the unfunded accumulated benefit obligation are the discount rate and expected return on plan assets. KU made a contribution to the pension plan of $3.5 million in January 2003. A 1% increase or decrease in the assumed discount rate could have an approximate $26.0 million positive or negative impact to the accumulated benefit obligation of KU. See also Note 6 of KU's Notes to Financial Statements under Item 8. Page 22 Regulatory Mechanisms - Judgments and uncertainties include future regulatory decisions, the impact of deregulation and competition on the ratemaking process and external regulator decisions. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates based upon Kentucky Commission orders. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections based upon orders by the Kentucky Commission. Management believes, based on orders, the existing regulatory assets and liabilities are probable of recovery. This determination reflects the current regulatory climate in the state. If future recovery of costs ceases to be probable the assets would be required to be recognized in current period earnings. KU has accrued in the financial statements, an estimate of $13.5 million for 2002 ESM, with collection from customers commencing in April 2003. The ESM is subject to Kentucky Commission approval. See also Note 3 of KU's Notes to Financial Statements under Item 8. NEW ACCOUNTING PRONOUNCEMENTS SFAS No. 143, Accounting for Asset Retirement Obligations was issued in 2001. SFAS No. 143 establishes accounting and reporting standards for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The effective implementation date for SFAS No. 143 is January 1, 2003. Management has calculated the impact of SFAS No. 143 and the recently released FERC NOPR No. RM02-7, Accounting, Financial Reporting, and Rate Filing Requirements for Asset Retirement Obligations. As of January 1, 2003, KU recorded asset retirement obligation (ARO) assets in the amount of $8.6 million and liabilities in the amount of $18.5 million. KU also recorded a cumulative effect adjustment in the amount of $9.9 million to reflect the accumulated depreciation and accretion of ARO assets at the transition date less amounts previously accrued under regulatory depreciation. KU recorded offsetting regulatory assets of $9.9 million, pursuant to regulatory treatment prescribed under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. Also pursuant to SFAS No. 71, KU recorded regulatory liabilities in the amount of $888,000 offsetting removal costs previously accrued under regulatory accounting in excess of amounts allowed under SFAS No. 143. KU also expects to record ARO accretion expense of approximately $1.2 million, ARO depreciation expense of approximately $176,000 and an offsetting regulatory credit in the income statement of approximately $1.4 million in 2003, pursuant to regulatory treatment prescribed under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. The accretion, depreciation and regulatory credit will be annual adjustments. SFAS No. 143 will have no impact on the results of the operation of KU. KU asset retirement obligations are primarily related to the final retirement of generating units. KU transmission and distribution lines largely operate under perpetual property easement agreements which do not generally require restoration upon removal of the property. Therefore, under SFAS No. 143, no material asset retirement obligations will be recorded for transmission and distribution assets. KU adopted EITF No. 98-10, Accounting for Energy Trading and Risk Management Activities, effective January 1, 1999. This pronouncement required that energy trading contracts be marked to market on the balance sheet, with the gains and losses shown net in the income statement. Page 23 The EITF clarified accounting standards related to energy trading activities under EITF Issue 02-03, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities. EITF No. 02-03 established the following: - Rescinded EITF No. 98-10, - Contracts that do not meet the definition of a derivative under SFAS No.133 should not be marked to fair market value, and - Revenues should be shown in the income statement net of costs associated with trading activities, whether or not the trades are physically settled. With the rescission of EITF No. 98-10, energy trading contracts that do not also meet the definition of a derivative under SFAS No. 133 must be accounted for as executory contracts. Contracts previously recorded at fair value under EITF No. 98-10 that are not also derivatives under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, must be restated to historical cost through a cumulative effect adjustment. The rescission of this standard had no impact on financial position or results of operations of KU since all contracts marked to market under EITF No. 98- 10 are also within the scope of SFAS No. 133. As a result of EITF No. 02-03, KU has netted the power purchased expense for trading activities against electric operating revenue to reflect this accounting change. KU applied this guidance to all prior periods, which had no impact on previously reported net income or common equity. 2002 2001 Gross electric operating revenues $875,192 $860,426 Less costs reclassified from power purchased 26,555 38,751 Net electric operating revenues reported $848,637 $821,675 Gross power purchased $157,955 $157,161 Less costs reclassified to revenues 26,555 38,751 Net power purchased reported $131,400 $118,410 In January 2003, the Financial Accounting Standards Board issued Financial Accounting Standards Board Interpretation No. 46, Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51 (FIN 46). FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. FIN 46 is effective immediately for all new variable interest entities created or acquired after January 31, 2003. For variable interest entities created or acquired prior to February 1, 2003, the provisions of FIN 46 must be applied for the first interim or annual period beginning after June 15, 2003. KU does not expect the adoption of this standard to have any impact on the financial position or results of operations. 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 $175.8 million, $188.1 million and $176.3 million in 2002, 2001 and 2000, respectively. The 2002 decrease from 2001 of $12.3 million was primarily the result of a decrease in accrued taxes and changes in accounts receivable. The 2001 increase resulted from sale of accounts receivable through a securitization program. See Note 1 of KU's Notes to Financial Statements under Item 8 for a discussion of accounts receivable securitization. Page 24 Investing Activities KU's primary use of funds for investing activities continues to be for capital expenditures. Capital expenditures were $237.9 million, $142.4 million and $100.3 million in 2002, 2001 and 2000, respectively. KU expects its capital expenditures for 2003 and 2004 will total approximately $550.0 million, which consists primarily of construction costs associated with installation of NOx equipment as described in the section titled "Environmental Matters," purchase of jointly owned CTs with LG&E and on going construction for the distribution system. Net cash used for investment activities increased $99.0 million in 2002 compared to 2001 and $38.6 million in 2001 compared to 2000 primarily due to the level of construction expenditures. NOx expenditures increased $50.6 million and CT expenditures increased $27.0 million in 2002. Financing Activities Net cash inflows from financing activities were $64.2 million in 2002 and outflows of $46.2 million and $82.4 million in 2001 and 2000, respectively. In 2002, short-term debt increased $72.0 million from 2001. In 2001, short- term debt decreased $13.4 million from 2000 and KU paid $32.8 million in dividends. In May 2002, KU issued $37.93 million variable rate pollution control Series 12, 13, 14 and 15 due February 1, 2032, and exercised its call option on $37.93 million, 6.25% pollution control Series 1B, 2B, 3B, and 4B due February 1, 2018. In September 2002, KU issued $96 million variable rate pollution control Series 16 due October 1, 2032, and exercised its call option on $96 million, 7.45% pollution control Series 8 due September 15, 2016. 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 future capital requirements through operating cash flow, debt, and/or infusion of capital from its parent. KU's debt ratings as of December 31, 2002, were: Moody's S&P Fitch First mortgage bonds A1 A A+ Preferred stock Baa1 BBB A- Commercial paper P-1 A-2 F-1 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. Page 25 Contractual Obligations The following is provided to summarize KU's contractual cash obligations for periods after December 31, 2002 (in thousands of $): Payments Due by Period Contractual cash 2004- 2006- After Obligations 20032005 2007 2007 Total Short-term debt (a) $119,490 $ - $ - $ - $ 119,490 Long-term debt (b) 153,930 - 89,000 257,562 500,492 Unconditional purchase obligations (c) 34,317 79,306 79,878 643,946 837,447 Other long-term obligations (d) 128,199 201,249 - - 329,448 Total contractual cash obligations (e) $435,936 $280,555 $168,878 $901,508 $1,786,877 (a) Represents borrowings from parent company due within one year. (b) Includes long-term debt of $91.9 million is classified as a current liability because 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. Maturity dates for the bonds range from 2024 to 2032. (c) Represents future minimum payments under purchased power agreements through 2020. (d) Represents construction commitments. (e) KU does not expect to pay the $91.9 million of long-term debt classified as a current liability in the consolidated balance sheets in 2003 as explained in (b) above. KU anticipates cash from operations and external financing will be sufficient to fund future obligations. KU anticipates refinancing a portion of its short-term debt with long-term debt in 2003. 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. See Notes 1 and 4 of KU's Notes to Financial Statements under Item 8. Interest Rate Sensitivity KU has short-term and long-term variable rate debt obligations outstanding. At December 31, 2002, the potential change in interest expense associated with a 1% change in base interest rates of KU's variable rate debt is estimated at $5.2 million after impact of interest rate swaps. 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, 2002, KU has swaps with a combined notional value of $153 million. The swaps exchange fixed-rate interest payments for floating rate interest payments on KU's Series P, R, and PCS-9 Bonds. The potential loss in fair value resulting from a hypothetical 1% adverse movement in base interest rates is estimated at $6.9 million as of December 31, 2002. This estimate is derived from third party valuations. 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, since its retail tariffs include the FAC commodity price pass- through mechanism. KU is exposed to market price volatility of fuel and electricity in its wholesale activities. Page 26 Energy Trading & Risk Management Activities KU conducts energy trading and risk management activities to maximize the value of power sales from physical assets it owns, in addition to the wholesale sale of excess asset capacity. Certain energy trading activities are accounted for on a mark-to-market basis in accordance with EITF 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities, SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities. Wholesale sales of excess asset capacity and wholesale purchases are treated as normal sales and purchases under SFAS No. 133 and SFAS No. 138 and are not marked-to-market. The consensus reached by the EITF on EITF No. 02-03, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities, to rescind EITF 98-10, effective for fiscal years after December 15, 2002, had no impact on KU's energy trading and risk management reporting as all contracts marked to market under EITF 98-10 are also within the scope of SFAS No. 133. The table below summarizes KU's energy trading and risk management activities for 2002 and 2001(in thousands of $). 2002 2001 Fair value of contracts at beginning of period, net liability $ (186) $ (17) Fair value of contracts when entered into during the period (65) 3,441 Contracts realized or otherwise settled during the period 448 (2,894) Changes in fair values due to changes in assumptions (353) (716) Fair value of contracts at end of period, net liability $ (156) $ (186) No changes to valuation techniques for energy trading and risk management activities occurred during 2002. Changes in market pricing, interest rate and volatility assumptions were made during both years. All contracts outstanding at December 31, 2002 have a maturity of less than one year and are valued using prices actively quoted for proposed or executed transactions or quoted by brokers. KU maintains policies intended to minimize credit risk and revalues credit exposures daily to monitor compliance with those policies. At December 31, 2002, 86% of the trading and risk management commitments were with counterparties rated BBB- equivalent or better. Accounts Receivable Securitization On February 6, 2001, KU implemented an accounts receivable securitization program. The purpose of this program is to enable KU to accelerate the receipt of cash from the collection of retail accounts receivable, thereby reducing dependence upon more costly sources of working capital. The securitization program allows for a percentage of eligible receivables to be sold. Eligible receivables are generally all receivables associated with retail sales that have standard terms and are not past due. KU is able to terminate this program at any time without penalty. If there is a significant deterioration in the payment record of the receivables by the retail customers or if KU fails to meet certain covenants regarding the program, the program may terminate at the election of the financial institutions. In this case, payments from retail customers would first be used to repay the financial institutions participating in the program, and would then be available for use by KU. Page 27 As part of the program, KU sold retail accounts receivables to a wholly owned subsidiary KU R. Simultaneously, KU R entered into two separate three-year accounts receivable securitization facilities with two financial institutions and their affiliates whereby KU R can sell, on a revolving basis, an undivided interest in certain of their receivables and receive up to $50 million from an unrelated third party purchaser. The effective cost of the receivables programs is comparable to KU's lowest cost source of capital, and is based on prime rated commercial paper. KU retains servicing rights of the sold receivables through two separate servicing agreements with the third party purchaser. KU has obtained an opinion from independent legal counsel indicating these transactions qualify as a true sale of receivables. As of December 31, 2002, the outstanding program balance was $49.3 million. KU is considering unwinding the accounts receivable securitization arrangements involving KU R during 2003. The allowance for doubtful accounts associated with the eligible securitized receivables was $520,000 at December 31, 2002. This allowance is based on historical experience of KU. Each securitization facility contains a fully funded reserve for uncollectible receivables. RATES AND REGULATION Following the purchase of Powergen by E.ON, E.ON became a registered holding company under PUHCA. As a result, E.ON, 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. KU believes that it has adequate authority (including financing authority) under existing SEC orders and regulations to conduct its business. KU 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. Kentucky Commission Settlement Order - VDT Costs, ESM and Depreciation During the first quarter 2001, KU recorded a $64 million charge for a workforce reduction program. Primary components of the charge were separation benefits, enhanced early retirement benefits, and health care benefits. The result of this workforce reduction was the elimination of approximately 300 positions, accomplished primarily through a voluntary enhanced severance program. On June 1, 2001, KU filed an application (VDT case) with the Kentucky Commission to create a regulatory asset relating to these first quarter 2001 charges. The application requested permission to amortize these costs over a four-year period. The Kentucky Commission also opened a case to review the new depreciation study and resulting depreciation rates implemented in 2001. KU reached a settlement in the VDT case as well as the other cases involving depreciation rates and ESM with all intervening parties. The settlement agreement was approved by the Kentucky Commission on December 3, 2001. The order allowed KU to set up a regulatory asset of $54 million for the workforce reduction costs and begin amortizing these costs over a five year period starting in April 2001. The first quarter 2001 charge of $64 million represented all employees who had accepted a voluntary enhanced severance program. Some employees rescinded their participation in the voluntary enhanced severance program and, along with the non-recurring charge of $6.9 million for FERC and Virginia jurisdictions, thereby decreasing the original charge of the regulatory asset from $64 million to $54 million. The settlement will also reduce revenues approximately $11 million through a surcredit on future bills to customers over the same five year period. The surcredit represents stipulated net savings KU is expected to realize from implementation of best practices through the VDT. The agreement also established KU's new depreciation rates in effect December 2001, retroactive to January 1, 2001. The new depreciation rates decreased depreciation expense by $6.0 million in 2001. Page 28 Environmental Cost Recovery In June 2000, the Kentucky Commission approved KU's application for a CCN to construct up to four SCR 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 2004. 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 in April 2001, allowed 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. In August 2002, KU filed an application with the Kentucky Commission to amend its compliance plan to allow recovery of the cost of a new and additional environmental compliance facility. The estimated capital cost of the additional facilities is $17.3 million. The Kentucky Commission conducted a public hearing on the case on December 20, 2002, final briefs were filed on January 15, 2003, and a final order was issued February 11, 2003. The final order approved recovery of the new environmental compliance facility totaling $17.3 million. Cost recovery through the environmental surcharge of the approved project will begin with bills rendered in April 2003. ESM KU's electric rates are subject to an ESM. The ESM, initially 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, the excess earnings are shared 40% with ratepayers and 60% with shareholders; if earnings are below the lower limit, the earnings deficiency is recovered 40% from ratepayers and 60% from shareholders. By order of the Kentucky Commission, rate changes prompted by the ESM filing go into effect in April of each year subject to a balancing adjustment in successive periods. KU made its second ESM filing on March 1, 2002 for the calendar year 2001 reporting period. KU is in the process of refunding $1 million to customers for the 2001 reporting period. KU estimated that the rate of return will fall below the lower limit, subject to Kentucky Commission approval, for the year ended December 31, 2002. The 2002 financial statements include an accrual to reflect the earnings deficiency of $13.5 million to be recovered from customers commencing in April 2003. On November 27, 2002, KU filed a revised ESM tariff which proposed continuance of the existing ESM through December 2005. The Kentucky Commission issued an Order suspending the ESM tariff one day making the effective date January 2, 2003. In addition, the Kentucky Commission is conducting a management audit to review the ESM plan and reassess its reasonableness in 2003. KU and interested parties will have the opportunity to provide recommendations for modification and continuance of the ESM or other forms of alternative or incentive regulation. DSM In May 2001, the Kentucky Commission approved a plan that would expand LG&E's current DSM programs into the service territory served by KU. The filing included a rate mechanism that provided for concurrent recovery of DSM costs, provided an incentive for implementing DSM programs, and recovered revenues from lost sales associated with the DSM program based on program planning engineering estimates and post-implementation evaluations. Page 29 FAC KU employs an FAC mechanism, which allows KU 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. In August 1999, after a rehearing request by KU, the Kentucky Commission issued a final order that reduced the refund obligation to $ 6.7 million ($5.8 million on Kentucky jurisdictional basis) from the original order amount of $10.1 million. KU implemented the refund from October 1999 through September 2000. Both KU and the KIUC appealed the order. Pending a decision on this appeal, a comprehensive settlement was reached by all parties and approved by the Kentucky Commission on May 17, 2002. Thereunder, KU agreed to credit its fuel clause in the amount of $954,000 (refund made in June and July 2002), and the parties agreed on a prospective interpretation of the state's fuel adjustment clause regulation to ensure consistent and mutually acceptable application on a going-forward basis. In December 2002, the Kentucky Commission initiated a two year review of the operation of KU's fuel adjustment clause for the period November 2000 through October 2002. Testimony in the review case was filed on January 20, 2003 and a public hearing was held February 18, 2003. Issues addressed at that time included the establishment of the current base fuel factor to be included in KU's base rates, verification of proper treatment of purchased power costs during unit outages, and compliance with fuel procurement policies and practices. In January 2003, the Kentucky Commission reviewed the FAC of KU for the six month period ended October 31, 2001. The Kentucky Commission ordered KU to reduce its fuel costs for purposes of calculating its FAC by $673,000. At issue was the purchase of approximately 102,000 tons of coal from Western Kentucky Energy Corporation, a non-regulated affiliate, for use at KU's Ghent Facility. The Kentucky Commission further ordered that an independent audit be conducted to examine operational and management aspects of KU's fuel procurement functions. Page 30 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 intended 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. During the period September 1998 to February 2000, the Kentucky Commission issued draft codes of conduct and cost allocation guidelines. In early 2000, the Kentucky General Assembly enacted legislation, House Bill 897, which authorized the Kentucky Commission to require utilities that provide nonregulated activities to keep separate accounts and allocate costs in accordance with procedures established by the Kentucky Commission. In the same bill, the General Assembly set forth provisions to govern a utility's 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. On February 14, 2001, the Kentucky Commission published notice of their intent to promulgate new administrative regulation under the auspices of the new law. This effort is still on going. Kentucky Commission Administrative Case for System Adequacy On June 19, 2001, Kentucky Governor Paul E. Patton issued Executive Order 2001-771, which directed the Kentucky Commission to review and study issues relating to the need for and development of new electric generating capacity in Kentucky. The issues to be considered included the impact of new power plants on the electric supply grid, facility siting issues, and economic development matters, with the goal of ensuring a continued, reliable source of supply of electricity for the citizens of Kentucky and the continued environmental and economic vitality of Kentucky and its communities. In response to that Executive Order, in July 2001 the Kentucky Commission opened Administrative Case No. 387 to review the adequacy of Kentucky's generation capacity and transmission system. Specifically, the items reviewed were the appropriate level of reliance on purchased power, the appropriate reserve margins to meet existing and future electric demand, the impact of spikes in natural gas prices on electric utility planning strategies, and the adequacy of Kentucky's electric transmission facilities. KU, as a party to this proceeding, filed written testimony and responded to two requests for information. Public hearings were held and in October 2001, KU filed a final brief in the case. In December 2001, the Kentucky Commission issued an order in which it noted that KU is responsibly addressing the long-term supply needs of native load customers and that current reserve margins are appropriate. However, due to the rapid pace of change in the industry, the order also requires KU to provide an annual assessment of supply resources, future demand, reserve margin, and the need for new resources. Regarding the transmission system, the Kentucky Commission concluded that the transmission system within Kentucky can reliably serve native load and a significant portion of the proposed new unregulated power plants. However, it will not be able to handle the volume of transactions envisioned by FERC without future upgrades, the costs of which should be borne by those for whom the upgrades are required. The Kentucky Commission pledged to continue to monitor all relevant issues and advocate Kentucky's interests at all opportunities. FERC SMD NOPR On July 31, 2002, the FERC issued a NOPR in Docket No. RM01-12-000 which would substantially alter the regulations governing the nation's wholesale electricity markets by establishing a common set of rules -- SMD. The SMD NOPR would require each public utility that owns, operates, or controls interstate transmission facilities to become an Independent Transmission Provider (ITP), belong to an RTO that is an ITP, or contract with an ITP for operation of its transmission assets. It would also establish a standardized congestion management system, real-time and day-ahead energy markets, and a single transmission service for network and point-to-point transmission customers. Review of the proposed rulemaking is underway and a final rule is expected during 2003. While it is expected that the SMD final rule will affect KU revenues and expenses, the specific impact of the rulemaking is not known at this time. MISO KU is a member of the MISO, which began commercial operations on February 1, 2002. MISO now has operational control over KU's high-voltage transmission facilities (100 kV and greater), while KU continues to control and operate the lower voltage transmission subject to the terms and conditions of the MISO OATT. As a transmission-owning member of MISO, KU also incurs administrative costs of MISO pursuant to Schedule 10 of the MISO OATT. MISO also proposed to implement a congestion management system. FERC directed the MISO to coordinate its efforts with FERC's Rulemaking on SMD. On September 24, 2002, the MISO filed new rate schedules designated as Schedules 16 and 17, which provide for the collection of costs incurred by the MISO to establish day-ahead and real-time energy markets. The MISO proposed to recover these costs under Schedules 16 and 17 once service commences. If approved by FERC, these schedules will cause KU to incur additional costs. KU opposes the establishment of Schedules 16 and 17. This effort is still on-going and the ultimate impact of the two schedules, if approved, is not known at this time. Page 31 Merger Surcredit As part of the LG&E Energy merger with KU Energy in 1998, LG&E Energy estimated 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 was deferred and 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) in the second quarter of 1998. In approving the merger, the Kentucky Commission adopted KU's proposal to reduce its retail customers' bills based on one-half of the estimated merger-related savings, net of deferred and amortized amounts, over a five- year period. The surcredit mechanism provides that 50% of the net non-fuel cost savings estimated to be achieved from the merger be provided to ratepayers through a monthly bill credit, and 50% be retained by the Companies, over a five-year period. The surcredit was allocated 53% to KU and 47% to LG&E. In that same order, the Commission required LG&E and KU, after the end of the five-year period, to present a plan for sharing with customers the then-projected non-fuel savings associated with the merger. The Companies submitted this filing on January 13, 2003, proposing to continue to share with customers, on a 50%/50% basis, the estimated fifth- year gross level of non-fuel savings associated with the merger. The filing is currently under review. Any fuel cost savings are passed to Kentucky customers through the fuel adjustment clause. See FAC above. 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 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. As a result of appeals to both rules, the compliance date was extended to May 2004. All KU generating units are subject to the May 2004 compliance date under these NOx emissions reduction rules. Page 32 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 $232 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 had anticipated that such capital and operating costs are the type of costs that are eligible for recovery from customers under its environmental surcharge mechanism and believed that a significant portion of such costs could be recovered. In April 2001, the Kentucky Commission granted recovery of these costs for KU. KU 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. KU owns or formerly owned several properties that 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 incurred costs of approximately $1.8 million and received insurance reimbursement of $1.2 million. In December 2002, the Department of Justice (DOJ) sent correspondence to KU regarding a potential per-day fine for failure to timely submit a spill control plan and a per-gallon fine for the amount of oil discharged. KU and the DOJ have commenced settlement discussions using existing DOJ settlement guidelines on this matter. In April 2002, the EPA sent correspondence to KU regarding potential exposure in connection with $1.5 million in completed remediation costs associated with a transformer scrap-yard. KU believes it is one of the more remote among a number of potentially responsible parties and has entered into settlement discussions with the EPA on this matter. See Note 11 of KU's Notes to Financial Statements under Item 8 for an additional discussion of environmental issues. Deferred Income Taxes KU expects to have adequate levels of taxable income to realize its recorded deferred tax assets. At December 31, 2002, deferred tax assets totaled $61 million and were principally related to expenses attributable to KU's pension plans and post retirement benefit obligations. Page 33 FUTURE OUTLOOK Competition and Customer Choice KU has moved aggressively over the past decade to be positioned for 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. 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. No general industry restructuring actions have been taken to date by the legislature. 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. Virginia has enacted a phase-in of customer choice through the Virginia Electric Restructuring Act. The Virginia Commission is promulgating regulations to govern the various activities required by the Act. KU filed unbundled rates that became effective January 1, 2002. KU was granted a waiver from the Virginia Commission on October 29, 2002, exempting KU from retail choice through December 31, 2004. KU is also seeking a permanent legislative exemption to the Virginia Electric Restructuring Act. The outcome of such legislative initiatives will not be known until mid-2003. Page 34 Exhibit 99(d) ITEM 8. Financial Statements and Supplementary Data. INDEX OF ABBREVIATIONS Capital Corp. LG&E Capital Corp. Clean Air Act The Clean Air Act, as amended in 1990 CCN 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 E.ON E.ON AG EPA U.S. Environmental Protection Agency ESM Earnings Sharing Mechanism F Fahrenheit FAC Fuel Adjustment Clause FERC Federal Energy Regulatory Commission FPA Federal Power Act FT and FT-A Firm Transportation GSC Gas Supply Clause 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 KU R KU Receivables LLC kV Kilovolts Kva Kilovolt-ampere KW Kilowatts Kwh Kilowatt hours LEM LG&E Energy Marketing Inc. LG&E Louisville Gas and Electric Company LG&E Energy LG&E Energy Corp. LG&E R LG&E Receivables LLC LG&E Services LG&E Energy Services Inc. Mcf Thousand Cubic Feet MGP Manufactured Gas Plant MISO Midwest Independent System Operator Mmbtu Million British thermal units Moody's Moody's Investor Services, Inc. Mw Megawatts Mwh Megawatt hours NNS No-Notice Service NOPR Notice of Proposed Rulemaking NOx Nitrogen Oxide OATT Open Access Transmission Tariff OMU Owensboro Municipal Utilities OVEC Ohio Valley Electric Corporation PBR Performance-Based Ratemaking PJM Pennsylvania, New Jersey, Maryland Interconnection Powergen Powergen Limited (formerly Powergen plc) PUHCA Public Utility Holding Company Act of 1935 ROE Return on Equity Page 1 RTO Regional Transmission Organization 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 SMD Standard Market Design SO2 Sulfur Dioxide 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 VDT Value Delivery Team Process Virginia Commission Virginia State Corporation Commission Virginia Staff Virginia State Corporation Commission Staff Page 2 Louisville Gas and Electric Company and Subsidiary Consolidated Statements of Income (Thousands of $) Years Ended December 31 2002 2001 OPERATING REVENUES: Electric $ 723,775 $ 674,492 Gas 267,693 290,775 Provision for rate collections (refunds) (Note 3) 12,267 (720) Total operating revenues (Note 1) 1,003,735 964,547 OPERATING EXPENSES: Fuel for electric generation 194,900 159,231 Power purchased 61,881 49,322 Gas supply expenses 182,108 206,165 Other operation expenses 208,322 167,818 Maintenance 60,210 58,687 Depreciation and amortization (Note 1) 105,906 100,356 Federal and state income taxes (Note 7) 55,035 63,452 Property and other taxes 17,459 17,743 Total operating expenses 885,821 822,774 Net operating income 117,914 141,773 Other income - net (Note 8) 820 2,930 Interest charges 29,805 37,922 Net income 88,929 106,781 Preferred stock dividends 4,246 4,739 Net income available for common stock $ 84,683 $ 102,042 Consolidated Statements of Retained Earnings (Thousands of $) Years Ended December 31 2002 2001 Balance January 1 $393,636 $314,594 Add net income 88,929 106,781 482,565 421,375 Deduct: Cash dividends declared on stock: 5% cumulative preferred 1,075 1,075 Auction rate cumulative preferred 1,702 2,195 $5.875 cumulative preferred 1,469 1,469 Common 69,000 23,000 73,246 27,739 Balance December 31 $409,319 $393,636 The accompanying notes are an integral part of these consolidated financial statements. Page 3 Louisville Gas and Electric Company and Subsidiary Consolidated Statements of Comprehensive Income (Thousands of $) Years Ended December 31 2002 2001 Net income $88,929 $106,781 Cumulative effect of change in accounting principle - Accounting for derivative instruments and hedging activities - (5,998) Losses on derivative instruments and hedging activities (Note 1) (8,511) (2,606) Additional minimum pension liability adjustment (Note 6) (25,999) (24,712) Income tax benefit related to items of other comprehensive income 13,898 13,416 Other comprehensive loss, net of tax (20,612) (19,900) Comprehensive income $68,317 $86,881 The accompanying notes are an integral part of these consolidated financial statements. Page 4 Louisville Gas and Electric Company and Subsidiary Consolidated Balance Sheets (Thousands of $) December 31 2002 2001 ASSETS: Utility plant, at original cost (Note 1): Electric $2,717,187 $2,598,152 Gas 435,235 409,994 Common 169,577 159,817 3,321,999 3,167,963 Less: reserve for depreciation 1,463,674 1,381,874 1,858,325 1,786,089 Construction work in progress 300,986 255,074 2,159,311 2,041,163 Other property and investments - less reserve of $63 in 2002 and 2001 764 1,176 Current assets: Cash 17,015 2,112 Accounts receivable - less reserve of $2,125 in 2002 and $1,575 in 2001 68,440 85,667 Materials and supplies - at average cost: Fuel (predominantly coal) (Note 1) 36,600 22,024 Gas stored underground (Note 1) 50,266 46,395 Other 25,651 29,050 Prepayments and other 5,298 4,688 203,270 189,936 Deferred debits and other assets: Unamortized debt expense (Note 1) 6,532 5,921 Regulatory assets (Note 3) 153,446 197,142 Other 37,755 13,016 197,733 216,079 $2,561,078 $2,448,354 CAPITAL AND LIABILITIES: Capitalization (see statements of capitalization): Common equity $ 833,141 $ 838,070 Cumulative preferred stock 95,140 95,140 Long-term debt (Note 9) 328,104 370,704 1,256,385 1,303,914 Current liabilities: Current portion of long-term debt (Note 9) 288,800 246,200 Notes payable (Note 10) 193,053 94,197 Accounts payable 122,771 149,070 Accrued taxes 1,450 20,257 Other 19,536 18,658 625,610 528,382 Deferred credits and other liabilities: Accumulated deferred income taxes (Notes 1 and 7) 313,225 298,143 Investment tax credit, in process of amortization 54,536 58,689 Accumulated provision for pensions and related benefits (Note 6) 224,703 167,526 Regulatory liabilities (Note 3) 52,424 65,349 Other 34,195 26,351 679,083 616,058 Commitments and contingencies (Note 11) $2,561,078 $2,448,354 The accompanying notes are an integral part of these consolidated financial statements. Page 5 Louisville Gas and Electric Company and Subsidiary Consolidated Statements of Cash Flows (Thousands of $) Years Ended December 31 2002 2001 CASH FLOWS FROM OPERATING ACTIVITIES: Net income $ 88,929 $ 106,781 Items not requiring cash currently: Depreciation and amortization 105,906 100,356 Deferred income taxes - net 11,915 3,021 Investment tax credit - net (4,153) (4,290) Other 37,260 (528) Change in certain net current assets: Accounts receivable (3,973) 43,185 Materials and supplies (15,048) (2,018) Accounts payable (26,299) 14,678 Accrued taxes (18,807) 12,184 Prepayments and other 321 (10,500) Sale of accounts receivable (Note 1) 21,200 42,000 Other 15,130 (17,806) Net cash flows from operating activities 212,381 287,063 CASH FLOWS FROM INVESTING ACTIVITIES: Purchases of securities - - Proceeds from sales of securities 412 4,237 Construction expenditures (220,416) (252,958) Net cash flows from investing activities (220,004) (248,721) CASH FLOWS FROM FINANCING ACTIVITIES: Short-term borrowings and repayments 98,856 (20,392) Issuance of pollution control bonds 158,635 9,662 Retirement of first mortgage bonds and pollution control bonds (161,665) - Additional paid-in capital - - Payment of dividends (73,300) (27,995) Net cash flows from financing activities 22,526 (38,725) Change in cash and temporary cash investments 14,903 (383) Cash and temporary cash investments at beginning of year 2,112 2,495 Cash and temporary cash investments at end of year $ 17,015 $ 2,112 Supplemental disclosures of cash flow information: Cash paid during the year for: Income taxes $51,540 $ 35,546 Interest on borrowed money 25,673 30,989 The accompanying notes are an integral part of these consolidated financial statements. Page 6 Louisville Gas and Electric Company and Subsidiary Consolidated Statements of Capitalization (Thousands of $) December 31 2002 2001 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 40,000 Accumulated other comprehensive income (40,512) (19,900) Retained earnings 409,319 393,636 833,141 838,070 CUMULATIVE PREFERRED STOCK: Shares Current Outstanding Redemption Price $25 par value, 1,720,000 shares authorized - 5% series 860,287 $28.00 21,507 21,507 Without par value, 6,750,000 shares authorized - Auction rate 500,000 100.00 50,000 50,000 $5.875 series 250,000 101.18 25,000 25,000 Preferred stock expense (1,367) (1,367) 95,140 95,140 LONG-TERM DEBT (Note 9): First mortgage bonds - Series due August 15, 2003, 6% 42,600 42,600 Pollution control series: R due November 1, 2020, 6.55 % - 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, 5.625% 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 25,000 Z due August 1, 2030, variable % 83,335 83,335 AA due September 1, 2027, variable % 10,104 10,104 BB due September 1, 2026, variable % 22,500 - CC due September 1, 2026, variable % 27,500 - DD due November 1, 2027, variable % 35,000 - EE due November 1, 2027, variable % 35,000 - FF due October 1, 2032, variable % 41,665 - Total first mortgage bonds 616,904 496,904 Pollution control bonds (unsecured) - Series due September 1, 2026, variable % - 22,500 Series due September 1, 2026, variable % - 27,500 Series due November 1, 2027, variable % - 35,000 Series due November 1, 2027, variable % - 35,000 Total unsecured pollution control bonds - 120,000 Total bonds outstanding 616,904 616,904 Less current portion of long-term debt 288,800 246,200 Long-term debt 328,104 370,704 Total capitalization $1,256,385 $1,303,914 The accompanying notes are an integral part of these consolidated financial statements. Page 7 Louisville Gas and Electric Company and Subsidiary Notes to Consolidated Financial Statements Note 1 - Summary of Significant Accounting Policies LG&E, a subsidiary of LG&E Energy and an indirect subsidiary of Powergen and E.ON, 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 LG&E's Common Stock is held by LG&E Energy. LG&E has one wholly owned consolidated subsidiary, LG&E R. On December 11, 2000, LG&E Energy was acquired by Powergen. On July 1, 2002, E.ON, a German company, completed its acquisition of Powergen plc (now Powergen Limited). E.ON had announced its pre-conditional cash offer of 5.1 billion pounds sterling ($7.3 billion) for Powergen on April 9, 2001. E.ON and Powergen are registered public utility holding companies under PUHCA. No costs associated with these acquisitions nor any of the effects of purchase accounting have been reflected in the financial statements of LG&E. Certain reclassification entries have been made to the previous year's financial statements to conform to the 2002 presentation with no impact on the balance sheet totals or previously reported income. Utility Plant. LG&E'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. 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 and Amortization. Depreciation is provided on the straight- line method over the estimated service lives of depreciable plant. Pursuant to a final order of the Kentucky Commission dated December 3, 2001, LG&E implemented new depreciation rates effective January 1, 2001. The amounts provided were approximately 3.1% in 2002 (2.9% electric, 2.8% gas and 6.6% common) and 3.0% for 2001 (2.9% electric, 2.9% gas and 5.7% common), of average depreciable plant. Of the amount provided for depreciation, at December 31, 2002 and 2001, respectively, approximately 0.4 % electric, 0.9 % gas and 0.04% common were related to the retirement, removal and disposal costs of long lived assets. Fuel Inventory. Fuel inventories of $36.6 million and $22.0 million at December 31, 2002, and 2001, respectively, are included in Fuel in the balance sheet. The inventory is accounted for using the average-cost method. Gas Stored Underground. Gas inventories of $50.3 million and $46.4 million at December 31, 2002, and 2001, 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. Gains and losses on interest-rate swaps used to hedge interest rate risk are reflected in other comprehensive income. See Note 4- Financial Instruments. Page 8 Unamortized Debt Expense. Debt expense is capitalized in deferred debits and amortized over the lives of the related bond issues, consistent with regulatory practices. Deferred Income Taxes. Deferred income taxes are recognized at currently enacted tax rates for all material temporary differences between the financial reporting and income tax basis of assets and liabilities. 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 were approximately $40.7 million and $37.3 million, at December 31, 2002 and 2001, respectively. See Note 3, Rates and Regulatory Matters. LG&E recorded electric revenues that resulted from sales to a related party, KU, of $46.5 million and $28.5 million for years ended December 31, 2002 and 2001, respectively. With the adoption of EITF 02-03, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities, revenues on the income statement are shown net of cost associated with trading activities. As a result LG&E has netted the power purchased expense for trading activities against operating revenue for all years presented. 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 performance-based ratemaking mechanism related to gas procurement and off-system gas sales activity. 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 11, Commitments and Contingencies, for a further discussion. Accounts Receivable Securitization. SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, revises the standards for accounting for securitizations and other transfers of financial assets and collateral and requires certain disclosures, and provides accounting and reporting standards for transfers and servicing of financial assets and extinguishments of liabilities. SFAS No. 140 was adopted in the first quarter of 2001, when LG&E entered into an accounts receivable securitization transaction. On February 6, 2001, LG&E implemented an accounts receivable securitization program. The purpose of this program is to enable LG&E to accelerate the receipt of cash from the collection of retail accounts receivable, thereby reducing dependence upon more costly sources of working capital. The securitization program allows for a percentage of eligible receivables to be sold. Eligible receivables are generally all receivables associated with retail sales that have standard terms and are not past due. LG&E is able to terminate this program at any time without penalty. If there is a significant deterioration in the payment record of the receivables by the retail customers or if LG&E fails to meet certain covenants regarding the program, the program may terminate at the election of the financial institutions. In this case, payments from retail customers would first be used to repay the financial institutions participating in the program, and would then be available for use by LG&E. Page 9 As part of the program, LG&E sold retail accounts receivables to a wholly owned subsidiary, LG&E R. Simultaneously, LG&E R entered into two separate three-year accounts receivable securitization facilities with two financial institutions and their affiliates whereby LG&E R can sell, on a revolving basis, an undivided interest in certain of its receivables and receive up to $75 million from an unrelated third party purchaser. The effective cost of the receivables programs is comparable to LG&E's lowest cost source of capital, and is based on prime rated commercial paper. LG&E retains servicing rights of the sold receivables through two separate servicing agreements with the third party purchaser. LG&E has obtained an opinion from independent legal counsel indicating these transactions qualify as true sale of receivables. As of December 31, 2002, the outstanding program balance was $63.2 million. LG&E is considering unwinding its accounts receivable securitization arrangements involving LG&E R during 2003. The allowance for doubtful accounts associated with the eligible securitized receivables was $2.125 million at December 31, 2002. This allowance is based on historical experience of LG&E. Each securitization facility contains a fully funded reserve for uncollectible receivables. New Accounting Pronouncements. SFAS No. 143, Accounting for Asset Retirement Obligations was issued in 2001. SFAS No. 143 establishes accounting and reporting standards for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The effective implementation date for SFAS No. 143 is January 1, 2003. Management has calculated the impact of SFAS No. 143 and the recently released FERC NOPR No. RM02-7, Accounting, Financial Reporting, and Rate Filing Requirements for Asset Retirement Obligations. As of January 1, 2003, LG&E recorded asset retirement obligation (ARO) assets in the amount of $4.6 million and liabilities in the amount of $9.3 million. LG&E also recorded a cumulative effect adjustment in the amount of $5.3 million to reflect the accumulated depreciation and accretion of ARO assets at the transition date less amounts previously accrued under regulatory depreciation. LG&E recorded offsetting regulatory assets of $5.3 million, pursuant to regulatory treatment prescribed under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. Also pursuant to SFAS No. 71, LG&E recorded regulatory liabilities in the amount of $60,000 offsetting removal costs previously accrued under regulatory accounting in excess of amounts allowed under SFAS No. 143. LG&E also expects to record ARO accretion expense of approximately $617,000, ARO depreciation expense of approximately $117,000 and an offsetting regulatory credit in the income statement of approximately $734,000 in 2003, pursuant to regulatory treatment prescribed under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. The accretion, depreciation and regulatory credit will be annual adjustments. SFAS No. 143 will have no impact on the results of the operation of LG&E. LG&E asset retirement obligations are primarily related to the final retirement of generating units. LG&E transmission and distribution lines largely operate under perpetual property easement agreements which do not generally require restoration upon removal of the property. Therefore, under SFAS No. 143, no material asset retirement obligations will be recorded for transmission and distribution assets. LG&E adopted EITF No. 98-10, Accounting for Energy Trading and Risk Management Activities, effective January 1, 1999. This pronouncement required that energy trading contracts be marked to market on the balance sheet, with the gains and losses shown net in the income statement. The EITF clarified accounting standards related to energy trading activities under EITF Issue 02-03, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Page 10 Energy Trading and Risk Management Activities. EITF No. 02-03 established the following: - Rescinded EITF No. 98-10, - Contracts that do not meet the definition of a derivative under SFAS No.133 should not be marked to fair market value, and - Revenues should be shown in the income statement net of costs associated with trading activities, whether or not the trades are physically settled. With the rescission of EITF No. 98-10, energy trading contracts that do not also meet the definition of a derivative under SFAS No. 133 must be accounted for as executory contracts. Contracts previously recorded at fair value under EITF No. 98-10 that are not also derivatives under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, must be restated to historical cost through a cumulative effect adjustment. The rescission of this standard had no impact on financial position or results of operations of LG&E since all contracts marked to market under EITF No. 98-10 are also within the scope of SFAS No. 133. As a result of EITF No. 02-03, LG&E has netted the power purchased expense for trading activities against electric operating revenue to reflect this accounting change. LG&E applied this guidance to all prior periods, which had no impact on previously reported net income or common equity. 2002 2001 Gross electric operating revenues $746,224 $706,645 Less costs reclassified from power purchased 22,449 32,153 Net electric operating revenues reported $723,775 $674,492 Gross power purchased $ 84,330 $ 81,475 Less costs reclassified to revenues 22,449 32,153 Net power purchased reported $ 61,881 $ 49,332 In January 2003, the Financial Accounting Standards Board issued Financial Accounting Standards Board Interpretation No. 46, Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51 (FIN 46). FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. FIN 46 is effective immediately for all new variable interest entities created or acquired after January 31, 2003. For variable interest entities created or acquired prior to February 1, 2003, the provisions of FIN 46 must be applied for the first interim or annual period beginning after June 15, 2003. LG&E does not expect the adoption of this standard to have any impact on the financial position or results of operations. Note 2 - Mergers and Acquisitions On July 1, 2002, E.ON completed its acquisition of Powergen, including LG&E Energy, for approximately 5.1 billion pounds sterling ($7.3 billion). As a result of the acquisition, LG&E Energy became a wholly owned subsidiary (through Powergen) of E.ON and, as a result, LG&E also became an indirect subsidiary of E.ON. LG&E has continued its separate identity and serves customers inKentucky under its existing name. The preferred stock and debt securities of LG&E were not affected by this transaction and the utilities continue to file SEC reports. Following the acquisition, E.ON became, and Powergen remained, a registered holding company under PUHCA. LG&E, as a subsidiary of a registered holding company, is subject to additional regulations under PUHCA. As contemplated in their regulatory filings in connection with the E.ON acquisition, E.ON, Powergen and LG&E Energy completed an administrative reorganization to move the LG&E Energy group from an indirect Powergen subsidiary to an indirect E.ON subsidiary. This reorganization was effective in March 2003. Page 11 LG&E Energy and KU Energy merged on May 4, 1998, with LG&E Energy as the surviving corporation. Management accounted for the merger as a pooling of interests and as a tax-free reorganization under the Internal Revenue Code. Following the acquisition, LG&E has continued to maintain its separate corporate identity and serve customers in Kentucky under its present name. 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 as of December 31 (in thousands of $): 2002 2001 VDT Costs $ 98,044 $127,529 Gas supply adjustments due from customers 13,714 30,135 Unamortized loss on bonds 18,843 17,902 ESM provision 12,500 - LGE/KU merger costs 1,815 5,444 Manufactured gas sites 1,757 2,062 One utility costs 954 3,643 Other 5,819 10,427 Total regulatory assets 153,446 197,142 Deferred income taxes - net (45,536) (48,703) Gas supply adjustments due to customers (3,154) (15,702) Other (3,734) (944) Total regulatory liabilities (52,424) (65,349) Regulatory assets - net $101,022 $131,793 Kentucky Commission Settlement - VDT Costs. During the first quarter 2001, LG&E recorded a $144 million charge for a workforce reduction program. Primary components of the charge were separation benefits, enhanced early retirement benefits, and health care benefits. The result of this workforce reduction was the elimination of approximately 700 positions, accomplished primarily through a voluntary enhanced severance program. On June 1, 2001, LG&E filed an application (VDT case) with the Kentucky Commission to create a regulatory asset relating to these first quarter 2001 charges. The application requested permission to amortize these costs over a four-year period. The Kentucky Commission also opened a case to review a new depreciation study and resulting depreciation rates implemented in 2001. LG&E reached a settlement in the VDT case as well as the other cases involving depreciation rates and ESM with all intervening parties. The settlement agreement was approved by the Kentucky Commission on December 3, 2001. The order allowed LG&E to set up a regulatory asset of $141 million for the workforce reduction costs and begin amortizing these costs over a five year period starting in April 2001. The first quarter 2001 charge of $144 million represented all employees who had accepted a voluntary enhanced severance program. Some employees rescinded their participation in the voluntary enhanced severance program, thereby decreasing the Page 12 original charge from $144 million to $141 million. The settlement will also reduce revenues approximately $26 million through a surcredit on future bills to customers over the same five year period. The surcredit represents net savings stipulated by LG&E. The agreement also established LG&E's new depreciation rates in effect December 2001, retroactive to January 1, 2001. The new depreciation rates decreased depreciation expense by $5.6 million in 2001. PUHCA. LG&E Energy was purchased by Powergen on December 11, 2000. Effective July 1, 2002, Powergen was acquired by E.ON, which became a registered holding company under PUHCA. As a result, E.ON, 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. LG&E believes that it has adequate authority (including financing authority) under existing SEC orders and regulations to conduct its business. LG&E will seek additional authorization when necessary. Environmental Cost Recovery. In June 2000, the Kentucky Commission approved LG&E's application for a CCN to construct up to three SCR 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 2004. 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 ECR Tariff to include an overall rate of return on capital investments. Approval of LG&E's application in April 2001 allowed 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. In August 2002, LG&E filed an application with the Kentucky Commission to amend its compliance plan to allow recovery of the cost of new and additional environmental compliance facilities. The estimated capital cost of the additional facilities is $71.1 million. The Kentucky Commission conducted a public hearing on the case on December 20, 2002, final briefs were filed on January 15, 2003, and a final order was issued February 11, 2003. The final order approved recovery of four new environmental compliance facilities totaling $43.1 million. A fifth project, expansion of the land fill facility at the Mill Creek Station, was denied without prejudice with an invitation to reapply for recovery when required construction permits are approved. Cost recovery through the environmental surcharge of the four approved projects will begin with the bills rendered in April 2003. ESM. LG&E's electric rates are subject to an ESM. The ESM, initially 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, the excess earnings are shared 40% with ratepayers and 60% with shareholders; if earnings are below the lower limit, the earnings deficiency is recovered 40% from ratepayers and 60% from shareholders. By order of the Kentucky Commission, rate changes prompted by the ESM filing go into effect in April of each year subject to a balancing adjustment in successive periods. LG&E made its second ESM filing on March 1, 2002 for the calendar year 2001 reporting period. LG&E is in the process of refunding $441,000 to customers for the 2001 reporting period. LG&E estimated that the rate of return will fall below the lower limit, subject to Kentucky Commission approval, for the year ended December 31, 2002. The 2002 financial statements include an accrual to reflect the earnings deficiency of $12.5 million to be recovered from customers commencing in April 2003. On November 27, 2002, LG&E filed a revised ESM tariff which proposed continuance of the existing ESM through December 2005. The Kentucky Commission issued an Order suspending the ESM tariff one day making the Page 13 effective date January 2, 2003. In addition, the Kentucky Commission is conducting a management audit to review the ESM plan and reassess its reasonableness in 2003. LG&E and interested parties will have the opportunity to provide recommendations for modification and continuance of the ESM or other forms of alternative or incentive regulation. 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. In May 2001, the Kentucky Commission approved LG&E's plan to continue DSM programs. This filing called for the expansion of the DSM programs into the service territory served by KU and proposed 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 November 1, 1997, LG&E has operated under an experimental PBR mechanism related to its gas procurement activities. For each of the last five years, LG&E's rates have been adjusted to recover its portion of the savings (or expenses) incurred during each of the five 12-month periods beginning November 1 and ending October 31. Since its implementation on November 1, 1997, through October 31, 2001, LG&E has achieved $38.1 million in savings. Of the total savings, LG&E has retained $16.5 million, and the remaining portion of $21.6 million has been distributed to 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 as a result of the benefits provided to both LG&E and its customers during the experimental period. Following the discovery and hearing process, the Kentucky Commission issued an order effective November 1, 2001, extending the experimental PBR program for an additional four years, and making other modifications, including changes to the sharing levels applicable to savings or expenses incurred under the PBR. Specifically, the Kentucky Commission modified the savings mechanism to a 25%/75% Company/Customer sharing for all savings (and expenses) up to 4.5% of the benchmarked gas costs. Savings (and expenses) in excess of 4.5% of the benchmarked gas costs are shared at a 50%/50% level. FAC. Prior to implementation of the electric 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. While legal challenges to the Kentucky Commission order were pending, a comprehensive settlement was reached by all parties and approved by the Kentucky Commission on May 17, 2002. Thereunder, LG&E agreed to credit its fuel clause in the amount of $720,000 (such credit provided over the course of June and July 2002), and the parties agreed on a prospective interpretation of the state's FAC regulation to ensure consistent and mutually acceptable application on a going-forward basis. In December 2002, the Kentucky Commission initiated a two year review of the operation of LG&E's FAC for the period November 2000 through October 2002. Testimony in the review case was filed on January 20, 2003 and a public hearing was held February 18, 2003. Issues addressed at that time included the establishment of the current base fuel factor to be included in LG&E's base rates, verification of proper treatment of purchased power costs during unit outages, and compliance with fuel procurement policies and practices. Gas Rate Case. In March 2000, LG&E filed an application with the Kentucky Commission requesting an adjustment in LG&E's gas rates. 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 base gas revenues from gas sales. Page 14 Wholesale Natural Gas Prices. On September 12, 2000, the Kentucky Commission issued an order establishing Administrative Case No. 384 - "An Investigation of Increasing Wholesale Natural Gas Prices and the Impacts of such Increase on the Retail Customers Served by Kentucky's Jurisdictional Natural Gas Distribution Companies". The impetus for this administrative proceeding was the escalation of wholesale natural gas prices during the summer of 2000. The Kentucky Commission directed Kentucky's natural gas distribution companies, including LG&E, to file selected information regarding the individual companies' natural gas purchasing practices, expectations for the then-approaching winter heating season of 2000-2001, and potential actions which these companies might take to mitigate price volatility. On July 17, 2001, the Kentucky Commission issued an order encouraging the natural gas distribution companies in Kentucky to take various actions, among them to propose a natural gas hedge plan, consider performance-based ratemaking mechanisms, and to increase the use of storage. In April 2002, in Case No. 2002-00136, LG&E proposed a hedging plan for the 2002/2003 winter heating season with three alternatives, the first two using a combination of storage and financial hedge instruments and the third relying upon storage alone. LG&E and the Attorney General, who represents Kentucky consumers, entered into a settlement which selected the third option. In August 2002, the Kentucky Commission approved the plan contemplated in the settlement. The Kentucky Commission validated the effectiveness of storage to mitigate potentially high winter gas prices by approving this natural gas hedging plan. The Kentucky Commission also decided in Administrative Case No. 384 to engage a consultant to conduct a forward-looking audit of the gas procurement and supply procedures of Kentucky's largest natural gas distribution companies. The Kentucky Commission completed its audit in late 2002. The audit recognized LG&E as "efficient and effective [in the] procurement and management of significant quantities of natural gas supplies." The auditors also recognized that "the Company's residential gas prices have long been below averages for the U. S. and for the Commonwealth of Kentucky" which "demonstrates [LG&E's] effectiveness in [the] procurement and management of natural gas supplies." The audit also stated that the "Company's very impressive record in keeping its rates down provides sound evidence on the excellent job done in the area of gas supply procurement and management." 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 intended 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. During the period September 1998 to February 2000, the Kentucky Commission issued draft codes of conduct and cost allocation guidelines. In early 2000, the Kentucky General Assembly enacted legislation, House Bill 897, which authorized the Kentucky Commission to require utilities that provide nonregulated activities to keep separate accounts and allocate costs in accordance with procedures established by the Kentucky Commission. In the same bill, the General Assembly set forth provisions to govern a utility's 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. On February 14, 2001, the Kentucky Commission published notice of its intent to promulgate new administrative regulations under the auspices of this new law. This effort is still on going. Kentucky Commission Administrative Case for System Adequacy. On June 19, 2001, Kentucky Governor Paul E. Patton issued Executive Order 2001-771, Page 15 which directed the Kentucky Commission to review and study issues relating to the need for and development of new electric generating capacity in Kentucky. The issues to be considered included the impact of new power plants on the electric supply grid, facility citing issues, and economic development matters, with the goal of ensuring a continued, reliable source of supply of electricity for the citizens of Kentucky and the continued environmental and economic vitality of Kentucky and its communities. In response to that Executive Order, in July 2001 the Kentucky Commission opened Administrative Case No. 387 to review the adequacy of Kentucky's generation capacity and transmission system. Specifically, the items reviewed were the appropriate level of reliance on purchased power, the appropriate reserve margins to meet existing and future electric demand, the impact of spikes in natural gas prices on electric utility planning strategies, and the adequacy of Kentucky's electric transmission facilities. LG&E, as a party to this proceeding, filed written testimony and responded to two requests for information. Public hearings were held and in October 2001, LG&E filed a final brief in the case. In December 2001, the Kentucky Commission issued an order in which it noted that LG&E is responsibly addressing the long-term supply needs of native load customers and that current reserve margins are appropriate. However, due to the rapid pace of change in the industry, the order also requires LG&E to provide an annual assessment of supply resources, future demand, reserve margin, and the need for new resources. Regarding the transmission system, the Kentucky Commission concluded that the transmission system within Kentucky can reliably serve native load and a significant portion of the proposed new unregulated power plants. However, it will not be able to handle the volume of transactions envisioned by FERC without future upgrades, the costs of which should be borne by those for whom the upgrades are required. The Kentucky Commission pledged to continue to monitor all relevant issues and advocate Kentucky's interests at all opportunities. FERC SMD NOPR. On July 31, 2002, FERC issued a NOPR in Docket No. RM01-12- 000 which would substantially alter the regulations governing the nation's wholesale electricity markets by establishing a common set of rules -- SMD. The SMD NOPR would require each public utility that owns, operates, or controls interstate transmission facilities to become an Independent Transmission Provider (ITP), belong to an RTO that is an ITP, or contract with an ITP for operation of its transmission assets. It would also establish a standardized congestion management system, real-time and day- ahead energy markets, and a single transmission service for network and point-to-point transmission customers. Review of the proposed rulemaking is underway and a final rule is expected during 2003. While it is expected that the SMD final rule will affect LG&E revenues and expenses, the specific impact of the rulemaking is not known at this time. MISO. LG&E is a member of the MISO, which began commercial operations on February 1, 2002. MISO now has operational control over LG&E's high- voltage transmission facilities (100 kV and greater), while LG&E continues to control and operate the lower voltage transmission subject to the terms and conditions of the MISO OATT. As a transmission-owning member of MISO, LG&E also incurs administrative costs of MISO pursuant to Schedule 10 of the MISO OATT. MISO also proposed to implement a congestion management system. FERC directed the MISO to coordinate its efforts with FERC's Rulemaking on SMD. On September 24, 2002, the MISO filed new rate schedules designated as Schedules 16 and 17, which provide for the collection of costs incurred by the MISO to establish day-ahead and real-time energy markets. The MISO proposed to recover these costs under Schedules 16 and 17 once service commences. If approved by FERC, these schedules will cause LG&E to incur additional costs. LG&E opposes the establishment of Schedules 16 and 17. This effort is still on-going and the ultimate impact of the two schedules, if approved, is not known at this time. ARO. In 2003, LG&E expects to record approximately $6.0 million in regulatory assets and approximately $60,000 in regulatory liabilities related to SFAS No. 143, Accounting for Asset Retirement Obligations. Page 16 Merger Surcredit. As part of the LG&E Energy merger with KU Energy in 1998, LG&E Energy estimated 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 was deferred and 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 approving the merger, the Kentucky Commission adopted LG&E's proposal to reduce its retail customers' bills based on one-half of the estimated merger-related savings, net of deferred and amortized amounts, over a five- year period. The surcredit mechanism provides that 50% of the net non-fuel cost savings estimated to be achieved from the merger be provided to ratepayers through a monthly bill credit, and 50% be retained by the Companies, over a five-year period. The surcredit was allocated 53% to KU and 47% to LG&E. In that same order, the Commission required LG&E and KU, after the end of the five-year period, to present a plan for sharing with customers the then-projected non-fuel savings associated with the merger. The Companies submitted this filing on January 13, 2003, proposing to continue to share with customers, on a 50%/50% basis, the estimated fifth- year gross level of non-fuel savings associated with the merger. The filing is currently under review. Any fuel cost savings are passed to Kentucky customers through the fuel adjustment clause. See FAC above. Note 4 - Financial Instruments The cost and estimated fair values of LG&E's non-trading financial instruments as of December 31, 2002, and 2001 follow (in thousands of $): 2002 2001 Fair Fair Cost Value Cost Value Preferred stock subject to mandatory redemption $ 25,000 $ 25,188 $ 25,000 $ 25,125 Long-term debt (including current portion) 616,904 623,325 616,904 620,504 Interest-rate swaps - (17,115) - (8,604) 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. LG&E uses interest rate swaps to hedge exposure to market fluctuations in certain of its debt instruments. Pursuant to policy, use of these financial instruments is intended to mitigate risk and earnings volatility and is not speculative in nature. Management has designated all of the interest rate swaps as hedge instruments. Financial instruments designated as cash flow hedges have resulting gains and losses recorded within other comprehensive income and stockholders' equity. To the extent a financial instrument or the underlying item being hedged is prematurely terminated or the hedge becomes ineffective, the resulting gains or losses are reclassified from other comprehensive income to net income. Financial instruments designated as fair value hedges are periodically marked to market with the resulting gains and losses recorded directly into net income to correspond with income or expense recognized from changes in market value of the items being hedged. As of December 31, 2002 and 2001, LG&E was party to various interest rate swap agreements with aggregate notional amounts of $117.3 million. Under these swap agreements, LG&E paid fixed rates averaging 5.13% and received variable rates based on the Bond Market Association's municipal swap index Page 17 averaging 1.52% and 1.61% at December 31, 2002 and 2001, respectively. The swap agreements in effect at December 31, 2002 have been designated as cash flow hedges and mature on dates ranging from 2003 to 2020. The hedges have been deemed to be fully effective resulting in a pretax loss of $8.5 million for 2002, recorded in other comprehensive income. Upon expiration of these hedges, the amount recorded in other comprehensive income will be reclassified into earnings. The amounts expected to be reclassified from other comprehensive income to earnings in the next twelve months is immaterial. Energy Trading & Risk Management Activities. LG&E conducts energy trading and risk management activities to maximize the value of power sales from physical assets it owns, in addition to the wholesale sale of excess asset capacity. Certain energy trading activities are accounted for on a mark-to- market basis in accordance with EITF 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities, SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities. Wholesale sales of excess asset capacity and wholesale purchases are treated as normal sales and purchases under SFAS No. 133 and SFAS No. 138 and are not marked-to-market. The consensus reached by the EITF on EITF No. 02-03, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities, to rescind EITF 98-10, effective for fiscal years after December 15, 2002, had no impact on LG&E's energy trading and risk management reporting as all contracts marked to market under EITF 98-10 are also within the scope of SFAS No. 133. The table below summarizes LG&E's energy trading and risk management activities for 2002 and 2001 (in thousands of $). 2002 2001 Fair value of contracts at beginning of period, net liability $ (186) $ (17) Fair value of contracts when entered into during the period (65) 3,441 Contracts realized or otherwise settled during the period 448 (2,894) Changes in fair values due to changes in assumptions (353) (716) Fair value of contracts at end of period, net liability $ (156) $ (186) No changes to valuation techniques for energy trading and risk management activities occurred during 2002. Changes in market pricing, interest rate and volatility assumptions were made during both years. All contracts outstanding at December 31, 2002, have a maturity of less than one year and are valued using prices actively quoted for proposed or executed transactions or quoted by brokers. LG&E maintains policies intended to minimize credit risk and revalues credit exposures daily to monitor compliance with those policies. At December 31, 2002, 86% of the trading and risk management commitments were with counterparties rated BBB- equivalent or better. 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 310,000 customers and electricity to approximately 382,000 customers in Louisville and adjacent areas in Kentucky. For the year ended December 31, 2002, 73% of total revenue was derived from electric operations and 27% from gas operations. Page 18 In November 2001, LG&E and IBEW Local 2100 employees, which represent approximately 70% of LG&E's workforce, entered into a four-year collective bargaining agreement. Note 6 - Pension Plans and Retirement Benefits 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 two-year period ending December 31, 2002, and a statement of the funded status as of December 31 for each of the last two years (in thousands of $): 2002 2001 Pension Plans: Change in benefit obligation Benefit obligation at beginning of year $ 356,293 $ 310,822 Service cost 1,484 1,311 Interest cost 24,512 25,361 Plan amendments 576 1,550 Curtailment loss - 24,563 Special termination benefits - 53,610 Benefits paid (34,823) (53,292) Actuarial (gain) or loss and other 16,752 (7,632) Benefit obligation at end of year $ 364,794 $ 356,293 Change in plan assets Fair value of plan assets at beginning of year $ 233,944 $ 333,378 Actual return on plan assets (15,648) (27,589) Employer contributions and plan transfers 14,150 (17,134) Benefits paid (34,824) (53,292) Administrative expenses (1,308) (1,419) Fair value of plan assets at end of year $ 196,314 $ 233,944 Reconciliation of funded status Funded status $(168,480) $(122,349) Unrecognized actuarial (gain) or loss 60,313 18,800 Unrecognized transition (asset) or obligation (3,199) (4,215) Unrecognized prior service cost 32,265 35,435 Net amount recognized at end of year $ (79,101) $ (72,329) Other Benefits: Change in benefit obligation Benefit obligation at beginning of year $ 89,946 $ 56,981 Service cost 444 358 Interest cost 5,956 5,865 Plan amendments - 1,487 Curtailment loss - 8,645 Special termination benefits - 18,089 Benefits paid (4,988) (4,877) Actuarial (gain) or loss 1,875 3,398 Benefit obligation at end of year $ 93,233 $ 89,946 Change in plan assets Fair value of plan assets at beginning of year $ 2,802 $ 7,166 Actual return on plan assets (533) (765) Employer contributions and plan transfers 4,213 1,282 Benefits paid (5,004) (4,881) Fair value of plan assets at end of year $ 1,478 $ 2,802 Page 19 Reconciliation of funded status Funded status $(91,755) $(87,144) Unrecognized actuarial (gain) or loss 16,971 15,947 Unrecognized transition (asset) or obligation 6,697 7,346 Unrecognized prior service cost 5,995 5,302 Net amount recognized at end of year $(62,092) $(58,549) There are no plan assets in the nonqualified plans due to the nature of the plans. LG&E made a contribution to the pension plan of $83.1 million in January 2003. 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, 2002 and 2001 (in thousands of $): 2002 2001 Pension Plans: Amounts recognized in the balance sheet consisted of: Prepaid benefits cost $ - $ - Accrued benefit liability (162,611) (108,977) Intangible asset 32,799 11,936 Accumulated other comprehensive income 50,711 24,712 Net amount recognized at year-end $(79,101) $(72,329) Additional year-end information for plans with accumulated benefit obligations in excess of plan assets (1): Projected benefit obligation $ 364,794 $ 356,293 Accumulated benefit obligation 358,956 352,477 Fair value of plan assets 196,314 233,944 (1) 2002 and 2001 includes all plans. Other Benefits: Amounts recognized in the balance sheet consisted of: Accrued benefit liability $ (62,092) $ (58,549) Additional year-end information for plans with benefit obligations in excess of plan assets: Projected benefit obligation $ 93,233 $ 89,946 Fair value of plan assets 1,478 2,802 The following table provides the components of net periodic benefit cost for the plans for 2002 and 2001 (in thousands of $): 2002 2001 Pension Plans: Components of net periodic benefit cost Service cost $ 1,484 $ 1,311 Interest cost 24,512 25,361 Expected return on plan assets (21,639) (26,360) Amortization of prior service cost 3,777 3,861 Amortization of transition (asset) or obligation (1,016) (1,000) Recognized actuarial (gain) or loss 21 (777) Net periodic benefit cost $ 7,139 $ 2,396 Page 20 Special charges Prior service cost recognized $ - $ 10,237 Special termination benefits - 53,610 Settlement loss - (2,244) Total charges $ - $ 61,603 Other Benefits: Components of net periodic benefit cost Service cost $ 444 $ 358 Interest cost 5,956 5,865 Expected return on plan assets (204) (420) Amortization of prior service cost 920 951 Amortization of transition (asset) or obligation 650 719 Recognized actuarial (gain) or loss 116 (32) Net periodic benefit cost $ 7,882 $ 7,441 Special charges Curtailment loss $ - $ 6,671 Prior service cost recognized - 2,391 Transition obligation recognized - 4,743 Special termination benefits - 18,089 Total charges $ - $ 31,894 The assumptions used in the measurement of LG&E's pension benefit obligation are shown in the following table: 2002 2001 Weighted-average assumptions as of December 31: Discount rate 6.75% 7.25% Expected long-term rate of return on plan assets 9.00% 9.50% Rate of compensation increase 3.75% 4.25% For measurement purposes, a 12.00% annual increase in the per capita cost of covered health care benefits was assumed for 2003. The rate was assumed to decrease gradually to 5.00% for 2014 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 2002 (201) 227 Effect on year-end 2002 postretirement benefit obligations (3,001) 3,347 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 of this matching were approximately $1.7 million for 2002 and $1.2 million for 2001. Page 21 Note 7 - Income Taxes Components of income tax expense are shown in the table below (in thousands of $): 2002 2001 Included in operating expenses: Current - federal $26,231 $42,997 - state 8,083 8,668 Deferred - federal - net 20,464 12,310 - state - net 4,410 3,767 Amortization of investment tax credit (4,153) (4,290) Total 55,035 63,452 Included in other income - net: Current - federal (1,667) (1,870) - state (430) (483) Deferred - federal - net (206) 285 - state - net (53) 73 Total (2,356) (1,995) Total income tax expense $52,679 $61,457 Components of net deferred tax liabilities included in the balance sheet are shown below (in thousands of $): 2002 2001 Deferred tax liabilities: Depreciation and other plant-related items $346,737 $334,914 Other liabilities 64,734 77,611 411,471 412,525 Deferred tax assets: Investment tax credit 22,012 23,713 Income taxes due to customers 18,431 19,709 Pensions 21,056 6,621 Accrued liabilities not currently deductible and other 36,747 64,339 98,246 114,382 Net deferred income tax liability $313,225 $298,143 A reconciliation of differences between the statutory U.S. federal income tax rate and LG&E's effective income tax rate follows: 2002 2001 Statutory federal income tax rate 35.0% 35.0% State income taxes, net of federal benefit 5.6 4.7 Amortization of investment tax credit (2.9) (2.6) Other differences - net (0.5) (0.6) Effective income tax rate 37.2% 36.5% Page 22 Note 8 - Other Income - net Other income - net consisted of the following at December 31 (in thousands of $): 2002 2001 Interest and dividend income $457 $ 748 Gains on fixed asset disposals 421 1,217 Income taxes and other (58) 965 Other income - net $820 $2,930 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, 2002. Weighted Average Stated Interest Principal Interest Rates Rate Maturities Amounts Noncurrent portion Variable - 5.90% 3.53% 2019-2032 $ 328,104 Current portion Variable - 6.00% 2.08% 2003-2027 288,800 Under the provisions for some of 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 in the consolidated balance sheets. The average annualized interest rate for these bonds during 2002 was 1.61%. LG&E's First Mortgage Bond, 6% Series of $42.6 million is scheduled to mature in 2003. There are no other scheduled maturities of pollution control bonds for the five years subsequent to December 31, 2002. In October 2002, LG&E issued $41.7 million variable rate pollution bonds due October 1, 2032, and exercised its call option on $41.7 million, 6.55% pollution control bonds due November 1, 2020. In March 2002, LG&E refinanced four unsecured pollution control bonds with an aggregate principal balance of $120 million and replaced them with secured pollution control bonds. The new bonds and the previous bonds were all variable rate bonds, and the maturity dates remained unchanged. In September 2001, LG&E issued $10.1 million variable rate tax-exempt environmental facility revenue bonds due September 1, 2027. 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 dividends on common stock, under certain specified conditions. No portion of retained earnings is restricted by this provision as of December 31, 2002. Page 23 Note 10 - Notes Payable LG&E participates in an intercompany money pool agreement wherein LG&E Energy can make funds available to LG&E at market based rates up to $400 million. The balance of the money pool loan from LG&E Energy was $193.1 million at a rate of 1.61% and $64.2 million at an average rate of 2.37%, at December 31, 2002 and 2001, respectively. LG&E also had outstanding commercial paper of $30 million at an average rate of 2.54% at December 31, 2001. The remaining money pool availability at December 31, 2002, was $206.9 million. LG&E Energy maintains facilities of $450 million with affiliates to ensure funding availability for the money pool. The outstanding balance under these facilities as of December 31, 2002 was $230 million, and availability of $220 million remained. Note 11 - Commitments and Contingencies Construction Program. LG&E had approximately $15.1 million of commitments in connection with its construction program at December 31, 2002. Construction expenditures for the years 2003 and 2004 are estimated to total approximately $340.0 million, although all of this amount is not currently committed, including the purchase of four jointly owned CTs, $89.0 million, and construction of NOx equipment, $34.0 million. Operating Lease. LG&E leases office space and accounts for its office space lease as an operating lease. Total lease expense for 2002 and 2001 less amounts contributed by the parent company, was $1.6 million and $1.1 million, respectively. The future minimum annual lease payments under this lease agreement for years subsequent to December 31, 2002, are as follows (in thousands of $): 2003 $ 3,371 2004 3,399 2005 3,467 2006 3,536 2007 3,607 Thereafter 29,794 Total $47,174 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 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 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. As a result of appeals to both rules, the compliance date was extended to May 2004. All LG&E generating units are subject to the May 2004 compliance date under these NOx emissions reduction rules. Page 24 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. In addition, LG&E will incur additional operation 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 had anticipated that such capital and operating costs are the type of costs that are eligible for recovery from customers under its environmental surcharge mechanism and believed that a significant portion of such costs could be recovered. In April 2001, the Kentucky Commission granted recovery of these costs for LG&E. 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 is in the process of converting the Mill Creek Station to wet stack operation in an effort to resolve all outstanding issues related to particulate matter emissions. 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 at December 31, 2002 and 2001. Page 25 Purchased Power. LG&E has a contract for purchased power with OVEC for various Mw capacities. The estimated future minimum annual payments under purchased power agreements for the years subsequent to December 31, 2002, are as follows (in thousands of $): 2003 $ 10,773 2004 10,116 2005 10,152 2006 10,816 2007 10,816 Thereafter 184,544 Total $237,217 Note 12 - 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. 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 386.2 66.4 62.4 515.0 LG&E's 75% ownership (in thousands of $): Cost $595,747 Accumulated depreciation 182,711 Net book value $413,036 Construction work in progress (included above) $12,867 Page 26 LG&E and KU jointly own the following combustion turbines (in thousands of $): LG&E KU Total Paddy's Run 13 Ownership % 53% 47% 100% Mw capacity 84 74 158 Cost $33,919 $29,973 $63,892 Depreciation 1,711 1,499 3,210 Net book value $32,208 $28,474 $60,682 E.W. Brown 5 Ownership % 53% 47% 100% Mw capacity 71 63 134 Cost $23,973 $21,106 $45,079 Depreciation 1,206 1,052 2,258 Net book value $22,767 $20,054 $42,821 E.W. Brown 6 Ownership % 38% 62% 100% Mw capacity 59 95 154 Cost $23,696 $36,957 $60,653 Depreciation 1,770 4,201 5,971 Net book value $21,926 $32,756 $54,682 E.W. Brown 7 Ownership % 38% 62% 100% Mw capacity 59 95 154 Cost $23,607 $44,792 $68,399 Depreciation 4,054 4,502 8,556 Net book value $19,553 $40,290 $59,843 Trimble 5 Ownership % 29% 71% 100% Mw capacity 45 110 155 Cost $15,970 $39,045 $55,015 Depreciation 251 614 865 Net book value $15,719 $38,431 $54,150 Trimble 6 Ownership % 29% 71% 100% Mw capacity 45 110 155 Cost $15,961 $39,025 $54,986 Depreciation 251 614 865 Net book value $15,710 $38,411 $54,121 Trimble CT Ownership % 29% 71% 100% Pipeline Cost $1,835 $4,475 $6,310 Depreciation 39 96 135 Net book value $1,796 $4,379 $6,175 See also Note 11, Construction Program, for LG&E's planned purchase of four jointly owned CTs in 2004. Page 27 Note 13 - 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 2002 Operating revenues $736,042 (a) $267,693 $1,003,735 Depreciation and amortization 90,248 15,658 105,906 Interest income 381 76 457 Interest expense 24,837 4,968 29,805 Operating income taxes 49,010 6,025 55,035 Net income 79,246 9,683 88,929 Total assets 2,105,956 455,122 2,561,078 Construction expenditures 195,662 24,754 220,416 2001 Operating revenues $673,772 (b) $290,775 $964,547 Depreciation and amortization 85,572 14,784 100,356 Interest income 616 132 748 Interest expense 31,295 6,627 37,922 Operating income taxes 55,527 7,925 63,452 Net income 95,103 11,768 106,781 Total assets 1,985,252 463,102 2,448,354 Construction expenditures 227,107 25,851 252,958 (a) Net of provision for rate collections of $12.3 million. (b) Net of provision for rate refunds of $.7 million. Note 14 - Selected Quarterly Data (Unaudited) Selected financial data for the four quarters of 2002 and 2001 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 $) 2002 Operating revenues $278,005 $216,163 $243,074 $266,493 Net operating income 28,748 22,410 41,652 25,104 Net income 20,943 15,256 34,204 18,526 Net income available for common stock 19,878 14,207 33,129 17,469 2001 Operating revenues $308,929 $212,918 $229,848 $212,852 Net operating income (loss) (a) (43,732) 37,624 49,092 98,789 Net income (loss) (a) (54,115) 28,467 40,270 92,159 Net income (loss) available for common stock (a) (55,413) 27,247 39,160 91,048 (a) Loss resulted from the VDT pre-tax charge of $144.0 million in March 2001, which was reversed in December 2001. See Note 3. Page 28 Note 15 - Subsequent Events LG&E made a contribution to the pension plan of $83.1 million in January 2003. On March 18, 2003, the Kentucky Commission approved LG&E and KU's joint application for the acquisition of four CTs from an unregulated affiliate, LG&E Capital Corp. The total projected construction cost for the turbines, expected to be available for June 2004 in-service, is $227.4 million. The requested ownership share of the turbines is 63% for KU and 37% for LG&E. Page 29 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. These statements have been prepared in accordance with accounting principles generally accepted in the United States applied on a consistent basis and, necessarily, include amounts that reflect the best estimates and judgment of management. LG&E's 2002 and 2001 financial statements have been audited by PricewaterhouseCoopers LLP, independent accountants. Management made available to PricewaterhouseCoopers 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 and external auditors. These recommendations for the year ended December 31, 2002, did not identify any material weaknesses in the design and operation of LG&E's internal control structure. In carrying out its oversight role for the financial reporting and internal controls of LG&E, the Board of Directors meets regularly with LG&E's independent public accountants, internal auditors and management. The Board of Directors 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 Board of Directors 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 Board of Directors 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. S. Bradford Rives Chief Financial Officer Louisville Gas and Electric Company Louisville, Kentucky November 12, 2003 Page 30 Louisville Gas and Electric Company and Subsidiary REPORT OF INDEPENDENT ACCOUNTANTS To the Shareholders of Louisville Gas and Electric Company and Subsidiary: In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of capitalization, income, retained earnings, cash flows and comprehensive income present fairly, in all material respects, the financial position of Louisville Gas and Electric Company and Subsidiary (the "Company"), a wholly-owned subsidiary of LG&E Energy Corp., at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. As discussed in Note 1 to the financial statements, effective January 1, 2003, the Company adopted EITF No. 02-03, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities. /s/ PricewaterhouseCoopers LLP Louisville, Kentucky January 21, 2003,except for Note 1 as to which the date is November 12, 2003 Page 31 INDEX OF ABBREVIATIONS Capital Corp. LG&E Capital Corp. Clean Air Act The Clean Air Act, as amended in 1990 CCN 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 E.ON E.ON AG EPA U.S. Environmental Protection Agency ESM Earnings Sharing Mechanism F Fahrenheit FAC Fuel Adjustment Clause FERC Federal Energy Regulatory Commission FPA Federal Power Act FT and FT-A Firm Transportation GSC Gas Supply Clause 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 KU R KU Receivables LLC kV Kilovolts Kva Kilovolt-ampere KW Kilowatts Kwh Kilowatt hours LEM LG&E Energy Marketing Inc. LG&E Louisville Gas and Electric Company LG&E Energy LG&E Energy Corp. LG&E R LG&E Receivables LLC LG&E Services LG&E Energy Services Inc. Mcf Thousand Cubic Feet MGP Manufactured Gas Plant MISO Midwest Independent System Operator Mmbtu Million British thermal units Moody's Moody's Investor Services, Inc. Mw Megawatts Mwh Megawatt hours NNS No-Notice Service NOPR Notice of Proposed Rulemaking NOx Nitrogen Oxide OATT Open Access Transmission Tariff OMU Owensboro Municipal Utilities OVEC Ohio Valley Electric Corporation PBR Performance-Based Ratemaking PJM Pennsylvania,New Jersey,Maryland Interconnection Powergen Powergen Limited (formerly Powergen plc) PUHCA Public Utility Holding Company Act of 1935 ROE Return on Equity RTO Regional Transmission Organization S&P Standard & Poor's Rating Services SCR Selective Catalytic Reduction SEC Securities and Exchange Commission Page 32 SERP Supplemental Employee Retirement Plan SFAS Statement of Financial Accounting Standards SIP State Implementation Plan SMD Standard Market Design SO2 Sulfur Dioxide 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 VDT Value Delivery Team Process Virginia Commission Virginia State Corporation Commission Virginia Staff Virginia State Corporation Commission Staff Page 33 Kentucky Utilities Company and Subsidiary Consolidated Statements of Income (Thousands of $) Years Ended December 31 2002 2001 OPERATING REVENUES: Electric (Note 1) $848,637 $821,675 Provision for rate collections (refunds) (Note 3) 13,027 (954) Total operating revenues 861,664 820,721 OPERATING EXPENSES: Fuel for electric generation 250,117 236,985 Power purchased 131,400 118,410 Other operation expenses 144,118 118,359 Non-recurring charge (Note 3) - 6,867 Maintenance 62,909 57,021 Depreciation and amortization (Note 1) 95,462 90,299 Federal and state income taxes (Note 7) 54,032 57,482 Property and other taxes 14,983 13,928 Total operating expenses 753,021 699,351 Net operating income 108,643 121,370 Other income - net (Note 3) 10,429 8,932 Interest charges 25,688 34,024 Net income before cumulative effect of a change in accounting principle 93,384 96,278 Cumulative effect of a change in accounting principle-accounting for Derivative instruments and hedging activities, net of tax - 136 Net income 93,384 96,414 Preferred stock dividends 2,256 2,256 Net income available for common stock $ 91,128 $ 94,158 Consolidated Statements of Retained Earnings (Thousands of $) Years Ended December 31 2002 2001 Balance January 1 $410,896 $347,238 Add net income 93,384 96,414 504,280 443,652 Deduct:Cash dividends declared on stock: 4.75% cumulative preferred 950 950 6.53% cumulative preferred 1,306 1,306 Common - 30,500 2,256 32,756 Balance December 31 $502,024 $410,896 The accompanying notes are an integral part of these consolidated financial statements. Page 34 Kentucky Utilities Company and Subsidiary Consolidated Statements of Comprehensive Income (Thousands of $) Years Ended December 31 2002 2001 Net income $ 93,384 $ 96,414 Cumulative effect of change in accounting principle - Accounting for derivative instruments and hedging activities - 2,647 Losses on derivative instruments and hedging activities (2,647) - Additional minimum pension liability adjustment (Note 6) (17,543) - Income tax benefit (expense) related to items of other comprehensive income 8,140 (1,059) Other comprehensive (loss) income, net of tax (12,050) 1,588 Comprehensive income $ 81,334 $ 98,002 The accompanying notes are an integral part of these consolidated financial statements. Page 35 Kentucky Utilities Company and Subsidiary Consolidated Balance Sheets (Thousands of $) December 31 2002 2001 ASSETS: Utility plant, at original cost (Note 1) $3,089,529 $2,960,818 Less: reserve for depreciation 1,536,658 1,457,754 1,552,871 1,503,064 Construction work in progress 191,233 103,402 1,744,104 1,606,466 Other property and investments - less reserve of $130 in 2002 and 2001 14,358 9,629 Current assets: Cash and temporary cash investments (Note 1) 5,391 3,295 Accounts receivable -less reserve of $800 in 2002 and 2001 49,588 45,291 Materials and supplies - at average cost: Fuel (predominantly coal) (Note 1) 46,090 43,382 Other 26,408 26,188 Prepayments and other 6,584 4,942 134,061 123,098 Deferred debits and other assets: Unamortized debt expense (Note 1) 4,991 4,316 Regulatory assets (Note 3) 65,404 66,467 Other 35,465 16,926 105,860 87,709 $1,998,383 $ 1,826,902 CAPITAL AND LIABILITIES: Capitalization (see statements of capitalization): Common equity $ 814,107 $ 735,029 Cumulative preferred stock 40,000 40,000 Long-term debt (Note 9) 346,562 434,506 1,200,669 1,209,535 Current liabilities: Current portion of long-term debt (Note 9) 153,930 54,000 Notes payable to parent (Note 10) 119,490 47,790 Accounts payable 95,374 85,149 Accrued taxes 4,955 20,520 Other 21,442 22,150 395,191 229,609 Deferred credits and other liabilities: Accumulated deferred income taxes (Notes 1 and 7) 241,184 239,204 Investment tax credit, in process of amortization 8,500 11,455 Accumulated provision for pensions and related benefits (Note 6) 110,927 91,235 Regulatory liabilities (Note 3) 29,876 33,889 Other 12,036 11,975 402,523 387,758 Commitments and contingencies (Note 11) $1,998,383 $1,826,902 The accompanying notes are an integral part of these consolidated financial statements. Page 36 Kentucky Utilities Company and Subsidiary Consolidated Statements of Cash Flows (Thousands of $) Years Ended December 31 2002 2001 CASH FLOWS FROM OPERATING ACTIVITIES: Net income $ 93,384 $ 96,414 Items not requiring cash currently: Depreciation and amortization 95,462 90,299 Deferred income taxes - net (2,038) (12,088) Investment tax credit - net (2,955) (3,446) Other (1,267) 11,776 Change in certain net current assets: Accounts receivable (8,497) 28 Materials and supplies (2,928) (31,263) Accounts payable 10,225 8,810 Accrued taxes (15,565) 898 Prepayments and other (2,350) (6,033) Sale of accounts receivable (Note 1) 4,200 45,100 Other 8,086 (12,364) Net cash flows from operating activities 175,757 188,131 CASH FLOWS FROM INVESTING ACTIVITIES: Proceeds from sales of securities - 3,480 Construction expenditures (237,909) (142,425) Net cash flows from investing activities (237,909) (138,945) CASH FLOWS FROM FINANCING ACTIVITIES: Short-term borrowings and repayments 71,700 (13,449) Retirement of long-term debt (133,930) - Issuance of long-term debt 128,734 - Additional paid-in capital - - Payment of dividends (2,256) (32,756) Net cash flows used for financing activities 64,248 (46,205) Change in cash and temporary cash investments 2,096 2,981 Cash and temporary cash investments at beginning of year 3,295 314 Cash and temporary cash investments at end of year $ 5,391 $ 3,295 Supplemental disclosures of cash flow information: Cash paid during the year for: Income taxes $59,580 $72,432 Interest on borrowed money 37,866 39,829 The accompanying notes are an integral part of these consolidated financial statements. Page 37 Kentucky Utilities Company and Subsidiary Consolidated Statements of Capitalization (Thousands of $) December 31 2002 2001 COMMON EQUITY: Common stock, without par value - authorized 80,000,000 shares, outstanding 37,817,878 shares $ 308,140 $ 308,140 Additional paid-in-capital 15,000 15,000 Accumulated other comprehensive income (10,462) 1,588 Other (595) (595) Retained earnings 502,024 410,896 814,107 735,029 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 (Note 9); First mortgage bonds - 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 2B due February 1, 2018, 6.25% - 2,400 3B due February 1, 2018, 6.25% - 7,200 4B due February 1, 2018, 6.25% - 7,400 8, due September 15, 2016, 7.45% - 96,000 9, due December 1, 2023, 5.75% 50,000 50,000 10, due November 1, 2024, variable % 54,000 54,000 11, due May 1, 2023, variable % 12,900 12,900 12, due February 1, 2032, variable % 20,930 - 13, due February 1, 2032, variable % 2,400 - 14, due February 1, 2032, variable % 7,400 - 15, due February 1, 2032, variable % 7,200 - 16, due October 1, 2032, variable % 96,000 - Long-term debt marked to market (Note 4) 15,662 3,676 Total bonds outstanding 500,492 488,506 Less current portion of long-term debt 153,930 54,000 Long-term debt 346,562 434,506 Total capitalization $1,200,669 $1,209,535 The accompanying notes are an integral part of these consolidated financial statements. Page 38 Kentucky Utilities Company and Subsidiary Notes to Consolidated Financial Statements Note 1 - Summary of Significant Accounting Policies KU, a subsidiary of LG&E Energy and an indirect subsidiary of Powergen and E.ON, 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 KU's Common Stock is held by LG&E Energy. KU has one wholly owned consolidated subsidiary, KU R. On December 11, 2000, LG&E Energy was acquired by Powergen. On July 1, 2002, E.ON, a German company, completed its acquisition of Powergen plc (now Powergen Limited). E.ON had announced its pre-conditional cash offer of 5.1 billion pounds sterling ($7.3 billion) for Powergen on April 9, 2001. Powergen and E.ON are registered public utility holding companies under PUHCA. No costs associated with these acquisitions nor any of the effects of purchase accounting have been reflected in the financial statements of KU. Certain reclassification entries have been made to the previous year's financial statements to conform to the 2002 presentation with no impact on the balance sheet totals or previously reported income. 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. Pursuant to a final order of the Kentucky Commission dated December 3, 2001, KU implemented new deprecation rates effective January 1, 2001. The amounts provided were approximately 3.1% in 2002 and 3.1% in 2001, of average depreciable plant. Of the amount provided for depreciation at December 31, 2002 and 2001, respectively, approximately 0.7% was related to the retirement, removal and disposal costs of long lived assets. 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. Fuel Inventories. Fuel inventories of $46.1 million and $43.4 million at December 31, 2002 and 2001, respectively, are included in Fuel in the balance sheet. The inventory is accounted for using the average-cost method. 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. Page 39 Unamortized Debt Expense. Debt expense is capitalized in deferred debits and amortized over the lives of the related bond issues, consistent with regulatory practices. Deferred Income Taxes. Deferred income taxes are recognized at currently enacted tax rates for all material temporary differences between the financial reporting and income tax basis of assets and liabilities. 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. 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 were approximately $36.4 million and $33.4 million at December 31, 2002, and 2001, respectively. KU recorded electric revenues that resulted from sales to a related party, LG&E, of $34.6 million and $31.1 million for years ended December 31, 2002 and 2001, respectively. See Note 3, Rates and Regulatory Matters. With the adoption of EITF 02-03, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities, revenues on the income statement are shown net of cost associated with trading activities. As a result KU has netted the power purchased expense for trading activities against operating revenue for all years presented. 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. Accounts Receivable Securitization. SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, revises the standards for accounting for securitizations and other transfers of financial assets and collateral and requires certain disclosures, and provides accounting and reporting standards for transfers and servicing of financial assets and extinguishments of liabilities. SFAS No. 140 was adopted in the first quarter of 2001, when KU entered into an accounts receivable securitization transaction. On February 6, 2001, KU implemented an accounts receivable securitization program. The purpose of this program is to enable KU to accelerate the receipt of cash from the collection of retail accounts receivable, thereby reducing dependence upon more costly sources of working capital. The securitization program allows for a percentage of eligible receivables to be sold. Eligible receivables are generally all receivables associated with retail sales that have standard terms and are not past due. KU is able to terminate this program at any time without penalty. If there is a significant deterioration in the payment record of the receivables by the retail customers or if KU fails to meet certain covenants regarding the program, the program may terminate at the election of the financial institutions. In this case, payments from retail customers would first be used to repay the financial institutions participating in the program, and would then be available for use by KU. As part of the program, KU sold retail accounts receivables to a wholly owned subsidiary, KU R. Simultaneously, KU R entered into two separate Page 40 three-year accounts receivable securitization facilities with two financial institutions and their affiliates whereby KU R can sell, on a revolving basis, an undivided interest in certain of its receivables and receive up to $50 million from an unrelated third party purchaser. The effective cost of the receivables programs is comparable to KU's lowest cost source of capital, and is based on prime rated commercial paper. KU retains servicing rights of the sold receivables through two separate servicing agreements with the third party purchaser. KU has obtained an opinion from independent legal counsel indicating these transactions qualify as a true sale of receivables. As of December 31, 2002, the outstanding program balance was $49.3 million. KU is considering unwinding its accounts receivable securitization arrangements involving KU R during 2003. The allowance for doubtful accounts associated with the eligible securitized receivables was $520,000 at December 31, 2002. This allowance is based on historical experience of KU. Each securitization facility contains a fully funded reserve for uncollectible receivables. New Accounting Pronouncements. SFAS No. 143, Accounting for Asset Retirement Obligations was issued in 2001. SFAS No. 143 establishes accounting and reporting standards for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The effective implementation date for SFAS No. 143 is January 1, 2003. Management has calculated the impact of SFAS No. 143 and the recently released FERC NOPR No. RM02-7, Accounting, Financial Reporting, and Rate Filing Requirements for Asset Retirement Obligations. As of January 1, 2003, KU recorded asset retirement obligation (ARO) assets in the amount of $8.6 million and liabilities in the amount of $18.5 million. KU also recorded a cumulative effect adjustment in the amount of $9.9 million to reflect the accumulated depreciation and accretion of ARO assets at the transition date less amounts previously accrued under regulatory depreciation. KU recorded offsetting regulatory assets of $9.9 million, pursuant to regulatory treatment prescribed under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. Also pursuant to SFAS No. 71, KU recorded regulatory liabilities in the amount of $888,000 offsetting removal costs previously accrued under regulatory accounting in excess of amounts allowed under SFAS No. 143. KU also expects to record ARO accretion expense of approximately $1.2 million, ARO depreciation expense of approximately $176,000 and an offsetting regulatory credit in the income statement of approximately $1.4 million in 2003, pursuant to regulatory treatment prescribed under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. The accretion, depreciation and regulatory credit will be annual adjustments. SFAS No. 143 will have no impact on the results of the operation of KU. KU asset retirement obligations are primarily related to the final retirement of generating units. KU transmission and distribution lines largely operate under perpetual property easement agreements which do not generally require restoration upon removal of the property. Therefore, under SFAS No. 143, no material asset retirement obligations will be recorded for transmission and distribution assets. KU adopted EITF No. 98-10, Accounting for Energy Trading and Risk Management Activities, effective January 1, 1999. This pronouncement required that energy trading contracts be marked to market on the balance sheet, with the gains and losses shown net in the income statement. The EITF clarified accounting standards related to energy trading activities under EITF Issue 02-03, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Page 41 Energy Trading and Risk Management Activities. EITF No. 02-03 established the following: - Rescinded EITF No. 98-10, - Contracts that do not meet the definition of a derivative under SFAS No. 133 should not be marked to fair market value, and - Revenues should be shown in the income statement net of costs associated with trading activities, whether or not the trades are physically settled. With the rescission of EITF No. 98-10, energy trading contracts that do not also meet the definition of a derivative under SFAS No. 133 must be accounted for as executory contracts. Contracts previously recorded at fair value under EITF No. 98-10 that are not also derivatives under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, must be restated to historical cost through a cumulative effect adjustment. The rescission of this standard had no impact on financial position or results of operations of KU since all contracts marked to market under EITF No. 98- 10 are also within the scope of SFAS No. 133. As a result of EITF No. 02-03, KU has netted the power purchased expense for trading activities against electric operating revenue to reflect this accounting change. KU applied this guidance to all prior periods, which had no impact on previously reported net income or common equity. 2002 2001 Gross electric operating revenues $875,192 $860,426 Less costs reclassified from power purchased 26,555 38,751 Net electric operating revenues reported $848,637 $821,675 Gross power purchased $157,955 $157,161 Less costs reclassified to revenues 26,555 38,751 Net power purchased reported $131,400 $118,410 In January 2003, the Financial Accounting Standards Board issued Financial Accounting Standards Board Interpretation No. 46, Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51 (FIN 46). FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. FIN 46 is effective immediately for all new variable interest entities created or acquired after January 31, 2003. For variable interest entities created or acquired prior to February 1, 2003, the provisions of FIN 46 must be applied for the first interim or annual period beginning after June 15, 2003. KU does not expect the adoption of this standard to have any impact on the financial position or results of operations. Note 2 - Mergers and Acquisitions On July 1, 2002, E.ON completed its acquisition of Powergen, including LG&E Energy, for approximately 5.1 billion pounds sterling ($7.3 billion). As a result of the acquisition, LG&E Energy became a wholly owned subsidiary (through Powergen) of E.ON and, as a result, KU also became an indirect subsidiaryof E.ON. KU has continued its separate identity and serves customers in Kentucky, Virginia and Tennessee under its existing names. The preferred stock and debt securities of KU were not affected by this transaction and the utilities continue to file SEC reports. Following the acquisition, E.ON became, and Powergen remained, a registered holding company under PUHCA. KU, as a subsidiary of a registered holding company, is subject to additional regulations under PUHCA. As contemplated in their regulatory filings in connection with the E.ON acquisition, E.ON, Powergen and LG&E Energy completed an administrative reorganization to move the LG&E Energy group from an indirect Powergen subsidiary to an indirect E.ON subsidiary. This reorganization was effective in March 2003. Page 42 LG&E Energy and KU Energy merged on May 4, 1998, with LG&E Energy as the surviving corporation. Management accounted for the merger as a pooling of interests and as a tax-free reorganization under the Internal Revenue Code. Following these acquisitions, KU has continued to maintain its separate identity and serve customers under its present name. 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, 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 $): 2002 2001 VDT costs $ 38,375 $ 48,811 Unamortized loss on bonds 9,456 6,142 LG&E/KU merger costs 2,046 6,139 One utility costs 873 4,365 ESM provision 13,500 - Other 1,154 1,010 Total regulatory assets 65,404 66,467 Deferred income taxes - net (28,854) (32,872) Other (1,022) (1,017) Total regulatory liabilities (29,876) (33,889) Regulatory assets - net $ 35,528 $ 32,578 Kentucky Commission Settlement Order - VDT Costs. During the first quarter 2001, KU recorded a $64 million charge for a workforce reduction program. Primary components of the charge were separation benefits, enhanced early retirement benefits, and health care benefits. The result of this workforce reduction was the elimination of approximately 300 positions, accomplished primarily through a voluntary enhanced severance program. On June 1, 2001, KU filed an application (VDT case) with the Kentucky Commission to create a regulatory asset relating to these first quarter 2001 charges. The application requested permission to amortize these costs over a four-year period. The Kentucky Commission also opened a case to review a new depreciation study and resulting depreciation rates implemented in 2001. KU reached a settlement in the VDT case as well as the other cases involving depreciation rates and ESM with all intervening parties. The settlement agreement was approved by the Kentucky Commission on December 3, 2001. The order allowed KU to set up a regulatory asset of $54 million for the workforce reduction costs and begin amortizing these costs over a five year period starting in April 2001. The first quarter 2001 charge of $64 million represented all employees who had accepted a voluntary enhanced Page 43 severance program. Some employees rescinded their participation in the voluntary enhanced severance program and, along with the non-recurring charge of $6.9 million for FERC and Virginia jurisdictions, thereby decreasing the original charge of the regulatory asset from $64 million to $54 million. The settlement will also reduce revenues approximately $11 million through a surcredit on future bills to customers over the same five year period. The surcredit represents net savings stipulated by KU. The agreement also established KU's new depreciation rates in effect December 2001, retroactive to January 1, 2001. The new depreciation rates decreased depreciation expense by $6.0 million in 2001. PUHCA. LG&E Energy was purchased by Powergen on December 11, 2000. Effective July 1, 2002, Powergen was acquired by E.ON, which became a registered holding company under PUHCA. As a result, E.ON, 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. KU believes that it has adequate authority (including financing authority) under existing SEC orders and regulations to conduct its business. KU will seek additional authorization when necessary. Environmental Cost Recovery. In June 2000, the Kentucky Commission approved KU's application for a CCN to construct up to four SCR 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 2004. 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 ECR Tariff to include an overall rate of return on capital investments. Approval of KU's application in April 2001 allowed 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. In August 2002, KU filed an application with the Kentucky Commission to amend its compliance plan to allow recovery of the cost of a new and additional environmental compliance facility. The estimated capital cost of the additional facilities is $17.3 million. The Kentucky Commission conducted a public hearing on the case on December 20, 2002, final briefs were filed on January 15, 2003, and a final order was issued February 11, 2003. The final order approved recovery of the new environmental compliance facility totaling $17.3 million. Cost recovery through the environmental surcharge of the approved project will begin with bills rendered in April 2003. ESM. KU's electric rates are subject to an ESM. The ESM, initially 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, the excess earnings are shared 40% with ratepayers and 60% with shareholders; if earnings are below the lower limit, the earnings deficiency is recovered 40% from ratepayers and 60% from shareholders. By order of the Kentucky Commission, rate changes prompted by the ESM filing go into effect in April of each year subject to a balancing adjustment in successive periods. KU made its second ESM filing on March 1, 2002 for the calendar year 2001 reporting period. KU is in the process of refunding $1 million to customers for the 2001 reporting period. KU estimated that the rate of return will fall below the lower limit, subject to Kentucky Commission approval, for the year ended December 31, 2002. The 2002 financial statements include an accrual to reflect the earnings deficiency of $13.5 million to be recovered from customers commencing in April 2003. On November 27, 2002, KU filed a revised ESM tariff which proposed continuance of the existing ESM through December 2005. The Kentucky Commission issued an order suspending the ESM tariff one day making the Page 44 effective date January 2, 2003. In addition, the Kentucky Commission is conducting a management audit to review the ESM plan and reassess its reasonableness in 2003. KU and interested parties will have the opportunity to provide recommendations for modification and continuance of the ESM or other forms of alternative or incentive regulation. DSM. In May 2001, the Kentucky Commission approved a plan that would expand LG&E's current DSM programs into the service territory served by KU. The filing included a rate mechanism that provided for concurrent recovery of DSM costs, provided an incentive for implementing DSM programs, and recovered revenues from lost sales associated with the DSM program based on program planning engineering estimates and post-implementation evaluation. FAC. KU employs a FAC mechanism which allows KU to recover from customers' 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. In August 1999, after a rehearing request by KU, the Kentucky Commission issued a final order that reduced the refund obligation to $6.7 million ($5.8 million on a Kentucky jurisdictional basis) from the original order amount of $10.1 million. KU implemented the refund from October 1999 through September 2000. Both KU and the KIUC appealed the order. Pending a decision on this appeal, a comprehensive settlement was reached by all parties and approved by the Kentucky Commission on May 17, 2002. Thereunder, KU agreed to credit its fuel clause in the amount of $954,000 (refund made in June and July 2002), and the parties agreed on a prospective interpretation of the state's FAC regulation to ensure consistent and mutually acceptable application on a going-forward basis. In December 2002, the Kentucky Commission initiated a two year review of the operation of KU's FAC for the period November 2000 through October 2002. Testimony in the review case was filed on January 20, 2003 and a public hearing was held February 18, 2003. Issues addressed at that time included the establishment of the current base fuel factor to be included in KU's base rates, verification of proper treatment of purchased power costs during unit outages, and compliance with fuel procurement policies and practices. 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 intended 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. During the period September 1998 to February 2000, the Kentucky Commission issued draft codes of conduct and cost allocation guidelines. In early 2000, the Kentucky General Assembly enacted legislation, House Bill 897, which authorized the Kentucky Commission to require utilities that provide nonregulated activities to keep separate accounts and allocate costs in accordance with procedures established by the Kentucky Commission. In the same Bill, the General Assembly set forth provisions to govern a utility's 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. On February 14, 2001, the Kentucky Commission published notice of their intent to promulgate new administrative regulations under the auspices of this new law. This effort is still on-going. Page 45 Kentucky Commission Administrative Case for System Adequacy. On June 19, 2001, Kentucky Governor Paul E. Patton issued Executive Order 2001-771, which directed the Kentucky Commission to review and study issues relating to the need for and development of new electric generating capacity in Kentucky. The issues to be considered included the impact of new power plants on the electric supply grid, facility citing issues, and economic development matters, with the goal of ensuring a continued, reliable source of supply of electricity for the citizens of Kentucky and the continued environmental and economic vitality of Kentucky and its communities. In response to that Executive Order, in July 2001 the Kentucky Commission opened Administrative Case No. 387 to review the adequacy of Kentucky's generation capacity and transmission system. Specifically, the items reviewed were the appropriate level of reliance on purchased power, the appropriate reserve margins to meet existing and future electric demand, the impact of spikes in natural gas prices on electric utility planning strategies, and the adequacy of Kentucky's electric transmission facilities. KU, as a party to this proceeding, filed written testimony and responded to two requests for information. Public hearings were held October 2001 and KU filed a final brief in the case. In December 2001, the Kentucky Commission issued an order in which it noted that KU is responsibly addressing the long-term supply needs of native load customers and that current reserve margins are appropriate. However, due to the rapid pace of change in the industry, the order also requires KU to provide an annual assessment of supply resources, future demand, reserve margin, and the need for new resources. Regarding the transmission system, the Kentucky Commission concluded that the transmission system within Kentucky can reliably serve native load and a significant portion of the proposed new unregulated power plants. However, it will not be able to handle the volume of transactions envisioned by FERC without future upgrades, the costs of which should be borne by those for whom the upgrades are required. The Kentucky Commission pledged to continue to monitor all relevant issues and advocate Kentucky's interests at all opportunities. FERC SMD NOPR. On July 31, 2002, the FERC issued a NOPR in Docket No. RM01- 12-000 which would substantially alter the regulations governing the nation's wholesale electricity markets by establishing a common set of rules -- SMD. The SMD NOPR would require each public utility that owns, operates, or controls interstate transmission facilities to become an Independent Transmission Provider (ITP), belong to an RTO that is an ITP, or contract with an ITP for operation of its transmission assets. It would also establish a standardized congestion management system, real-time and day-ahead energy markets, and a single transmission service for network and point-to-point transmission customers. Review of the proposed rulemaking is underway and a final rule is expected during 2003. While it is expected that the SMD final rule will affect KU revenues and expenses, the specific impact of the rulemaking is not known at this time. MISO. KU is a member of the MISO, which began commercial operations on February 1, 2002. MISO now has operational control over KU's high-voltage transmission facilities (100 kV and greater), while KU continues to control and operate the lower voltage transmission subject to the terms and conditions of the MISO OATT. As a transmission-owning member of MISO, KU also incurs administrative costs of MISO pursuant to Schedule 10 of the MISO OATT. MISO also proposed to implement a congestion management system. FERC directed the MISO to coordinate its efforts with FERC's Rulemaking on SMD. On September 24, 2002, the MISO filed new rate schedules designated as Schedules 16 and 17, which provide for the collection of costs incurred by the MISO to establish day-ahead and real-time energy markets. The MISO proposed to recover these costs under Schedules 16 and 17 once service commences. If approved by FERC, these schedules will cause KU to incur additional costs. KU opposes the establishment of Schedules 16 and 17. This effort is still on-going and the ultimate impact of the two schedules, if approved, is not known at this time. Page 46 ARO. In 2003, KU expects to record approximately $11.3 million in regulatory assets and approximately $888,000 in regulatory liabilities related to SFAS No. 143, Accounting for Asset Retirement Obligations. Merger Surcredit. As part of the LG&E Energy merger with KU Energy, KU estimated 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 was deferred and 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) in the second quarter of 1998. In approving the merger, the Kentucky Commission adopted KU's proposal to reduce its retail customers' bills based on one-half of the estimated merger-related savings, net of deferred and amortized amounts, over a five year period. The surcredit mechanism provides that 50% of the net non-fuel cost savings estimated to be achieved from the merger would be provided to ratepayers through a monthly bill credit, and 50% retained by the Companies, over a five-year period. The surcredit was allocated 53% to KU and 47% to LG&E. In that same order, the Commission required LG&E and KU, after the end of the five-year period, to present a plan for sharing with customers the then-projected non-fuel savings associated with the merger. The Companies submitted this filing on January 13, 2003, proposing to continue to share with customers, on a 50%/50% basis, the estimated fifth- year gross level of non-fuel savings associated with the merger. The filing is currently under review. Any fuel cost savings are passed to Kentucky customers through the fuel adjustment clauses. See FAC above. Note 4 - Financial Instruments The cost and estimated fair values of KU's non-trading financial instruments as of December 31, 2002, and 2001 follow (in thousands of $): 2002 2001 Fair Fair Cost Value Cost Value Long-term debt (including current portion) $484,830 $503,194 $484,830 $499,618 Interest-rate swaps - 16,928 - 6,906 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 uses interest rate swaps to hedge exposure to market fluctuations in certain of its debt instruments. Pursuant to policy, use of these financial instruments is intended to mitigate risk and earnings volatility and is not speculative in nature. Management has designated all of the interest rate swaps as hedge instruments. Financial instruments designated as fair value hedges are periodically marked to market with the resulting gains and losses recorded directly into net income to correspond with income or expense recognized from changes in market value of the items being hedged. As of December 31, 2002 and 2001, KU was party to various interest rate swap agreements with aggregate notional amounts of $153 million in 2002 and 2001. Under these swap agreements, KU paid variable rates based on either Page 47 LIBOR or the Bond Market Association's municipal swap index averaging 2.36% and 2.54%, and received fixed rates averaging 7.13% and 7.13% at December 31, 2002 and 2001, respectively. The swap agreements in effect at December 31, 2002 have been designated as fair value hedges and mature on dates ranging from 2007 to 2025. For 2002, the effect of marking these financial instruments and the underlying debt to market resulted in immaterial pretax gains recorded in interest expense. Interest rate swaps hedge interest rate risk on the underlying debt under SFAS 133, in addition to swaps being marked to market, the item being hedged must also be marked to market, consequently at December 31, 2002, KU's debt reflects a $15.7 million mark to market adjustment. Energy Trading & Risk Management Activities. KU conducts energy trading and risk management activities to maximize the value of power sales from physical assets it owns, in addition to the wholesale sale of excess asset capacity. Certain energy trading activities are accounted for on a mark-to- market basis in accordance with EITF 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities, SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities. Wholesale sales of excess asset capacity and wholesale purchases are treated as normal sales and purchases under SFAS No. 133 and SFAS No. 138 and are not marked-to-market. The consensus reached by the EITF on EITF No. 02-03, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities, to rescind EITF 98-10, effective for fiscal years after December 15, 2002, had no impact on KU's energy trading and risk management reporting as all contracts marked to market under EITF 98-10 are also within the scope of SFAS No. 133. The table below summarizes KU's energy trading and risk management activities for 2002 and 2001 (in thousands of $). 2002 2001 Fair value of contracts at beginning of period, net liability $ (186) $ (17) Fair value of contracts when entered into during the period (65) 3,441 Contracts realized or otherwise settled during the period 448 (2,894) Changes in fair values due to changes in assumptions (353) (716) Fair value of contracts at end of period, net liability $ (156) $ (186) No changes to valuation techniques for energy trading and risk management activities occurred during 2002. Changes in market pricing, interest rate and volatility assumptions were made during both years. All contracts outstanding at December 31, 2002, have a maturity of less than one year and are valued using prices actively quoted for proposed or executed transactions or quoted by brokers. KU maintains policies intended to minimize credit risk and revalues credit exposures daily to monitor compliance with those policies. At December 31, 2002, 86% of the trading and risk management commitments were with counterparties rated BBB- equivalent or better. 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. Page 48 KU's customer receivables and revenues arise from deliveries of electricity to approximately 477,000 customers in over 600 communities and adjacent suburban and rural areas in 77 counties in central, southeastern and western Kentucky, to approximately 30,000 customers in five counties in southwestern Virginia and less than ten customers in Tennessee. For the year ended December 31, 2002, 100% of total utility revenue was derived from electric operations. In August 2001, KU and its employees represented by IBEW Local 2100 entered into a two-year collective bargaining agreement. KU and its employees represented by USWA Local 9447-01 entered into a three-year collective bargaining agreement effective August 2002 and expiring August 2005. The employees represented by these two bargaining units comprise approximately 17% of KU's workforce. Note 6 - Pension Plans and Retirement Benefits 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 two-year period ending December 31, 2002, and a statement of the funded status as of December 31 for each of the last two years (in thousands of $): 2002 2001 Pension Plans: Change in benefit obligation Benefit obligation at beginning of year $244,472 $233,034 Service cost 2,637 2,761 Interest cost 16,598 17,534 Plan amendment 28 4 Change due to transfers - (16,827) Curtailment loss - 1,400 Special termination benefits - 24,274 Benefits paid (23,291) (29,166) Actuarial (gain) or loss and other 7,283 11,458 Benefit obligation at end of year $247,727 $244,472 Change in plan assets Fair value of plan assets at beginning of year $216,947 $244,677 Actual return on plan assets (13,767) 18,155 Employer contributions and plan transfers (99) (15,300) Benefits paid (23,291) (29,166) Administrative expenses (1,256) (1,419) Fair value of plan assets at end of year $178,534 $216,947 Reconciliation of funded status Funded status $(69,193) $(27,525) Unrecognized actuarial (gain) or loss 36,233 (20,581) Unrecognized transition (asset) or obligation (532) (664) Unrecognized prior service cost 10,106 11,027 Net amount recognized at end of year $(23,386) $(37,743) Page 49 Other Benefits: Change in benefit obligation Benefit obligation at beginning of year $ 83,223 $ 64,213 Service cost 610 495 Interest cost 6,379 5,433 Plan amendments - - Curtailment loss - 6,381 Special termination benefits - 3,824 Benefits paid net of retiree contributions (4,640) (5,446) Actuarial (gain) or loss 19,030 8,323 Benefit obligation at end of year $104,602 $ 83,223 Change in plan assets Fair value of plan assets at beginning of year $ 14,330 $ 23,762 Actual return on plan assets (2,698) (4,404) Employer contributions and plan transfers 1,648 473 Benefits paid net of retiree contributions (5,337) (5,501) Fair value of plan assets at end of year $ 7,943 $ 14,330 Reconciliation of funded status Funded status $(96,659) $(68,893) Unrecognized actuarial (gain) or loss 22,667 (437) Unrecognized transition (asset) or obligation 11,209 12,290 Unrecognized prior service cost 2,891 3,548 Net amount recognized at end of year $(59,892) $(53,492) There are no plan assets in the non-qualified plan due to the nature of the plan. KU made a contribution to the pension plan of $3.5 million in January 2003. 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, 2002 and 2001 (in thousands of $): 2002 2001 Pension Plans: Amounts recognized in the balance sheet consisted of: Accrued benefit liability $ (51,035) $(37,743) Intangible asset 10,106 - Accumulated other comprehensive income 17,543 - Net amount recognized at year-end $(23,386) $(37,743) Additional year-end information for plans with accumulated benefit obligations in excess of plan assets (1): Projected benefit obligation $247,727 $244,472 Accumulated benefit obligation 229,569 224,261 Fair value of plan assets 178,534 216,947 (1) 2002 and 2001 includes all plans. Other Benefits: Amounts recognized in the balance sheet consisted of: Accrued benefit liability $(59,892) $(53,492) Additional year-end information for plans with benefit obligations in excess of plan assets: Projected benefit obligation $104,602 $ 83,223 Fair value of plan assets 7,943 14,330 Page 51 The following table provides the components of net periodic benefit cost for the plans for 2002 and 2001 (in thousands of $): 2002 2001 Pension Plans: Components of net periodic benefit cost Service cost $ 2,637 $ 2,761 Interest cost 16,598 17,534 Expected return on plan assets (18,406) (19,829) Amortization of transition (asset) or obligation (133) (136) Amortization of prior service cost 956 962 Recognized actuarial (gain) or loss 1 (120) Net periodic benefit cost $ 1,653 $ 1,172 Special charges Prior service cost recognized $ - $ 1,238 Special termination benefits - 24,274 Total charges $ - $ 25,512 Other Benefits: Components of net periodic benefit cost Service cost $ 610 $ 495 Interest cost 6,379 5,433 Expected return on plan assets (1,022) (1,313) Amortization of prior service cost 691 740 Amortization of transition (asset) or obligation 1,081 1,193 Recognized actuarial (gain) or loss 343 (40) Net periodic benefit cost $ 8,082 $ 6,508 Special charges Transition obligation recognized $ - $ 7,638 Prior service cost recognized - 1,613 Special termination benefits - 3,824 Total charges $ - $ 13,075 The assumptions used in the measurement of KU's pension benefit obligation are shown in the following table: 2002 2001 Weighted-average assumptions as of December 31: Discount rate 6.75% 7.25% Expected long-term rate of return on plan assets 9.00% 9.50% Rate of compensation increase 3.75% 4.25% For measurement purposes, a 12.00% annual increase in the per capita cost of covered health care benefits was assumed for 2003. The rate was assumed to decrease gradually to 5.00% for 2014 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 $): Page 52 1% Decrease 1% Increase Effect on total of service and interest cost components for 2002 (422) 479 Effect on year-end 2002 postretirement benefit obligations (7,010) 7,972 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 $1.5 million for 2002 and $1.4 million for 2001. Note 7 - Income Taxes Components of income tax expense are shown in the table below (in thousands of $): 2002 2001 Included in operating expenses: Current - federal $38,524 $58,337 - state 10,494 13,465 Deferred - federal - net 3,467 (12,980) - state - net 1,547 (1,340) Total 54,032 57,482 Included in other income - net: Current - federal (685) (948) - state 15 (268) Deferred - federal - net (195) 863 - state - net (88) 222 Amortization of investment tax credit (2,955) (3,446) Total (3,908) (3,577) Total income tax expense $50,124 $53,905 Components of net deferred tax liabilities included in the balance sheet are shown below (in thousands of $): 2002 2001 Deferred tax liabilities: Depreciation and other plant-related items $271,792 $269,752 Other liabilities 30,378 33,376 302,170 303,128 Deferred tax assets: Investment tax credit 3,431 4,623 Income taxes due to customers 11,609 13,263 Pensions 15,861 4,595 Accrued liabilities not currently deductible and other 30,085 41,443 60,986 63,924 Net deferred income tax liability $241,184 $239,204 Page 53 A reconciliation of differences between the statutory U.S. federal income tax rate and KU's effective income tax rate follows: 2002 2001 Statutory federal income tax rate 35.0% 35.0% State income taxes, net of federal benefit 5.5 5.4 Amortization of investment tax credit (2.4) (2.3) Other differences - net (3.2) (2.2) Effective income tax rate 34.9% 35.9% The change in other differences is due to increased non-taxable earnings from an unconsolidated KU investment. Note 8 - Other Income - net Other income - net consisted of the following at December 31 (in thousands of $): 2002 2001 Equity in earnings - subsidiary company $ 6,697 $ 1,803 Interest and dividend income 641 1,368 Gains on fixed asset disposals 157 1,844 Income taxes and other 2,934 3,917 Other income - net $10,429 $ 8,932 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, 2002. Weighted Average Stated Interest Principal Interest Rates Rate Maturities Amounts Noncurrent portion Variable - 8.55% 5.21% 2006-2032 $346,562 Current portion Variable - 6.32% 3.58% 2003-2032 $153,930 Under the provisions for KU's variable-rate pollution control bonds Series PCS 10, 12, 13, 14, and 15, 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 in the consolidated balance sheets. The average annualized interest rate for these bonds during 2002 was 1.58%. In September 2002, KU issued $96 million variable rate pollution control Series 16 due October 1, 2032, and exercised its call option on $96 million, 7.45% pollution control Series 8 due September 15, 2016. In May 2002, KU issued $37.9 million variable rate pollution control Series 12, 13, 14 and 15 due February 1, 2032, and exercised its call option on $37.9 million, 6.25% pollution control Series 1B, 2B, 3B, and 4B due February 1, 2018. Page 54 KU's First Mortgage Bond, 6.32% Series Q of $62 million is scheduled to mature in June 2003, KU's First Mortgage Bond, 5.99% Series S of $36 million matures in 2006, and KU's First Mortgage Bond, 7.92% Series P of $53 million matures in 2007. There are no scheduled maturities of Pollution Control Bonds for the five years subsequent to December 31, 2002. Substantially all of KU's utility plant is pledged as security for its First Mortgage Bonds. Note 10 - Notes Payable to Parent KU participates in an intercompany money pool agreement wherein LG&E Energy can make funds available to KU at market based rates up to $400 million. The balance of the money pool loan from LG&E Energy was $119.5 million at a rate of 1.61% and $47.8 million at an average rate of 2.37% at December 31, 2002 and 2001, respectively. The remaining money pool availability at December 31, 2002, was $280.5 million. LG&E Energy maintains facilities of $450 million with affiliates to ensure funding availability for the money pool. The outstanding balance under these facilities as of December 31, 2002 was $230 million, and availability of $220 million remained. Note 11 - Commitments and Contingencies Construction Program. KU had approximately $6.2 million of commitments in connection with its construction program at December 31, 2002. Construction expenditures for the years 2003 and 2004 are estimated to total approximately $550.0 million; although all of this is not currently committed, including the purchase of four jointly owned CTs, $152.0 million, and construction of NOx equipment, $177.0 million. Operating Leases. KU leases office space, office equipment, and vehicles. KU accounts for these leases as operating leases. Total lease expense for 2002 and 2001 was $2.6 million and $2.8 million, respectively. 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 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 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. As a result of appeals to both rules, the compliance date was extended to May 2004. All KU generating units are subject to the May 2004 compliance date under these NOx emissions reduction rules. Page 54 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. 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 had anticipated that such capital and operating costs are the type of costs that are eligible for recovery from customers under its environmental surcharge mechanism and believed that a significant portion of such costs could be recovered. In April 2001, the Kentucky Commission granted recovery of these costs for KU. KU 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. KU owns or formerly owned several properties that 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 incurred costs of approximately $1.8 million and received insurance reimbursement of $1.2 million. In December 2002, the Department of Justice (DOJ) sent correspondence to KU regarding a potential per-day fine for failure to timely submit a spill control plan and a per-gallon fine for the amount of oil discharged. KU and the DOJ have commenced settlement discussions using existing DOJ settlement guidelines on this matter. In April 2002, the EPA sent correspondence to KU regarding potential exposure in connection with $1.5 million in completed remediation costs associated with a transformer scrap-yard. KU believes it is one of the more remote among a number of potentially responsible parties and has entered into settlement discussions with the EPA on this matter. 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 2003-2007, which is expected to be approximately 8% of KU's total kWh native load energy 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 costs of the station allocated per terms of the OMU agreement, which generally follow delivered kWh. Included in the total costs is KU's proportionate share of debt service requirements on $149.6 million of OMU bonds outstanding at December 31, 2002. The debt service is allocated to KU based on its annual allocated share of capacity, which averaged approximately 50% in 2002. 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 follow delivered kWh. Page 56 KU has several other contracts for purchased power of various Mw capacities. The estimated future minimum annual payments under purchased power agreements for the years subsequent to December 31, 2002, are as follows (in thousands of $): 2003 $ 34,317 2004 39,653 2005 39,653 2006 39,884 2007 39,994 Thereafter 643,946 Total $837,447 Page 57 Note 12 - Jointly Owned Electric Utility Plant LG&E and KU jointly own the following combustion turbines (in thousands of $): LG&E KU Total Paddy's Run 13 Ownership % 53% 47% 100% Mw capacity 84 74 158 Cost $33,919 $29,973 $63,892 Depreciation 1,711 1,499 3,210 Net book value $32,208 $28,474 $60,682 E.W. Brown 5 Ownership % 53% 47% 100% Mw capacity 71 63 134 Cost $23,973 $21,106 $45,079 Depreciation 1,206 1,052 2,258 Net book value $22,767 $20,054 $42,821 E.W. Brown 6 Ownership % 38% 62% 100% Mw capacity 59 95 154 Cost $23,696 $36,957 $60,653 Depreciation 1,770 4,201 5,971 Net book value $21,926 $32,756 $54,682 E.W. Brown 7 Ownership % 38% 62% 100% Mw capacity 59 95 154 Cost $23,607 $44,792 $68,399 Depreciation 4,054 4,502 8,556 Net book value $19,553 $40,290 $59,843 Trimble 5 Ownership % 29% 71% 100% Mw capacity 45 110 155 Cost $15,970 $39,045 $55,015 Depreciation 251 614 865 Net book value $15,719 $38,431 $54,150 Trimble 6 Ownership % 29% 71% 100% Mw capacity 45 110 155 Cost $15,961 $39,025 $54,986 Depreciation 251 614 865 Net book value $15,710 $38,411 $54,121 Trimble CT Ownership % 29% 71% 100% Pipeline Cost $1,835 $4,475 $6,310 Depreciation 39 96 135 Net book value $1,796 $4,379 $6,175 See also Note 11, Construction Program, for KU's planned purchase of four jointly owned CTs in 2004. Page 58 Note 13 - Selected Quarterly Data (Unaudited) Selected financial data for the four quarters of 2002 and 2001 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 $) 2002 Revenues $209,023 $196,020 $235,059 $221,562 Net operating income 28,200 20,047 31,028 29,368 Net income 24,357 12,752 31,085 25,190 Net income available for common stock 23,793 12,188 30,521 24,626 2001 Revenues $206,162 $201,745 $212,438 $200,376 Net operating income (loss) (a) (344) 28,422 30,253 63,039 Net income (loss) (a) (7,995) 22,080 26,340 55,989 Net income (loss) available for common stock (a) (8,559) 21,516 25,776 55,425 (a) Loss resulted from the VDT pre-tax charge of $64.0 million in March 2001, which $57.1 million was reversed in December 2001. See Note 3. Note 14 - Subsequent Events In January 2003, the Kentucky Commission reviewed the FAC of KU for the six month period ended October 31, 2001. The Kentucky Commission ordered KU to reduce its fuel costs for purposes of calculating its FAC by $673,000. At issue was the purchase of approximately 102,000 tons of coal from Western Kentucky Energy Corporation, a non-regulated affiliate, for use at KU's Ghent Facility. The Kentucky Commission further ordered that an independent audit be conducted to examine operational and management aspects of KU's fuel procurement functions. On February 15, 2003, KU experienced a severe ice storm in Lexington, Kentucky, and surrounding service area causing over 140,000 customers to lose power. KU is still in the process of accumulating the costs of the storm. Costs relate to repair of transmission and distribution system, property damage, and significant labor costs, including contractor costs. A portion of the costs may be offset by insurance proceeds. On March 18, 2003, the Kentucky Commission approved LG&E and KU's joint application for the acquisition of four CTs from an unregulated affiliate, LG&E Capital Corp. The total projected construction cost for the turbines, expected to be available for June 2004 in-service, is $227.4 million. The requested ownership share of the turbines is 63% for KU and 37% for LG&E. Page 59 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. These statements have been prepared in accordance with accounting principles generally accepted in the United States applied on a consistent basis and, necessarily, include amounts that reflect the best estimates and judgment of management. KU's 2002 and 2001 financial statements have been audited by PricewaterhouseCoopers LLP, independent accountants. Management made available to PricewaterhouseCoopers 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 and external auditors. These recommendations for the year ended December 31, 2002, did not identify any material weaknesses in the design and operation of KU's internal control structure. In carrying out its oversight role for the financial reporting and internal controls of KU, the Board of Directors meets regularly with KU's independent public accountants, internal auditors and management. The Board of Directors 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 Board of Directors 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 Board of Directors 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. S. Bradford Rives Chief Financial Officer Kentucky Utilities Company Louisville, Kentucky November 12, 2003 Page 60 Kentucky Utilities Company and Subsidiary REPORT OF INDEPENDENT ACCOUNTANTS To the Shareholders of Kentucky Utilities Company and Subsidiary: In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of capitalization, income, retained earnings, cash flows and comprehensive income present fairly, in all material respects, the financial position of Kentucky Utilities Company and Subsidiary (the "Company"), a wholly-owned subsidiary of LG&E Energy Corp., at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audits 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. As discussed in Note 1 to the financial statements, effective January 1, 2003, the Company adopted EITF No. 02-03, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities. /s/ PricewaterhouseCoopers LLP Louisville, Kentucky January 21, 2003, except for note 1 as to which the date is November 12, 2003 Page 61