Current Report

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

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

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.

                                   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

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

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.

                              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

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.

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.

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

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.

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

(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.

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

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.

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.

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

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.

                                                     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.

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.

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.

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.

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.

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.

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.

                                    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

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.

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

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.

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.

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.

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.

                                       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.

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.

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.

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

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

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.

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.

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,

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.

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.

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.

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.

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.

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.

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.

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.

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.

                                       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.

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.

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.

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.

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.

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.

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.

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.

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.

     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

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     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

Louisville Gas and Electric Company and Subsidiary Consolidated Statements of Income

(Thousands of $)

Years Ended December 31
2002 2001