TABLE OF CONTENTS

(a) Incorporated by reference.

RTOR

PART I

Item 1. Business.

Item 1.  Business.

LG&E and KU are each subsidiaries of LG&E Energy.  OnE.ON U.S. LLC (E.ON U.S.). Prior to December 11, 2000,1, 2005, E.ON U.S. LLC was known as LG&E Energy Corp., nowLLC. Previously, effective December 30, 2003, LG&E Energy LLC was acquiredhad become the successor, by Powergen plc, now known as Powergen Limited, for cash of approximately $3.2 billionassignment and subsequent merger, to all 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 Powergenassets and as a result, LG&E and KU became indirect subsidiaries of Powergen.  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 subsidiaryliabilities 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 fromCorp. E.ON U.S. is a subsidiary of E.ON AG (E.ON), a German corporation. E.ON acquired LG&E Energy LG&E and KU, were moved to LG&E Services.

Onthrough its July 1, 2002 E.ON, a German company, completed its acquisition of Powergen plc, (nownow Powergen Limited).  AsLimited (Powergen), a result, LG&EUnited Kingdom company and KU became indirect subsidiaries of E.ON.  E.ON had announced its pre-conditional cash offer of £5.1 billion ($7.3 billion) for Powergen on April 9, 2001.

Following the purchase of Powergen by E.ON, E.ON became a registered holding company under PUHCA.  As a result,for E.ON its utility subsidiaries, including LG&E and 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.  LG&E and KU believe that they have adequate authority (including financing authority) under existing SEC orders and regulations to conduct their business.  LG&E and KU will seek additional authorization when necessary.

UK plc, E.ON’s United Kingdom market unit operating parent. As contemplated in their regulatory filings in connection with the E.ON acquisition, E.ON, Powergen and LG&E EnergyE.ON U.S. completed an administrative reorganization to move the LG&E EnergyE.ON U.S. group from an indirect Powergen subsidiary to an indirect E.ON subsidiary. This reorganization was effective in March 2003. In early 2004, LG&E EnergyE.ON U.S. began direct reporting arrangements to E.ON.

LG&E and KU are now indirect subsidiaries of E.ON. As a result of these acquisitions and otherwise, E.ON and E.ON U.S. anticipate registering as holding companies under PUHCA 2005 and were formerly registered holding companies under PUHCA 1935.

In order to comply with PUHCA 1935, E.ON U.S. Services (formerly LG&E Energy Services), which was formed as a subsidiary service company of E.ON U. S., provides services to affiliated entities, including LG&E and KU, at cost as permitted under PUHCA 1935 and PUHCA 2005.

E.ON, its utility subsidiaries, including LG&E and KU, and certain of its non-utility subsidiaries are subject to certain regulation by the FERC under the FPA, PUHCA 2005 and the EPAct 2005, including with respect to record-keeping and reporting, acquisitions and sales of utility securities and properties, financial matters, and intra-system sales of goods and services. LG&E and KU believe that they have adequate authority (including financing authority) under existing FERC orders and regulations to conduct their business. LG&E and KU will seek additional authorization when necessary.

The utility operations (LG&E and KU) of LG&E EnergyE.ON U.S. have continued their separate identities as LG&E and continue to serve customers in Kentucky, Virginia and Tennessee under their existing names.KU. The preferred stock and debt securities of LG&E and KU were not affected by these transactions resulting in LG&E’s and KU’s obligations to continue to file SEC reports.

Effective December 30, 2003, LG&E Energy LLC became the successor, by assignment and subsequent merger, to all the assets and liabilities of LG&E Energy Corp.transactions.

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LOUISVILLE GAS AND ELECTRIC COMPANY

General

LG&E, incorporated in 1913 in Kentucky, is a regulated public utility that supplies natural gas to approximately 312,000321,000 customers and electricity to approximately 384,000394,000 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 natural gas and provides electric service, but which maintains its owndoes not provide any distribution systems.services. LG&E also provides natural gas service in limited additional areas. LG&E’s coal-fired electric generating plants, all equipped with systems to reduce sulfur dioxideSO₂ 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 natural 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 which commenced in February 2001.  LG&E completed its accounts receivable securitization arrangements involving LG&E R in January 2004 and LG&E R is currently inactive.Operating Revenues

For the year ended December 31, 2003, 70%2005, 69% of total operating revenues were derived from electric operations and 30%31% from natural gas operations. Electric and gas operating revenues and the percentages by class of service on a combined basis for this period were as follows:

See Note 1312 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, 2003.2005.

Electric Operations

The sources of LG&E’s electric operating revenues and the volumes of sales for the three years ended December 31, 2003,2005, were as follows:

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Gas Operations

The sources of LG&E’s gas operating revenues and the volumes of sales for the three years ended December 31, 2003,2005, were as follows:

The natural 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. While natural gas usage patterns are seasonal, LG&E received approval from the Kentucky Commission for a Weather Normalization Adjustment (“WNA”)WNA mechanism. The WNA mechanism adjusts the non-gas base portiondistribution cost recovery component of the natural gas billings of residential and commercial customers to normal temperatures during the heating season months of DecemberNovember through April, somewhat mitigating the effect of weather extremes on gas revenue.extremes. LG&E has requested, and the Kentucky Commission has approved, an extension of the current WNA mechanism through April 30, 2006. LG&E expects to file for another extension of the WNA before the next heating season begins in November 2006. 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 natural gas service to ultimate consumers. By using natural 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 natural 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 natural gas and pipeline transportation services during the winter months when customer demand increases and when the prices for natural gas supply and transportation services are typically at their highest. Currently, LG&E buys competitively priced natural 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 natural gas sales service at rates generally lower than state and national averages. At December 31, 2003,2005, LG&E had an inventory balance of gas stored underground of approximately 12.912.1 million Mcf of working gas valued at approximately $69.9$124.9 million.

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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 approximately one-fourth of LG&E’s annual throughput.

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The all-timeDuring 2005, the maximum daydaily gas sendout of 545,000was approximately 444,000 Mcf, occurredoccurring on Sunday, January 20, 1985,17, 2005, when the average temperature for the day was -1016 degrees F.  During 2003, maximum day gas sendout was approximately 525,000 Mcf, occurring on January 23, 2003, when the average temperature for the day was 7 degrees F.Fahrenheit. Supply on that day consisted of approximately 240,000221,000 Mcf from purchases, approximately 200,000166,000 Mcf delivered from underground storage, and approximately 85,00057,000 Mcf transported for industrial customers. For a further discussion, see Gas Supply under Item 1.

Rates and Regulation

Following the purchase of Powergen byHistorically, E.ON, E.ON becameLG&E’s ultimate parent, has been a registered holding company under PUHCA.PUHCA 1935, and anticipates registering under PUHCA 2005. As a result,registered holding company, E.ON, its utility subsidiaries, including LG&E, and certain of its non-utility subsidiaries arehave been subject to extensive regulation by the SEC under PUHCAand the FERC with respect to numerous matters, including: electric utility facilities and operations, wholesale sales of power and related transactions, accounting practices, issuances and sales of securities, acquisitions and sales of certain utility properties, payments of dividends out of capital and intra-systemsurplus, financial matters and inter-system sales of certainnon-power goods and services. In addition, PUHCA 2005 generally limitslimited 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 SECFERC orders and regulations to conduct its business.  LG&Ebusiness and will seek additional authorization when necessary.

In August 2005, President Bush signed into law the EPAct 2005, significantly changing many federal statutes, repealing PUHCA 1935 as of February 8, 2006 and enacting PUHCA 2005. As part of the repeal of PUHCA 1935, the FERC was given more authority over the merger and acquisition of public utilities and more authority over the books and records of public utilities. Despite these increases in the FERC’s authority, LG&E believes that the repeal of PUHCA 1935 will lessen its regulatory burdens and provide more flexibility in the event of expansion.

Besides repealing PUHCA 1935, the EPAct 2005 is also expected to have substantial long-term effects on energy markets, energy investment and regulation of public utilities and holding company systems by the FERC and the DOE. The FERC and the DOE are in various stages of rulemaking in implementing the EPAct 2005. The precise impact of these rulemakings cannot be determined at this time.

The Kentucky Commission has regulatory jurisdiction over LG&E’s retail rates and service, 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.  FERC has classified LG&E as a “public utility” as defined in the FPA. The Department of Energy and FERC have jurisdiction under the FPA over certain electric utility facilities and operations, wholesale sale of power and related transactions, accounting practices of LG&E, and in certain other respects as provided in the FPA.

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.

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LG&E’s retail electric rates contain an 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.

Prior to 2004, LG&E’s retail electric rates arewere subject to an ESM. LG&E and the Kentucky Commission agreed to a termination of the ESM relating to all periods after 2003. The ESM, initially in place for three years beginning in 2000, setsset an upper (12.5%) and lower point(10.5%) limit 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.equity. If earnings arewere above the upper limit, the excess earnings arewere shared 40% with ratepayers and 60% with shareholders; if earnings arewere below the lower limit, the earnings deficiency iswas recovered 40% from ratepayers and 60% from shareholders. By order of the Kentucky Commission, rate changes prompted by the ESM filing gowent into effect in April of each year subject to a balancing adjustment in successive periods. For discussion of current ESM matters, see Note 3 of LG&E’s Notes to Financial Statements under Item 8.

In November 2002,June 2001, LG&E filed a revised ESM tariff which proposed continuance of the existing ESM through 2005.  In addition,an application (“VDT case”) with the Kentucky Commission initiatedto create a focused management auditregulatory asset relating to review the ESM plan and reassess its reasonableness, and recently concluded discovery in the case.  LG&E and interested parties had the opportunity to provide recommendationsfirst quarter 2001 charges for modification and continuance of the ESM or other forms of alternative or incentive regulation.  Continuance of the ESM is still being deliberated bya workforce reduction program. In December 2001, the Kentucky Commission approved a settlement in the VDT case and allowed LG&E to set up a final order is not expected untilregulatory asset of $141 million for the second quarterworkforce reduction costs and begin amortizing these costs over a five year period starting in April 2001. The settlement reduced revenues by approximately $26 million through a surcredit on bills to ratepayers over the same five-year period. The surcredit represented net savings stipulated by LG&E. For discussion of 2004.  The ESM tariff remains in effect pending

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 the resolutioncurrent VDT matters, see Note 3 and Note 16 of the case.LG&E’s Notes to Financial Statements under Item 8.

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 natural gas rates contain a GSC, whereby increases or decreases in the cost of natural 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 natural gas supply in that quarter. In addition, the GSC contains a mechanism whereby any over- or under-recoveries of natural gas supply cost from prior quarters willis to be refunded to or recovered from customers through the adjustment factor determined for subsequent quarters. In late 2005, as wholesale natural gas prices began to decrease, a monthly adjustment in the GSC was requested by LG&E and approved by the Kentucky Commission to pass the lower natural gas costs to the customers on a more timely basis.

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 (“IRP”)IRP in October 2002.April 2005. The AG and KIUC were granted intervention in the IRP proceeding. The Kentucky Commission issued its Staff Reportstaff report on February 15, 2006, with no substantive issues noted and orderedclosed the case closed in December 2003 with no significant findings.  The next IRP is due April 2005 and will incorporate the recommendations from the Staff Report regarding the 2002 IRP.by Order dated February 24, 2006.

In December 2003, LG&E filed applicationsan application with the Kentucky Commission requesting adjustments in LG&E’s electric and natural gas rates. LG&E asked for general adjustments in electric and natural gas rates based on the twelve month test yearperiod ended September 30, 2003. The revenue increases requested were $63.8

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approximately $64 million for electric and $19.1$19 million for gas. The Kentucky Commission has suspended the effective date of the proposed new tariffs for five months, so that the rates may go into effect subject to refund by July 1, 2004.  The Kentucky Commission established a procedural schedule for the cases pertaining to discovery and hearings.  Hearings are scheduled in May 2004.  LG&E expectsIn June 2004, the Kentucky Commission to issue ordersissued an order approving increases in the cases before newLG&E’s annual electric base rates go intoof approximately $43 million (7.7%) and annual gas base rates of approximately $12 million (3.4%). The rate increases took effect on July 1, 2004.

Subsequently during 2004 and 2005, the AG conducted an investigation regarding the proceedings resulting in the rate increases. The AG requested information from LG&E and the Kentucky Commission and its staff regarding alleged improper communications between LG&E and the Kentucky Commission related to the rate proceedings. The AG also requested rehearing of the rate increase orders on the basis of these allegations, as well as calculational aspects of the increased rates. In February 2005, the AG submitted a confidential report on its investigation with the Kentucky Commission and filed a motion summarizing the report as containing evidence of improper communications and record-keeping errors by LG&E in respect of its activities with state governmental agencies, including the Kentucky Commission.

In December 2005, the Kentucky Commission issued an order noting completion of its inquiry, including review of the AG’s investigative report. The order concluded that no improper communications occurred during the rate proceedings. The order further established a procedural schedule through the first quarter of 2006 for considering the sole issue for which rehearing was granted: state income tax rates used in calculating the granted rate increases. This issue is estimated at less than $1 million annually. Upon resolution of this issue on rehearing, the initial rate increase orders could be subject to judicial appeal.

For a further 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.

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 natural 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 interest rates, economic conditions, construction costs, and new environmental or other governmental laws and regulations.

During the five years ended December 31, 2003,2005, gross property additions amounted to approximately $1 billion. 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 27%24% of total utility plant at December 31, 2003,2005, and consisted of $870$807 million for electric properties and $155$164 million for natural gas properties. Gross retirements during the same period were $116$108 million, consisting of $80$81 million for electric properties and $36$27 million for natural gas properties.

6Capital expenditures during the three years ending December 31, 2008, are estimated to be approximately $530 million. The major expenditures during this period relate to the development and construction of Trimble County Unit 2, of which LG&E’s portion totals approximately $120 million, and approximately $26 million for the redevelopment of the Ohio Falls hydro facility.

Coal Supply

Coal-fired generating units provided over 98%approximately 97% of LG&E’s net kilowatt-hour generation for 2003.  2005.

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The remaining net generation for 20032005 was provided by natural gas and oil-fueled combustion turbine peaking units  and a hydroelectric plant. Coal is expected to 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 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 laborproduction issues and other supplier or transporter operating difficulties.

LG&E believes there are adequate reserves available tohas entered into coal supply its existing base-load generating unitsagreements with the quantityvarious suppliers for coal deliveries for 2006 and quality of coal required for those units throughout their useful lives.  LG&E intends to meet a portion ofbeyond and normally augments its coal requirementssupply agreements with three-year or shorter contracts.  As part of this strategy, LG&E will continue to negotiate replacement contracts as contracts expire.  LG&E does not anticipate any problems negotiating new contracts for future coal needs.  The balance of coal requirements will be met through spot market purchases. LG&E has a coal inventory policy which it believes provides adequate protection under most contingencies. It had a coal inventory of approximately 1.041.1 million tons, or a53-day 50-day supply, on hand at December 31, 2003.2005.

LG&E expects to continue purchasing most of its coal, withwhich has a sulfur content in the 2%-4.5% - 4.5% range, from western Kentucky, southern Indiana, southern Illinois, Ohio and West Virginia for the foreseeable future. This supply is relatively low pricedlow-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 cost of coal purchased and the percentage of spot coal purchases were as follows:

A slight increase in theThe delivered cost of coal is expected duringto increase in 2006 due to the start of new contracts for 2006 and market conditions. LG&E increased spot purchases in 2005 and 2004 due to multi-year contracts signedsupply and transportation issues in 2002.  This slight increase is partially offset by lower prices negotiated in more recent contracts signed for 2004.the market.

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.

LG&E participates in rate and other proceedings affecting its regulated interstate pipeline services, as appropriate.  Although both Texas Gas and Tennessee Gas have several active proceedings in which LG&E is participating at the FERC, neither Texas Gas nor Tennessee Gas have filed applications at FERC to increase the pipeline’s base rates.  Additionally, the rates of these pipelines are not being billed subject to refund, and LG&E has refunded to its customers any amounts which have been refunded to it as the result of the settlement of any FERC proceedings.  Texas Gas is obligated to file a general rate case at FERC to be effective no later than November 1, 2005.  Tennessee Gas is under no such obligation.

LG&E transports natural gas on the Texas Gas system under Rate Schedules No-Notice Service (“NNS”) and Firm

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Transportation (“FT”) service.  During the winter months, LG&E has 184,900 Mmbtu/day in NNS and 36,000 Mmbtu/day in FT service. Effective November 1, 2005, LG&E’s winter season NNS levels are 184,900 MMBtu/day and its winter season FT levels are 36,000 MMBtu/day. LG&E’s summer season NNS levels are 60,000 Mmbtu/MMBtu/day and its summer season FT levels are 54,000 Mmbtu/36,000 MMBtu/day. LG&E provided Texas Gas with notice to terminate a portion of its FT agreement in the amount of 8,000 MMBtu/day effective November 1, 2006. As a result, LG&E will have FT service in the amount of 28,000 MMBtu/day, effective November 1, 2006. Each of thesethe NNS and FT agreements with Texas Gas areis subject to termination by LG&E in equal portions during 2005, 2006,2008, 2010 and 2008.  For January 2004 only, LG&E contracted for short-term firm transportation service from2011. Each of the FT

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agreements with Texas Gas under Rate Schedule STF in the amount of 15,000 Mmbtu/day.is subject to termination by LG&E during 2008 and 2011. LG&E also transports on the Tennessee Gas system under Tennessee Gas’sGas’ Rate Schedule FT-A. LG&E’s contract levels with Tennessee Gas are 51,000 Mmbtu/MMBtu/day throughout the year. The FT-A agreement with Tennessee Gas is subject to termination by LG&E during 2007.

LG&E participates in rate and other proceedings affecting the regulated interstate natural gas pipelines that provide service to LG&E. Both Texas Gas and Tennessee Gas have several active proceedings in which LG&E is participating at the FERC. One of those proceedings is an application filed by Texas Gas with the FERC to increase its base rates. LG&E is participating in this proceeding with other interested parties. The rates of Texas Gas are, therefore, being billed subject to refund, and LG&E will refund to its customers any amounts which may be refunded to it as the result of the resolution of this proceeding before the FERC. The rates of Tennessee Gas are not being billed subject to refund.

LG&E also has a portfolio of supply arrangements of various terms with a number of suppliers designed to meet its firm sales obligations. These natural gas supply arrangements include pricing provisions that are market-responsive. These firm natural gas supplies, in tandem with pipeline transportation services, provide the reliability and flexibility necessary to serve LG&E’s natural gas customers.

LG&E owns and operates five underground natural gas storage fields with a current working gas capacity of approximately 15.1 million Mcf. GasNatural gas is purchased and injected into storage during the summer season when natural gas prices are typically lower, 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 approximately 373,000expected to be in excess of 370,000 Mcf/day. DeliverabilityUnder mid-winter design conditions, LG&E expects to be able to withdraw in excess of 350,000 Mcf/day from its storage facilities. The deliverability of natural gas from LG&E’s storage facilities decreases during the latter portion of the heating season as the storage inventory islevels are reduced by seasonal withdrawals.

LG&E relies upon its significant underground storage to mitigate the price volatility to which customers might otherwise be exposed. In 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”. Subsequent to this investigation, the Kentucky Commission issued an order on July 17, 2001, encouraging the natural gas distribution companies in Kentucky to take various actions, among them to propose a natural gas hedge plan. LG&E currently operates under a hedge plan proposed by LG&E beginning with the 2004/2005 winter heating season. This hedge plan relies upon LG&E’s underground natural gas storage to mitigate customer exposure to price volatility. In 2004, the Kentucky Commission approved LG&E’s proposed hedge plan, validating the effectiveness of storage to mitigate potential volatility associated with high winter natural gas prices by approving this natural gas hedge plan. The Kentucky Commission also ordered that LG&E need not file hedge plans in the future unless it intended to utilize financial hedging instruments.

The average cost per Mcf of natural gas purchased by LG&E was $10.23 in 2005, $7.18 in 2004, and $6.30 in 2003, $4.19 in 2002, and $5.27 in 2001.2003. Natural gas prices in the unregulated wholesale market generally have increased significantly over the last few years beginning in 2000. These increases inFor further discussion of wholesale natural gas prices, caused in part by decreased natural gas production, decreased liquidity in the marketplace, and increased demand for natural gas as a fuel for electric generation have been significantly affected by changing national gas storage inventory levels.see Note 3 of LG&E relies upon storage&E’s Notes to mitigate the price volatility to which customers might otherwise be exposed.Financial Statements under Item 8.

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KENTUCKY UTILITIES COMPANY

GeneralGeneral

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.  KUthat provides electric serviceelectricity to approximately 482,000495,000 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 105 customers in Tennessee. KU’s coal-fired electric generating plants produce most of KU’s electricity, the remainder is generated by hydroelectric power plants and combustion turbines. In Virginia, KU operates under the name Old Dominion Power Company. KU operates under appropriate franchises in substantially all of the 161160 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. See Item 2, Properties.

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 which commenced in February 2001.  KU completed its accounts receivable securitization arrangements involving KU R in January 2004 and KU R is currently inactive.

Electric OperationsOperations

The sources of KU’s electric operating revenues and the volumes of sales for the three years ended December 31, 2003,2005, were as follows:

KU’s weighted-average system-wide emission rate for sulfur dioxide in 2003 was approximately1.4lbs./Mmbtuof heat input, with every generating unit below its emission limit established by the Kentucky Division for Air Quality.

KU set an all-time record localannual peak load of 3,9444,079 Mw on Monday, January 27, 2003,July 25, 2005, when the temperature reached 94 degrees Fahrenheit. This was the highest hourly customer demand in KU’s history.

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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 and LG&E currently maintainsmaintain a 13% -15%12% - 14% reserve margin range. At December 31, 2003,2005, KU owned steam and combustion turbine generating facilities with a net summer capability of 4,0444,433 Mw and a 28 Mw nameplate-rated hydroelectric facility with a summer capability of 24 Mw. See Item 2, Properties. KU also obtains power from other utilities under bulk power purchase and interchange contracts. At December 31, 2003,2005, KU’s system net summer capability, including purchases from others and excluding the hydroelectric facility, was 4,5454,678 Mw.

KU’s weighted-average system-wide emission rate for SO₂ in 2005 was approximately1.25lbs./MMBtuof heat input, with every generating unit below its emission limit established by the Kentucky Division for Air Quality.

Under a contract expiring in 2020 with OMU, KU has agreed to purchase from OMU the surplus output of the 142-Mw and 265-Mw generating units at OMU’s Elmer Smith station. Purchases under the contract are made under a contractual formula resulting in costs which are expected to be comparable to the cost of other power purchased or generated by KU. Such power equated to approximately 10%8% of KU’s net generation system output during 2003.2005. See Note 1110 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. Previously, KU iswas entitled to take 20% of the available capacity of the station.  Purchases from EEI are madestation under a contractualpricing 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 2003.  See Note 112005. The contract governing the purchases from EEI terminated on December 31, 2005. Subsequent to December 31, 2005, EEI has sold power under general market-based pricing and terms. KU has not contracted with EEI for power under the new arrangements, but maintains its 20% ownership in the common stock of KU’s Notes to Financial Statements under Item 8.EEI. Replacement power for the EEI capacity has been largely provided by KU generation.

KU and 11 other electric utilities are participating owners of OVEC, located in Piketon, Ohio.  KU’s investment in OVEC is the equivalent of 2.5% of OVEC’s common stock. 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 owns 2.5% of OVEC’s common stock. KU’s share of OVEC’s output is 2.5%, approximately 55 Mw of generation capacity. In April 2004, OVEC and its shareholders, including KU and LG&E, entered into an Amended and Restated Inter-Company Power Agreement, to be effective beginning March 2006, upon the expiration of the current power contract among the parties. The parties received SEC approval under PUHCA 1935 of the Amended and Restated Inter-Company Power Agreement in February 2005.

KU and LG&E are founding membersis a member of the MISO.MISO, a non-profit independent transmission system operator that serves the electrical transmission needs of much of the Midwest. Membership was obtained when the MISO was formed in 1998 in response to and consistent with federal energy policy initiatives.  Itinitiatives at that time. The MISO began commercial operations in February 2002. At that time, as members of the MISO,As a result, KU and LG&E turned over operational control of its high-voltage100 Kv and above transmission facilities, (100 kV and greater), while continuingbut continues to control and operate the lower voltage transmission system subject to the terms and conditions of the MISO. The MISO currently controls over 100,000 miles of transmission over 1.1 million square miles located in the northern Midwest between Manitoba, Canada and Kentucky.  In September 2002, FERC granted a 12.88% ROE on transmission facilities for LG&E, KU and the rest of the MISO owners.  As a transmission-owning member of the MISO, KU incurs costs under the MISO OATT. In April 2005, the MISO implemented its day-ahead real-time market (MISO Day 2), including a congestion management system. At the present time, KU is involved in regulatory proceedings at the Kentucky Commission and the FERC seeking authority to exit the MISO. On March 17, 2006, the FERC issued an order conditionally approving the request of KU and LG&E also incur administrative costs through MISO Schedule 10.  The MISO uses Schedule 10 as a means to recover operational and capital costs for providing system operator services to its members.exit the MISO. For further discussion, of current MISO matters, see Rates and Regulation for KU under Item 7 and

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Note 315 of KU’s Notes to Financial Statements under Item 8.

KU also has agreements with a number of entities throughout the United States for the purchase and/or sale of capacityRates and energy and for the utilization of their bulk transmission systems.Regulation

Rates and Regulation

Following the purchase of Powergen byHistorically, E.ON, E.ON becameKU’s ultimate parent, has been a registered holding company under PUHCA.PUHCA 1935, and anticipates registering under PUHCA 2005. As a result,registered holding company, E.ON, its utility subsidiaries, including KU, and certain of its non-utility subsidiaries arehave been subject to extensive regulation by the SEC under PUHCAand the FERC with respect to numerous matters, including: electric utility facilities and operations, wholesale sales of power and related transactions, accounting practices, issuances and sales of securities, acquisitions

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and sales of certain utility properties, payments of dividends out of capital and intra-systemsurplus, financial matters and inter-system sales of certainnon-power goods and services. In addition, PUHCA 1935 generally limitslimited 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 SECFERC orders and regulations to conduct its business.  KUbusiness and will seek additional authorization when necessary.

In August 2005, President Bush signed into law the EPAct 2005, significantly changing many federal statutes, repealing PUHCA 1935 as of February 8, 2006 and enacting PUHCA 2005. As part of the repeal of PUHCA 1935, the FERC was given more authority over the merger and acquisition of public utilities and more authority over the books and records of public utilities. Despite these increases in the FERC’s authority, KU believes that the repeal of PUHCA 1935 will lessen its regulatory burdens and provide more flexibility in the event of expansion.

Besides repealing PUHCA 1935, the EPAct 2005 is also expected to have substantial long-term effects on energy markets, energy investment and regulation of public utilities and holding company systems by the FERC and the DOE. The FERC and the DOE are in various stages of rulemaking in implementing the EPAct 2005. While the precise impact of these rulemakings cannot be determined at this time, KU generally views the EPAct 2005 as legislation that will enhance the utility industry going forward.

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)$0.3 million) from which KU served five5 customers at December 31, 2003,2005, KU is subject to the jurisdiction of the TRA. FERC has classifiedTennessee Regulatory Authority. The Kentucky Commission, the Virginia Commission and the Tennessee Regulatory Authority have the ability to examine the rates KU as a “public utility” as defined in the FPA.  The Department of Energy and FERC have jurisdiction under the FPA over certain of the electric utility facilities and operations, wholesale sale of power and related transactions, accounting practices of KU, and in certain other respects as provided in the FPA.charges its retail customers at any time.

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.

KU’s Kentucky retail electric rates contain an 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

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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.

Prior to 2004, KU’s Kentucky retail electric rates arewere subject to an ESM. KU and the Kentucky Commission agreed to a termination of the ESM relating to all periods after 2003. The ESM, initially in place for three years beginning in 2000, setsset an upper (12.5%) and lower point(10.5%) limit 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.equity. If earnings arewere above the upper limit, the excess earnings arewere shared 40% with ratepayers and 60% with shareholders; if earnings arewere below the lower limit, the earnings deficiency iswas recovered 40% from ratepayers and 60% from shareholdersshareholders..  By order of the Kentucky Commission, rate changes prompted by the ESM filing gowent into effect in April of each year subject to a balancing adjustment in successive periods. There is no ESM for Virginia retail electric rates. For discussion of current ESM matters, see Note 3 of KU’s Notes to Financial Statements under Item 8.

In November 2002,June 2001, KU filed a revised ESM tariff which proposed continuance of the existing ESM through 2005.  In addition,an application (“VDT case”) with the Kentucky Commission initiatedto create a focused management auditregulatory asset relating to review the ESM plan and reassess its reasonableness, and recently concluded discovery in the case.  KU and interested parties had the opportunity to provide recommendationsfirst quarter 2001 charges for modification and continuance of the ESM or other forms of alternative or incentive regulation.  Continuance of the ESM is still being deliberated bya workforce reduction program. In December 2001, the Kentucky Commission approved a settlement in the VDT and allowed KU to set up a final order is not expected untilregulatory asset of $54 million for the second quarterworkforce reduction costs and begin amortizing these costs over a five year period starting in April 2001. The settlement reduced revenues by approximately $11 million through a surcredit on bills to ratepayers over the same five-year period. The surcredit represented net savings stipulated by KU. For discussion of 2004.  The ESM tariff remains in effect pending the resolutioncurrent VDT matters, see Note 3 and Note 15 of the case.KU’s Notes to Financial Statements under Item 8.

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

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margins and demand-side management techniques. KU filed its most recent integrated resource plan (“IRP”)IRP in October 2002.April 2005. The AG and KIUC were granted intervention in the IRP proceeding. The Kentucky Commission issued its Staff Reportstaff report on February 15, 2006, with no substantive issues noted and orderedclosed the case closed in December 2003 with no significant findings.  The next IRP is due April 2005 and will incorporate the recommendations from the Staff Report regarding the 2002 IRP.by Order dated February 24, 2006.

The Commonwealth of Virginia passed the Virginia Electric Utility Restructuring Act in 1999. This act givesgave Virginia customers a choice for energy services.  The change was phased in gradually between January 2002 and January 2004.  In 2002, KU filed prospective unbundled rate schedules which included a capthe ability to choose their electric supplier. Rates are capped at current levels from January 2002 through June 2007.December 2010. The Virginia Commission granted KUwill continue to require each Virginia utility to make annual filings of either a waiver from retail choice andbase 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 associated rate filingsindividual utility’s financial performance during the historic 12-month period. The Staff Report can lead to an adjustment in rates, but through December 2004.  Additionally,2010 rates are subject to the capped rate period and essentially “frozen”. However, KU may petition the Virginia Commission for a one-time adjustment in Marchrates during the capped rate period. Effective July 1, 2003, the General Assembly of Virginia amended and reenacted Section 56-580 of the Code of Virginia with language that effectively exempts all KU Virginia service territory from retail choice and the associated rate filings until such time as retail choice is offered to other customers in KU’s other service territories.

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In December 2003, KU filed an application with the Kentucky Commission requesting an adjustment in KU’s electric rates. KU asked for a general adjustment in electric rates based on the twelve month test yearperiod ended September 30, 2003. The revenue increase requested was $58.3approximately $58 million. The Kentucky Commission has suspended the effective date of the proposed new tariffs for five months, so that the rates may go into effect subject to refund by July 1, 2004.  The Kentucky Commission established a procedural schedule for the case pertaining to discovery and a hearing.  The hearing is scheduled in May 2004.  KU expectsIn June 2004, the Kentucky Commission to issueissued an order approving an increase in the case before newKU’s annual electric base rates go intoof approximately $46 million (6.8%). The rate increase took effect on July 1, 2004.

Subsequently during 2004 and 2005, the AG conducted an investigation regarding the proceedings resulting in the rate increase. The AG requested information from KU and the Kentucky Commission and its staff regarding alleged improper communications between KU and the Kentucky Commission related to the rate proceeding. The AG also requested rehearing of the rate increase order on the basis of these allegations, as well as calculational aspects of the increased rates. In February, 2005 the AG submitted a confidential report on its investigation with the Kentucky Commission and filed a motion summarizing the report as containing evidence of improper communications and record-keeping errors by KU in respect of its activities with state governmental agencies, including the Kentucky Commission.

In December 2005, the Kentucky Commission issued an order noting completion of its inquiry, including review of the AG’s investigative report. The order concluded that no improper communications occurred during the rate proceedings. The order further established a procedural schedule through the first quarter of 2006 for considering the sole issue for which rehearing was granted: state income tax rates used in calculating the granted rate increase. This issue is estimated at less than $1 million annually. Upon resolution of this issue on rehearing, the initial rate increase order could be subject to judicial appeal.

For a further 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.

Construction Program and FinancingFinancing

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 interest rates, economic conditions, construction costs, and new environmental or other governmental laws and regulations.

During the five years ended December 31, 2003,2005, gross property additions amounted to approximately $1 billion. 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 28%26% of total utility plant at December 31, 2003.2005. Gross retirements during the same period were $90$106 million.

Capital expenditures during the three years ending December 31, 2008 are estimated to be approximately $1.5 billion. The major expenditures during this period relate to the development and construction of Trimble County Unit 2, of which KU’s portion totals approximately $510 million, and the installation of FGDs on Ghent and Brown units, totaling approximately $560 million.

Coal SupplySupply

Coal-fired generating units provided over 98%approximately 97% of KU’s net kilowatt-hour generation for 2003.2005. The remaining net generation for 20032005 was provided by natural gas and oil-fueled combustion turbine peaking units

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and hydroelectric plants. Coal is expected to be the predominant fuel used by KU in the foreseeable future, with natural gas and oil being used for peaking 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.

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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 laborproduction issues and other supplier or transporter operating difficulties.

KU believes there are adequate reserves available tohas entered into coal supply its existing base-load generating unitsagreements with the quantityvarious suppliers for coal deliveries for 2006 and quality of coal required for those units throughout their useful lives.  KU intends to meet a portion ofbeyond and normally augments its coal requirementssupply agreements with three-year or shorter contracts.  As part of this strategy,spot market purchases. KU will continue to negotiate replacement contracts as contracts expire.  KU does not anticipate any problems negotiating new contracts for futurehas a coal needs.  The balance of coal requirements will be met through spot purchases.  KUinventory policy which it believes provides adequate protection under most contingencies. It had a coal inventory of approximately 1.21.1 million tons, or a 60-day51-day supply, on hand at December 31, 2003.2005.

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, southern Indiana, southern Illinois, Ohio, Wyoming and Colorado for the foreseeable future.

Coal for Ghent is delivered to KU’s Ghent plant by barge.  Deliveries to thebarge, Tyrone and Green River locations areplants by truck.  Delivery totruck, and E.W. Brown isplant by rail.rail and truck.

The historical average delivered cost of coal purchased and the percentage of spot coal purchases were as follows:

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 during 2004for 2006 is expected to remain at approximatelyincrease due to the same level as 2003.start of new contracts and market conditions.

Environmental MattersMatters

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 2003,2005, expenditures for pollution control facilities represented $201.8$269 million or 20%26% of total construction expenditures. KU estimates that construction expenditures for environmental control equipment from 2006 through 2008, will be approximately $680 million, of which approximately $560 million is related to the installation of NOx control equipment from 2004 through 2005 will be approximately $58.9 million.FGDs at Ghent and Brown. For a discussion of environmental matters, see Rates and Regulation for KU under Item 7 and Note 1110 of KU’s Notes to Financial Statements under Item 8.

Competition

In the last several years, KU has taken many steps to keep its rates low while maintaining high levels of customer satisfaction, 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; and continuous modifications of its organizational structure.Competition

At this time, 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

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EMPLOYEES AND LABORLABOR RELATIONS

LG&E had 881approximately 895 full-time regular employees and KU had 941approximately 925 full-time regular employees at December 31, 2003.February 28, 2006. Of the LG&E total, 621 operating, maintenance, and construction employees were represented by IBEW Local 2100. LG&E and employees represented by IBEW Local 2100 signed a four-yearthree-year collective bargaining agreement in November 2001 and completed wage and2005 with annual benefits re-opener negotiations in October 2003.  New wage and benefit rates went into effect in November 2003.re-openers. Of the KU total, 155approximately 150 operating, maintenance, and construction employees were represented by IBEW Local 2100 and USWA Local 9447-01. In August 2003, KU and employees represented by IBEW Local 2100 entered into a three-year collective bargaining agreement. KU and employees represented by USWA Local 9447-01 entered into a three-year collective bargaining agreement effectivein August 2002 and expiring August 2005.2005 with authorized annual wage re-openers.

As a result of the Powergen acquisition and in order to comply with PUHCA, LG&EE.ON U.S. 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 requiredpermitted under PUHCA.PUHCA 2005. On January 1, 2001,February 28, 2006, approximately 1,0001,022 employees mainly from LG&E Energy, LG&E and KU, were moved to LG&Eworked for E.ON U.S. 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 the workforce separation program in effect for 2001.

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The present term of office of each of the above executive and other officers extends to the meeting of the Board of Directors following the 20042006 Annual Meeting of Shareholders.

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There are no family relationships between or among executive and other officers of LG&E and KU. The above tables indicate officers serving as executive officers of both LG&E and KU at December 31, 2003.February 28, 2006. 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 Chief Financial Officer of LG&E Energy (now E.ON U.S.) and LG&E from May 1997 to February 1999 (including Chief Financial Officer of KU from May 1998 to February 1999) and President and Chief Operating Officer of LG&E Energy (now E.ON U.S.) from March 1999 to April 2001 (including President of LG&E and KU from June 2000 to April 2001).

Mr. McCall has been Executive Vice President, General Counsel and Corporate Secretary of LG&E Energy (now E.ON U.S.) 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 from March 1996 to February 1999; Senior Vice President - Finance and Business Development from February 1999 to December 2000 and Senior Vice President - Finance and Controller of LG&E Energy (now E.ON U.S.), LG&E and KU from December 2000 to September 2003.

Before he was elected to his current positions, Mr. Thompson was Vice President - Business Development for LG&E Energy 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 (now E.ON U.S.) from August 1999 to June 2000.

Before he was elected to his current positions, Mr. Hermann was 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; Vice President Supply Chain and Operating Services from December 1999 to December 2000; and Senior Vice President - Distribution Operations, from December 2000 to February 2003.

Before she was elected to her current positions, Ms. Welsh was Vice President Administration of LG&E Energy from May 1997 to February 1998; and Vice President - Information Technology from February 1998 to December 2000.2000 for LG&E Energy (now E.ON U.S.).

Before he was elected to his current positions, Mr. Gallus was 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.Energy (now E.ON U.S.).

Before heshe was elected to hisher current positions, Mr. SmithMs. Pottinger was Head of Construction ProjectsDirector, Human Resources from June 1997 to June 2002; and Vice President - PowergenHuman Resources from June 2002 to 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 2000.2006.

Before he was elected to his current positions, Mr. Vogel served in management positions within the Distribution organization of LG&E and KU from November 1994 to December 2000, and was Vice President - Retail Services from December 2000 to March 2003.

Before he wasIn addition to being elected to his current positions, Mr. Arbough was Manager, Corporate Finance of LG&E Energy and LG&E from August 1996 to May 1998; and he has held the positionpositions of Director, Corporate Finance of LG&E Energy (now E.ON U.S.), LG&E and KU from May 1998 to present.

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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 2001.2001, and Vice President – Rates and Regulatory from February 2001 to September 2004.

Before he was elected to his current positions, Mr. Siemens held the position of Director of External Affairs for LG&E Energy (now E.ON U.S.) from August 1982 to January 2001.

Before she was elected to her current position, 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 from July 1998 to December 2001; and General Manager Black Fossil Operations for PowergenE.ON U.K. 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 1988 to January 1999.  He joined LG&E Energy and held the title Manager, Media Relations from January 1999 to February 2000; and Director, Corporate Communications for LG&E Energy (now E.ON U.S.) from February 2000 to March 2002.

Before he was elected to his current positions, Mr. Voyles was General Manager, Jefferson County Operations December 1995 to November 1998; General Manager, Cane Run, Ohio Falls and Combustion Turbines, November 1998 to February 2003; and Director, Generation Services, February 2003 to June 2003.

17Before she was elected to her current positions, Ms. Scott was Director, Trading Controls and Energy Marketing Accounting from February 1999 to September 2002, and Director, Financial Planning and Accounting – Utility Operations from September 2002 to December 2004.

Item 1A. Risk Factors

In addition to the other information in this Form 10-K and other documents furnished to or filed by LG&E and KU with the SEC from time to time, the following factors should be carefully considered in evaluating the Companies. Such factors could affect actual results and cause results to differ materially from those expressed in any forward-looking statements made by, or on behalf of, the Companies. Some or all of these factors may apply to LG&E or KU or both.

The electric and gas rates that LG&E and KU charge customers, as well as other aspects of the business, are subject to significant state and FERC regulation.

The rates that the Companies are allowed to charge for their services are a primary item influencing the results of operations, financial position, and liquidity of the Companies. The regulation of the rates that are collected from customers is determined, in large part, by governmental organizations outside the Companies’ control, including the Kentucky Commission, and for KU, the Virginia Commission and the Tennessee Regulatory Authority. These commissions regulate many aspects of utility operations, including financial and capital structure matters, siting and construction of facilities, terms and conditions of service, safety and operations, accounting and cost allocation methodologies and other matters. While rate regulation is premised on recovery of prudently incurred costs and reasonable rate of return on capital, such cannot be assured. Regulatory proceedings regarding all matters of operations can thus significantly affect the earnings, liquidity and business activities of the Companies.

Base rate increases of LG&E and KU approved during 2004 and currently being collected by the Companies in Kentucky remain the subject of continuing proceedings by the Kentucky Commission and the Attorney General. Proceedings regarding the expiration of VDT charges formerly included in the Companies’ rates in Kentucky

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ITEM 2.  Properties.are also the subject of on-going proceedings.

Transmission and interstate market activities of LG&E and KU, as well as other aspects of the business, are subject to significant FERC regulation.

The Companies’ businesses are subject to regulation under the FERC covering matters including rates charged to transmission users and wholesale customers, interstate market structure and design, construction and operation of transmission facilities, acquisition and disposal of utility assets and securities, standards of conduct, cost allocations and financial matters. Existing FERC regulation, changes thereto or issuance of new rules in these areas, can affect the earnings, operations and other activities of the Companies.

LG&E’s and KU’s continued participation in the MISO, as well as changes in transmission and wholesale power market structures, could increase costs or reduce revenues.

LG&E and KU are members of the MISO and have transferred functional control of their transmission systems to the MISO. The Companies must incur MISO membership-related costs and charges established by the MISO and can be required to incur other expenses or make transmission and generation operating decisions as directed by the MISO. The MISO Day 2 markets, which began operation in April 2005, have represented a significant change in the wholesale power market structure and operation. Until the market matures, the effects on results of operations, financial position, or liquidity will remain difficult to predict.

LG&E and KU have commenced proceedings at the Kentucky Commission and the FERC seeking authority to exit the MISO. On March 17, 2006, the FERC issued an order conditionally approving the request of KU and LG&E to exit the MISO. For further discussion see Note 16 of LG&E’s Notes to Financial Statements and Note 15 of KU's Notes to Financial Statements under Item 8.

LG&E and KU undertake significant capital projects and are subject to unforeseen costs, delays or failures in such projects, as well as risk of full recovery of such costs.

In the ordinary course of business, the Companies are continually developing, permitting and constructing new generation and transmission facilities, as well as maintaining and improving existing facilities. The completion of these facilities without delays or cost overruns is subject to risks in many areas, including approval and licensing, permitting, construction problems or delays, contractor performance, weather and geological issues, and political, labor and regulatory developments. Delays, additional costs or unsatisfactory regulatory treatment can result in reduced earnings. Further, if construction projects are not completed according to specifications, the Companies may incur reduced plant efficiency, higher operating costs or continued capital costs.

Projects underway at LG&E and KU include plans to construct a new base-load generating plant, Trimble County Unit 2, and associated transmission facilities; the upgrade or construction of other transmission facilities; and the installation of significant on-going emissions reduction equipment. These projects are in varying stages of construction, planning or regulatory approval.

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LG&E’s and KU’s costs of compliance with environmental laws are significant and are subject to continuing changes.

LG&E and KU are subject to extensive federal, state and local environmental requirements which, among other things, regulate air emissions, water discharges and the management of hazardous and solid waste in order to adequately protect the environment. Compliance by the Companies requires significant expenditures for installation of pollution control equipment, environmental monitoring, emission fees and permits at all of their facilities. If the Companies fail to comply with environmental laws and regulations, even if caused by factors beyond their control, civil or criminal penalties and fines can result. Revised or additional laws and regulations could result in significant additional expense and operating restrictions on LG&E’s or KU’s facilities or increased compliance costs which may not be fully recoverable from customers. The cost impact of such changes would depend upon the specific requirements enacted and cannot be determined at this time.

LG&E and KU are undertaking significant emissions construction projects relating to upcoming compliance with the Clean Air Act, CAIR and CAMR standards, among others. Rate recovery and other regulatory proceedings regarding these matters occur periodically and will continue for some time.

LG&E’s and KU’s operating results are affected by weather conditions, including storms and seasonal temperature variations, as well as by significant man-made or accidental disturbances.

Customer demand for electricity and natural gas is seasonal and can cause extreme variability in load due to higher or lower than normal temperatures. Generally, demand for electricity peaks during the summer and demand for natural gas peaks during the winter. As a result, LG&E’s and KU’s overall operating results can fluctuate substantially on a seasonal basis. LG&E and KU maintain adequate generating and natural gas supply resources to accommodate system demands for electricity and natural gas. In addition, the Companies have generally sold less electricity or natural gas, as applicable, and consequently earned lower revenues, when weather conditions have been milder. However, the natural gas rates contain a WNA mechanism which adjusts the distribution cost recovery component of the natural gas billings of residential and commercial customers to normal temperatures during the heating season months of November through April, somewhat mitigating the effect of weather extremes. Severe weather, such as tornadoes, ice storms, thunderstorms, high wind or floods could also significantly affect the Companies’ operations by causing power outages, damaging infrastructure and requiring significant repair costs. Terrorism, explosions or fires pose similar risks. LG&E and KU maintain a comprehensive storm management plan for efficient and timely restoration of service to customers after major storm events.

LG&E’s and KU’s businesses are concentrated in the Midwest United States, specifically Kentucky.

The operations of the Companies are concentrated in Kentucky and are therefore impacted by changes in the Midwest United States economy in general, and the Kentucky economy in particular. General economic conditions, such as population growth, industrial growth or expansion and economic development, as well as the operational or financial performance of major industries or customers in the Companies’ service territories can affect the demand for electricity and natural gas.

LG&E and KU are subject to operational risks relating to their generating plants, transmission facilities and distribution equipment.

Operation of power plants, transmission and distribution facilities subject LG&E and KU to many risks, including the breakdown or failure of equipment, accidents, labor disputes, delivery/transportation problems, disruptions of fuel supply and performance below expected levels. Because LG&E’s and KU’s transmission facilities are interconnected with those of third parties, the operation of their facilities may be

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adversely affected by unexpected or uncontrollable events occurring on the systems of such third parties. Operation of the Companies’ power plants below expected capacity levels could result in lost revenues or increased expenses, including higher maintenance costs that may not be recovered from customers. Unplanned outages may result in significant replacement power costs. While LG&E and KU believe appropriate prevention or mitigation measures are in place, where possible, with respect to these potential business disruptions, no assurances can be given that such events will not occur in the future or will not negatively affect their financial condition or results of operations.

LG&E and KU could be negatively affected by downgrades to credit ratings or other negative developments in their ability to access capital markets.

In the ordinary course of business, the Companies have significant long-term and short-term financing requirements to fund their capital expenditures, debt interest or maturities and operating needs. If rating agencies were to downgrade the Companies’ credit ratings, particularly below investment grade, or withdraw such ratings, it could significantly limit access to the capital market and the Companies’ borrowing costs could increase. In addition, the Companies’ financing costs can also be affected by financial matters involving their parent holding company, including its overall credit rating, its provision of intra-company financing and the terms and rates of such financing.

LG&E and KU are subject to commodity price risk, credit risk, counterparty risk and other risks associated with the energy business.

LG&E and KU are exposed to purchase and sales market operating and financial risks common to utility operations. Although the Companies operate largely in regulated markets, increases in the cost of power and fuel, such as coal or natural gas, as well as other major inputs and supplies, can affect their margins because authorized rate structures and pass-through cost mechanisms may include timing lags or regulatory discretion which do not lead to full cost recovery. Changes in the wholesale market price for electricity can impact LG&E’s and KU’s financial results by altering the revenues from off-system sales of excess power from period to period. LG&E and KU are also exposed to risk that counterparties could fail to perform their obligations to provide energy, fuel, goods, services or payments resulting in potential increased costs to the Companies.

LG&E and KU are subject to risks associated with defined benefit retirement plans, health care plans, wages and other employee-related benefits.

The Companies’ funding obligations concerning defined benefit and postretirement plans are subject to risks relating to developments in future costs, returns on investments, interest rates and other actuarial matters which may differ from assumptions currently in effect for the plans and may lead to higher required funding outlays. Further, higher wage levels, whether related to collective bargaining agreements or employment market conditions, and costs of providing health care benefits to employee may adversely affect LG&E’s and KU’s results of operations, financial position or liquidity.

Item 1B. Unresolved Staff Comments.

None.

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