**UNITED STATES**

**SECURITIES AND EXCHANGECOMMISSION**

**Washington,D. C.  20549**

 

**FORM 10-K**

 

**(Mark One)**
| **ý**                                            | ** ** | **ANNUAL REPORT PURSUANT TO SECTION 13 OR  15(d) OF THE  SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)**     |
|-------------------------------------------------------|------------|-----------------------------------------------------------------------------------------------------------------------|
|                                                  |
| **For the  fiscal year ended December 31, 2004** |
|                                                  |
| **OR**                                                |
|                                                  |
| **o**                                                 | ** ** | **TRANSITION REPORT PURSUANT TO SECTION 13 OR  15(d) OF THE  SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)** |

 
| **Commission  File Number**                                         | ** ** | **Registrant, State of  Incorporation,  Address, and Telephone Number** | ** ** | **IRS Employer  Identification Number** |
|---------------------------------------------------------------------|------------|-------------------------------------------------------------------------|------------|-----------------------------------------|
|                                                                |       |                                                                    |       |                                    |
| **1-2893**                                                          | ** ** | **Louisville Gas and Electric Company**                                 |       | **61-0264150**                          |
| ** **                                                          | ** ** | **(A  Kentucky Corporation)**                                           | ** ** | ** **                              |
| ** **                                                          | ** ** | **220 West  Main Street**                                               | ** ** | ** **                              |
| ** **                                                          | ** ** | **P. O. Box 32010**                                                     | ** ** | ** **                              |
| ** **                                                          | ** ** | **Louisville, Kentucky 40232**                                          | ** ** | ** **                              |
| ** **                                                          | ** ** | **(502)  627-2000**                                                     | ** ** | ** **                              |
|                                                                |       |                                                                    |       |                                    |
| **1-3464**                                                          | ** ** | **Kentucky Utilities Company**                                          |       | **61-0247570**                          |
| ** **                                                          | ** ** | **(A  Kentucky and Virginia Corporation)**                              | ** ** | ** **                              |
| ** **                                                          | ** ** | **One  Quality Street**                                                 | ** ** | ** **                              |
| ** **                                                          | ** ** | **Lexington,  Kentucky 40507-1428**                                     | ** ** | ** **                              |
| ** **                                                          | ** ** | **(859)  255-2100**                                                     | ** ** | ** **                              |
|                                                                |       |                                                                    |       |                                    |
| Securities  registered pursuant to section 12(g) of the Act:   |
|                                                                |
| **Louisville  Gas and Electric Company**                            |
| **5%  Cumulative Preferred Stock, $25 Par Value**                   |
| **$5.875  Cumulative Preferred Stock, Without Par Value**           |
| **Auction  Rate Series A Preferred Stock, Without Par Value**       |
| (Title of  class)                                                   |
| ** **                                                          |
| **Kentucky  Utilities Company**                                     |
| **Preferred  Stock, 6.53% cumulative, stated value $100 per share** |
| **Preferred  Stock, 4.75% cumulative, stated value $100 per share** |
| (Title of  class)                                                   |

 

Indicate by check mark whether the registrants (1) have filed allreports required to be filed by Section 13 or 15(d) of the SecuritiesExchange Act of 1934 during the preceding 12 months (or for such shorter periodthat the registrants were required to file such reports), and (2) have beensubject to such filing requirements for the past 90 days.  Yes  ý   No  o

 

Indicate by check mark if disclosure of delinquent filers pursuant toItem 405 of Regulation S-K is not contained herein, and will not be contained,to the best of registrant’s knowledge, in definitive proxy or informationstatements incorporated by reference in Part III of this Form 10-K or anyamendment to this Form 10-K.  ý

 

Indicate by check mark whether the registrant is an accelerated filer(as defined in Exchange Act Rule 12b-2). Yes  o   No  ý

 

As of June 30, 2004, the aggregate market value of the commonstock of each of Louisville Gas and Electric Company and Kentucky UtilitiesCompany held by non-affiliates was $0. As of February 28, 2005, Louisville Gas and Electric Company had21,294,223 shares of common stock outstanding, all held by LG&E EnergyLLC.  Kentucky Utilities Company had37,817,878 shares of common stock outstanding, all held by LG&E Energy LLC.

 

This combined Form 10-K is separately filed by Louisville Gas andElectric Company and Kentucky Utilities Company.  Information contained herein related to anyindividual registrant is filed by such registrant on its own behalf.  Each registrant makes no representation as toinformation relating to the other registrant.

 

DOCUMENTSINCORPORATED BY REFERENCE

 

Not applicable.

 

 

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TABLE OF CONTENTS

 
| PART I     | ** **                                                                                                             |
|------------|------------------------------------------------------------------------------------------------------------------------|
|       | ** **                                                                                                             |
| Item  1.   | Business                                                                                                               | * * |
|       | Louisville Gas and Electric Company                                                                                    | * * |
|       | General                                                                                                                | * * |
|       | Electric Operations                                                                                                    | * * |
|       | Gas  Operations                                                                                                        | * * |
|       | Rates and Regulation                                                                                                   | * * |
|       | Construction Program and Financing                                                                                     | * * |
|       | Coal  Supply                                                                                                           | * * |
|       | Gas  Supply                                                                                                            | * * |
|       | Environmental Matters                                                                                                  | * * |
|       | Competition                                                                                                            | * * |
|       | Kentucky Utilities Company                                                                                             | * * |
|       | General                                                                                                                | * * |
|       | Electric Operations                                                                                                    | * * |
|       | Rates and Regulation                                                                                                   | * * |
|       | Construction Program and Financing                                                                                     | * * |
|       | Coal  Supply                                                                                                           | * * |
|       | Environmental Matters                                                                                                  | * * |
|       | Competition                                                                                                            | * * |
|       | Employees and Labor Relations                                                                                          | * * |
| Item 2.    | Properties                                                                                                             | * * |
| Item 3.    | Legal Proceedings                                                                                                      | * * |
| Item 4.    | Submission of Matters to a Vote of Security  Holders                                                                   | * * |
|       | * *                                                                                                               |
| PART II    | ** **                                                                                                             |
|       | ** **                                                                                                             |
| Item 5.    | Market for the Registrant’s Common Equity, Related Stockholder  Matters and Issuer Purchases of Equity Securities | * * |
| Item 6.    | Selected Financial Data                                                                                                | * * |
| Item 7.    | Management’s Discussion and Analysis of  Financial Condition and Results of Operations                            | * * |
|       | Louisville Gas and Electric Company                                                                                    | * * |
|       | Kentucky Utilities Company                                                                                             | * * |
| Item 7A.   | Quantitative and Qualitative Disclosures  About Market Risk                                                            | * * |
| Item 8.    | Financial Statements and Supplementary Data                                                                            | * * |
|       | Louisville Gas and Electric Company                                                                                    | * * |
|       | Kentucky Utilities Company                                                                                             | * * |
| Item 9.    | Changes in and Disagreements with  Accountants on Accounting and Financial Disclosure                                  | * * |
| Item 9A.   | Controls and Procedures                                                                                                | * * |
| Item 9B.   | Other Information                                                                                                      | * * |
|       | * *                                                                                                               |
| PART  III  | ** **                                                                                                             |
|       | ** **                                                                                                             |
| Item 10.   | Directors and Executive Officers of the  Registrant (a)                                                                | * * |
| Item 11.   | Executive Compensation. (a)                                                                                            | * * |
| Item 12.   | Security Ownership of Certain Beneficial  Owners and Management and related Stockholder Matters (a)                    | * * |
| Item 13.   | Certain Relationships and Related  Transactions (a)                                                                    | * * |
| Item 14.   | Principal Accountant Fees and Services                                                                                 | * * |
|       | * *                                                                                                               |
| PART IV    | ** **                                                                                                             |
|       | ** **                                                                                                             |
| Item 15.   | Exhibits and Financial Statement Schedules                                                                             | * * |
| Signatures | * *                                                                                                               |
|            |                                                                                                                        |  |  |

 

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(a) Incorporate by reference

 

2

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INDEX OF ABBREVIATIONS

 
| AFUDC               |   | Allowance for Funds Used During  Construction                |
|---------------------|--------|--------------------------------------------------------------|
| ARO                 |   | Asset Retirement Obligation                                  |
| Capital Corp.       |   | LG&E Capital Corp.                                       |
| Clean Air Act       |   | The Clean Air Act, as amended  in 1990                       |
| CCN                 |   | Certificate of Public  Convenience and Necessity             |
| CO2                 |   | Carbon Dioxide                                               |
| CT                  |   | Combustion Turbines                                          |
| CWIP                |   | Construction Work in Progress                                |
| DSM                 |   | Demand Side Management                                       |
| ECAR                |   | East Central Area Reliability  Region                        |
| 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                         |
| FGD                 |   | Flue Gas Desulfurization                                     |
| 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                               |
| IRP                 |   | Integrated Resource Plan                                     |
| 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 LLC (as  successor to LG&E Energy Corp.) |
| LG&E R          |   | LG&E Receivables LLC                                     |
| LG&E Services   |   | LG&E Energy Services Inc.                                |
| LNG                 |   | Liquefied Natural Gas                                        |
| Mcf                 |   | Thousand Cubic Feet                                          |
| MGP                 |   | Manufactured Gas Plant                                       |
| MISO                |   | Midwest Independent  Transmission 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)                    |

 

3

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| PUHCA               |   | Public Utility Holding Company Act of 1935   |
|---------------------|--------|----------------------------------------------|
| ROE                 |   | Return on Equity                             |
| RTO                 |   | Regional Transmission  Organization          |
| S&P             |   | Standard & Poor’s Rating  Services  |
| SCR                 |   | Selective Catalytic Reduction                |
| SEC                 |   | Securities and Exchange Commission           |
| SERP                |   | Supplemental Executive  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 LLC                   |
| 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 |
| WNA                 |   | Weather Normalization  Adjustment            |

 

4

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# **PART I**

# ** **

## Item 1. Business.

##  

LG&E and KU are each subsidiaries of LG&E Energy.  LG&E Energy is a subsidiary of E.ON AG, aGerman corporation.  E.ON acquiredLG&E Energy through its July 1, 2002 acquisition of Powergen plc, nowPowergen Limited, a United Kingdom company. LG&E and KU are now indirect subsidiaries of E.ON.  As a result of these acquisitions andotherwise, E.ON and LG&E Energy are registered as holding companies underPUHCA.

 

In order to comply with PUHCA, LG&E Services was formed as asubsidiary of LG&E Energy.  LG&EServices provides certain services to affiliated entities, including LG&Eand KU, at cost as required under PUHCA. Approximately 1,000 employees, mainly from LG&E Energy, LG&E andKU, were moved to LG&E Services upon its formation.

 

E.ON, its utilitysubsidiaries, including LG&E and KU, and certain of its non-utilitysubsidiaries are subject to extensive regulation by the SEC under PUHCA withrespect to issuances and sales of securities, acquisitions and sales of certainutility properties, and intra-system sales of certain goods and services.  In addition, PUHCA generally limits theability of registered holding companies to acquire additional public utilitysystems and to acquire and retain businesses unrelated to the utilityoperations of the holding company. LG&E and KU believe that they have adequate authority (includingfinancing authority) under existing SEC orders and regulations to conduct theirbusiness.  LG&E and KU will seekadditional authorization when necessary. E.ON’s generalfinancing approval order under PUHCA (including certain LG&E and KUcomponents) expires in May 2005 and an application has been submitted to theSEC for renewed or modified financing authorizations for an additional threeyear period.  LG&E and KU anticipatereceiving a timely approval from the SEC, but such approval cannot be assured.

 

Ascontemplated in their regulatory filings in connection with the E.ONacquisition, E.ON, Powergen and LG&E Energy completed an administrativereorganization to move the LG&E Energy group from an indirect Powergensubsidiary to an indirect E.ON subsidiary. This reorganization was effective in March 2003.  In early 2004, LG&E Energy began directreporting arrangements to E.ON.

 

The utility operations (LG&E and KU) of LG&E Energy havecontinued their separate identities as LG&E and KU.  The preferred stock and debt securities ofLG&E and KU were not affected by these transactions.

 

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

 

5

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LOUISVILLE GAS AND ELECTRIC COMPANY

 

General

 

LG&E, incorporated in 1913 in Kentucky, is a regulated publicutility that supplies natural gas to approximately 318,000 customers andelectricity to approximately 390,000 customers in Louisville and adjacent areasin Kentucky.  LG&E’s service areacovers approximately 700 square miles in 17 counties and has an estimatedpopulation of one million.  Included inthis area is the Fort Knox Military Reservation, to which LG&E transportsgas and provides electric service, but does not provide any distributionservices.  LG&E also provides gasservice in limited additional areas. LG&E’s coal-fired electric generatingplants, all equipped with systems to reduce sulfur dioxide emissions, producemost of LG&E’s electricity.  Theremainder is generated by a hydroelectric power plant and combustionturbines.  Underground natural gasstorage fields help LG&E provide economical and reliable gas service tocustomers.  See Item 2, Properties.

 

For the year ended December 31, 2004, 70% of total operatingrevenues were derived from electric operations and 30% from gasoperations.  Electric and gas operatingrevenues and the percentages by class of service on a combined basis for thisperiod were as follows:

 
| **(in thousands)**              | ** ** | **Electric** | ** ** | **Gas** | ** ** | **Combined** | ** ** | **% Combined** | ** ** |
|---------------------------------|------------|--------------|------------|---------|------------|--------------|------------|----------------|------------|
| Residential                     |       | $            | 240,779    |    | $          | 222,574      |       | $              | 463,353    |   | 48 | % |
| Commercial                      |       | 202,025      |       | 88,774  |       | 290,799      |       | 30             | %          |
| Industrial                      |       | 119,758      |       | 15,277  |       | 135,035      |       | 14             | %          |
| Public  authorities             |       | 62,266       |       | 15,533  |       | 77,799       |       | 8              | %          |
| Total retail                    |       | 624,828      |       | 342,158 |       | 966,986      |       | 100            | %          |
| Wholesale  sales                |       | 185,563      |       | 7,195   |       | 192,758      |       |           |       |
| Gas  transported – net     |       | —       |       | 6,140   |       | 6,140        |       |           |       |
| Provision  for rate collections |       | (11,418      | )          | —  |       | (11,418      | )          |           |       |
| Miscellaneous                   |       | 16,724       |       | 1,578   |       | 18,302       |       |           |       |
| Total                           |       | $            | 815,697    |    | $          | 357,071      |       | $              | 1,172,768  |   |   |   |

 

See Note 13 of LG&E’s Notes to Financial Statements under Item 8for financial information concerning segments of business for the three yearsended December 31, 2004.

 

ElectricOperations

 

The sources of LG&E’s electric operating revenues and the volumesof sales for the three years ended December 31, 2004, were as follows:

 
| **(in thousands)**                        | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|-------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| ELECTRIC  OPERATING REVENUES              |       |     |       |     |       |     |       |
| Residential                               |       | $        | 240,779    |     | $          | 223,404  |       | $ | 232,527 |   |
| Commercial                                |       | 202,025  |       | 187,500  |       | 185,306  |       |
| Industrial                                |       | 119,758  |       | 111,535  |       | 111,988  |       |
| Public  authorities                       |       | 62,266   |       | 58,493   |       | 57,762   |       |
| Total retail                              |       | 624,828  |       | 580,932  |       | 587,583  |       |
| Wholesale  sales                          |       | 185,563  |       | 169,782  |       | 120,552  |       |
| Provision  for rate collections (refunds) |       | (11,418  | )          | (412     | )          | 11,656   |       |
| Miscellaneous                             |       | 16,724   |       | 17,886   |       | 16,251   |       |
|   Total                         |       | $        | 815,697    |     | $          | 768,188  |       | $ | 736,042 |   |

 
| **(Thousands of Mwh)** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
|------------------------|------------|------------|------------|------------|------------|------------|------------|
| ELECTRIC  SALES        |       |       |       |       |       |       |       |
| Residential            |       | 3,923      |       | 3,835      |       | 4,036      |       |
| Commercial             |       | 3,534      |       | 3,482      |       | 3,493      |       |
| Industrial             |       | 3,019      |       | 2,936      |       | 3,028      |       |
| Public  authorities    |       | 1,248      |       | 1,251      |       | 1,253      |       |
| Total retail           |       | 11,724     |       | 11,504     |       | 11,810     |       |
| Wholesale  sales       |       | 7,819      |       | 7,678      |       | 6,387      |       |
| Total                  |       | 19,543     |       | 19,182     |       | 18,197     |       |

 

6

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LG&E uses efficient coal-fired boilers, fully equipped with sulfurdioxide removal systems, to generate most of its electricity.  LG&E’s weighted-average system-wideemission rate for sulfur dioxide in 2004 was approximately 0.56 lbs./MMBtu ofheat input, with every generating unit below its emission limit established bythe Kentucky Division for Air Quality.

 

LG&E set an annual peak load of 2,485 Mw on July 13, 2004,when the temperature reached 88 degrees F in Louisville.

 

The electric utility business is affected by seasonal weatherpatterns.  As a result, operatingrevenues (and associated operating expenses) are not generated evenlythroughout the year.  See LG&E’sResults of Operations under Item 7.

 

LG&E currently maintains a 13% – 15% reserve margin range.  At December 31, 2004, LG&E ownedsteam and combustion turbine generating facilities with a net summer capabilityof 3,105 Mw and an 80 Mw nameplate-rated hydroelectric facility on the OhioRiver with a summer capability rate of 48 Mw. See Item 2, Properties.  LG&Ealso obtains power from other utilities under bulk power purchase and interchangecontracts.  At December 31, 2004,LG&E’s system net summer capability, including purchases from others andexcluding the hydroelectric facility, was 3,260 Mw.  See Item 2, Properties.

 

LG&E and 11 other electric utilities are participating owners ofOVEC located in Piketon, Ohio.

 

In March 2005, LG&E purchased from American Electric PowerCompany Inc. (“AEP”) an additional 0.73% interest in OVEC for a purchase priceof approximately $0.1 million, which resulted in an increase in LG&Eownership in OVEC from 4.9% to 5.63%. OVEC owns and operates two power plants that burn coal to generateelectricity, Kyger Creek Station in Ohio and Clifty Creek Station inIndiana.  LG&E’s share is 7%,representing approximately 155 Mw of generation capacity.

 

LG&E is a member of the MISO and therefore has turned overoperational control of transmission facilities 100 kV and above, but continues to control and operate the lower voltagetransmission subject to the terms and conditions of the MISO.  The MISO currently controls over 100,000miles of transmission lines over 1.1 million square miles located in thenorthern Midwest between Manitoba, Canada and Kentucky.  As a transmission-owning member of the MISO,LG&E also incurs costs under the MISO Open Access Transmission Tariff,including the Schedule 10 adder which recovers the operational and capitalcosts incurred by the MISO.  Fordiscussion of current MISO matters, see Rates and Regulation for LG&E underItem 7 and Note 3 of LG&E’s Notes to Financial Statements under Item 8.

 

Gas Operations

 

The sources of LG&E’s gas operating revenues and the volumes ofsales for the three years ended December 31, 2004, were as follows:

 

7

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| **(in thousands)**          | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|-----------------------------|------------|----------|------------|----------|------------|----------|------------|
| GAS  OPERATING REVENUES     |       |     |       |     |       |     |       |
| Residential                 |       | $        | 222,574    |     | $          | 198,881  |       | $ | 160,733 |   |
| Commercial                  |       | 88,774   |       | 78,280   |       | 61,036   |       |
| Industrial                  |       | 15,277   |       | 13,812   |       | 10,232   |       |
| Public  authorities         |       | 15,533   |       | 13,745   |       | 11,197   |       |
| Total retail                |       | 342,158  |       | 304,718  |       | 243,198  |       |
| Wholesale  sales            |       | 7,195    |       | 12,278   |       | 16,384   |       |
| Gas  transported – net |       | 6,140    |       | 6,046    |       | 6,232    |       |
| Miscellaneous               |       | 1,578    |       | 2,291    |       | 1,879    |       |
| Total                       |       | $        | 357,071    |     | $          | 325,333  |       | $ | 267,693 |   |

 
| **(Millions of cu. ft.)** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
|---------------------------|------------|------------|------------|------------|------------|------------|------------|
| GAS SALES                 | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Residential               |       | 21,402     |       | 23,192     |       | 22,124     |       |
| Commercial                |       | 9,144      |       | 9,652      |       | 9,074      |       |
| Industrial                |       | 1,736      |       | 1,880      |       | 1,783      |       |
| Public  authorities       |       | 1,646      |       | 1,746      |       | 1,747      |       |
| Total retail              |       | 33,928     |       | 36,470     |       | 34,728     |       |
| Wholesale  sales          |       | 1,221      |       | 2,119      |       | 5,345      |       |
| Gas  transported          |       | 13,692     |       | 13,683     |       | 13,939     |       |
| Total                     |       | 48,841     |       | 52,272     |       | 54,012     |       |

 

The gas utility business is affected by seasonal weather patterns.  As a result, operating revenues (andassociated operating expenses) are not generated evenly throughout theyear.  While natural gas usage patternsare seasonal, LG&E received approval from the Kentucky Commission for a WNAmechanism.  The WNA mechanism adjusts thedistribution cost recovery component of the natural gas billings of residentialand commercial customers to normal temperatures during the heating seasonmonths of November through April, somewhat mitigating the effect of weatherextremes.  LG&E requested, and theKentucky Commission approved, an extension of the current WNA mechanism throughApril 30, 2006.  See LG&E’sResults of Operations under Item 7.

 

LG&E has five underground natural gas storage fields that helpprovide economical and reliable gas service to ultimate consumers.  By using gas storage facilities, LG&Eavoids the costs associated with typically more expensive pipelinetransportation capacity to serve peak winter space-heating loads.  LG&E stores gas in the summer season forwithdrawal in the subsequent winter heating season.  Without its storage capacity, LG&E wouldbe forced to buy additional gas and pipeline transportation services during thewinter months when customer demand increases and when the prices for gas supplyand transportation services are typically at their highest.  Currently, LG&E buys competitively pricedgas from several large suppliers under contracts of varying duration.  LG&E’s underground storage facilities, incombination with its purchasing practices, enable it to offer gas sales serviceat rates lower than state and national averages.  At December 31, 2004, LG&E had aninventory balance of gas stored underground of approximately 12.2 million Mcfof working gas valued at approximately $77.5 million.

 

A number of industrial customers purchase their natural gasrequirements directly from alternate suppliers for delivery through LG&E’sdistribution system.  These largeindustrial customers account for approximately one-fourth of LG&E’s annualthroughput.

 

During 2004, the maximum day gas sendout was approximately 491,000 Mcf,occurring on January 30, 2004, when the average temperature for the daywas 7 degrees F.  Supply on that dayconsisted of approximately 235,000 Mcf from purchases, approximately 180,000Mcf delivered from underground storage, and approximately 76,000 Mcftransported for industrial customers. For a further discussion, see Gas Supply under Item 1.

 

Rates and Regulation

 

As a subsidiary ofa registered holding company under PUHCA, LG&E is subject to extensiveregulation by the SEC under PUHCA with respect to issuances and sales ofsecurities, acquisitions and sales of certain utility properties, andintra-system sales of certain goods and services.  In addition, PUHCA generally limits theability

 

8

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of registeredholding companies to acquire additional public utility systems and to acquireand retain businesses unrelated to the utility operations of the holdingcompany.  LG&E believes that it hasadequate authority (including financing authority) under existing SEC ordersand regulations to conduct its business. LG&E will seek additional authorization when necessary.  E.ON’s general financing approval order under PUHCA (including certainLG&E components) expires in May 2005 and an application has been submittedto the SEC for renewed or modified financing authorizations for an additionalthree year period.  LG&E anticipatesreceiving a timely approval from the SEC, but such approval cannot be assured.

 

The Kentucky Commission has regulatory jurisdiction over LG&E’sretail rates and service, and over the issuance of certain of its securities.  The Kentucky Commission has the ability toexamine the rates LG&E charges its retail customers at any time.  FERC has classified LG&E as a “publicutility” as defined in the FPA.  TheDepartment of Energy and FERC have jurisdiction under the FPA over certainelectric utility facilities and operations, wholesale sale of power and relatedtransactions, accounting practices of LG&E, and in certain other respectsas provided in the FPA.

 

Pursuant to Kentucky law, the Kentucky Commission has established theboundaries of the service territory or area of each retail electric supplier inKentucky (including LG&E), other than municipal corporations.  Within this service territory, each suchsupplier has the exclusive right to render retail electric service.

 

LG&E’s retail electric rates contain a FAC, whereby increases anddecreases in the cost of fuel for electric generation are reflected in therates charged to retail electric customers.  The Kentucky Commission requires publichearings at six-month intervals to examine past fuel adjustments, and attwo-year intervals to review past operations of the fuel clause and transfer ofthe then current fuel adjustment charge or credit to the base charges.  The Kentucky Commission also requires thatelectric utilities, including LG&E, file certain documents relating to fuelprocurement and the purchase of power and energy from other utilities.

 

Prior to 2004, LG&E’s retail electric rates were subject to anESM.  LG&E and the KentuckyCommission agreed to a termination of the ESM relating to all periods after2003.  The ESM, initially in place forthree years beginning in 2000, set an upper and lower point for rate of returnon equity, whereby if LG&E’s rate of return for the calendar year fellwithin the range of 10.5% to 12.5%, no action was necessary.  If earnings were above the upper limit, theexcess earnings were shared 40% with ratepayers and 60% with shareholders; ifearnings were below the lower limit, the earnings deficiency was recovered 40%from ratepayers and 60% from shareholders. By order of the Kentucky Commission, rate changes prompted by the ESMfiling went into effect in April of each year subject to a balancingadjustment in successive periods.  Fordiscussion of current ESM matters, see Rates and Regulation for LG&E underItem 7 and Note 3 of LG&E’s Notes to Financial Statements under Item 8.

 

LG&E’s retail rates contain an ECR surcharge which recovers certaincosts incurred by LG&E that are required to comply with the Clean Air Actand other environmental regulations.  SeeRates and Regulation for LG&E under Item 7 and Note 3 of LG&E’sNotes to Financial Statements under Item 8.

 

LG&E’s gas rates contain a GSC, whereby increases or decreases inthe cost of gas supply are reflected in LG&E’s rates, subject to approvalby the Kentucky Commission.  The GSCprocedure prescribed by order of the Kentucky Commission provides for quarterlyrate adjustments to reflect the expected cost of gas supply in thatquarter.  In addition, the GSC contains amechanism whereby any over- or under-recoveries of gas supply cost from priorquarters will be refunded to or recovered from customers through the adjustmentfactor determined for subsequent quarters.

 

Integrated resource planning regulations in Kentucky require LG&Eand the other major utilities to make triennial filings with the KentuckyCommission of various historical and forecasted information relating to load,

 

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capacity margins and demand-side management techniques.  LG&E filed its most recent IRP in October 2002.  The Kentucky Commission issued its StaffReport and ordered the case closed in December 2003 with no significantfindings.  The next IRP is due April 2005,and will incorporate the recommendations from the Staff Report regarding the2002 IRP.

 

In December 2003, LG&E filed applications with the KentuckyCommission requesting adjustments in LG&E’s electric and gas rates.  LG&E asked for general adjustments inelectric and gas rates based on the twelve month test year ended September 30,2003.  The revenue increases requestedwere $63.8 million for electric and $19.1 million for gas.  In June 2004, the Kentucky Commissionissued an order approving increases in LG&E’s annual electric base rates ofapproximately $43.4 million (7.7%) and annual gas base rates of approximately$11.9 million (3.4%). The rate increases took effect on July 1, 2004.

 

DuringJuly 2004, the Attorney General of Kentucky (“AG”) served subpoenas onLG&E, as well as on the Kentucky Commission and its staff, requestinginformation regarding allegedly improper communications between LG&E andthe Kentucky Commission, particularly during the period covered by the ratecase.  The Kentucky Commission has procedurallyreopened the rate cases for the limited purpose of taking evidence, if any, asto the communication issues.

 

LG&E believes no improprieties have occurred in its communicationswith the Kentucky Commission and is cooperating with the proceedings before theAG and the Kentucky Commission.  LG&Eis currently unable to determine the ultimate impact, if any, of, or anypossible future actions of the AG or the Kentucky Commission arising out of,the AG’s report and investigation, including whether there will be furtheractions to appeal, review or otherwise challenge the granted increases in baserates.

 

For a further discussion of regulatory matters, see Rates andRegulation for LG&E under Item 7 and Note 3 of LG&E’s Notes toFinancial Statements under Item 8.

 

Construction Program and Financing

 

LG&E’s construction program is designed to ensure that there willbe adequate capacity and reliability to meet the electric and gas needs of itsservice area.  These needs arecontinually being reassessed and appropriate revisions are made, whennecessary, in construction schedules. LG&E’s estimates of its construction expenditures can vary substantiallydue to numerous items beyond LG&E’s control, such as changes in interestrates, economic conditions, construction costs, and new environmental or othergovernmental laws and regulations.

 

During the five years ended December 31, 2004, gross propertyadditions amounted to approximately $1 billion.  Internally generated funds and externalfinancings for the five-year period were utilized to provide for these grossadditions.  The gross additions duringthis period amounted to approximately 25% of total utility plant at December 31,2004, and consisted of $821 million for electric properties and $156 millionfor gas properties.  Gross retirementsduring the same period were $126 million, consisting of $92 million forelectric properties and $34 million for gas properties.

 

Capital expendituresduring the five years ending December 31, 2009 are estimated to beapproximately $843 million.  The majorexpenditures during this period relate to the development and construction ofTrimble County Unit 2, of which LG&E’s portion totals $158 million,contingent upon approval of the Company’s application for a CCN by the KentuckyCommission, and the redevelopment of the Ohio Falls hydro facility ($46million).

 

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Coal Supply

 

Coal-fired generating units provided over 98.2% of LG&E’s netkilowatt-hour generation for 2004.  Theremaining net generation for 2004 was provided by natural gas and oil-fueledcombustion turbine peaking units (0.5%) and a hydroelectric plant (1.3%).  Coal is expected to be the predominant fuelused by LG&E in the foreseeable future, with natural gas and oil being usedfor peaking capacity and flame stabilization in coal-fired boilers or in emergencies.  LG&E has no nuclear generating units andhas no plans to build any in the foreseeable future.

 

LG&E maintains its fuel inventory at levels estimated to benecessary to avoid operational disruptions at its coal-fired generatingunits.  Reliability of coal deliveriescan be affected from time to time by a number of factors, includingfluctuations in demand, coal mine production issues and other supplier ortransporter operating difficulties.

 

LG&E has entered into coal supply agreements with various suppliersfor coal deliveries for 2005 and beyond. The Company normally augments its coal supply agreements with spotmarket purchases.  LG&E has a coalinventory policy which it believes provides adequate protection under mostcontingencies.  It had a coal inventoryof approximately 0.7 million tons, or a****36-day supply,on hand at December 31, 2004.

 

LG&E expects to continue purchasing most of its coal, with sulfurcontent in the 2%-4.5% range, from western Kentucky, southern Indiana, and WestVirginia for the foreseeable future. This supply is relatively low-priced coal, and in combination with itssulfur dioxide removal systems is expected to enable LG&E to continue toprovide electric service in compliance with existing environmental laws andregulations.

 

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 thepercentage of spot coal purchases were as follows:

 
| ** **                          | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|-------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Per ton                             |       | $        | 26.25      |     | $          | 25.56    |       | $ | 25.30 |   |
| Per MMBtu                           |       | $        | 1.15       |     | $          | 1.12     |       | $ | 1.11 |   |
| Spot  purchases as % of all sources |       | 7        | %          | 1        | %          | 2        | %          |

 

The delivered cost of coal is expected to increase in 2005 due tomarket conditions.

 

Gas Supply

 

LG&E purchases natural gas supplies from multiple sources under contractsfor varying periods of time, while transportation services are purchased fromTexas Gas and Tennessee Gas.

 

LG&Eparticipates in rate and other proceedings affecting the regulated interstatenatural gas pipelines that provide service to LG&E. Although both Texas Gasand Tennessee Gas have several active proceedings in which LG&E isparticipating at the FERC, neither interstate natural gas pipeline has filed anapplication at FERC to increase the pipeline’s base rates.  Additionally, the rates of these pipelinesare not being billed subject to refund, and LG&E has refunded to itscustomers any amounts which have been refunded to it as the result of thesettlement of any FERC proceedings. Texas Gas is obligated to file a general rate case at FERC to beeffective no later than November 1, 2005. Tennessee Gas is under no such obligation.

 

LG&E transports on the Texas Gas system under Rate Schedules NNSand FT service.  During the winter

 

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months, LG&E has 184,900 MMBtu/day in NNS and 36,000 MMBtu/day inFT service.  LG&E’s summer NNS levelsare 60,000 MMBtu/day and its summer FT levels are 54,000 MMBtu/day.  Each of these NNS and FT agreements withTexas Gas are subject to termination by LG&E in equal portions during 2005,2006, and 2008.  LG&E has providedTexas Gas with notice to terminate a portion of the summer-only FT agreement inthe amount of 18,000 MMBtu/day effective November 1, 2005.  After that date, LG&E will have FTservice during the summer in the amount of 36,000 MMBtu/day.  For January 2005 only, LG&Econtracted for short-term firm transportation service from Texas Gas under RateSchedule STF in the amount of 15,000 MMBtu/day.  LG&E also transports on the Tennessee Gassystem under Tennessee Gas’s Rate Schedule FT-A.  LG&E’s contract levels with Tennessee Gasare 51,000 MMBtu/day throughout the year. The FT-A agreement with Tennessee Gas is subject to termination byLG&E during 2007.

 

LG&E also has a portfolio of supply arrangementsof various terms with a number of suppliers designed to meet its firm salesobligations.  These gas supplyarrangements include pricing provisions that are market-responsive.  These firm gas supplies, in tandem withpipeline transportation services, provide the reliability and flexibilitynecessary to serve LG&E’s gas customers.

 

LG&E owns andoperates five underground gas storage fields with a current working gascapacity of approximately 15.1 million Mcf. Gas is purchased and injected into storage during the summer season whennatural gas prices are typically lower, and is then withdrawn to supplementpipeline supplies to meet the gas-system load requirements during the winterheating season.  See Gas Operations underItem 1.

 

The estimatedmaximum deliverability from storage during the early part of the heating seasonis approximately 373,000 Mcf/day. Deliverability decreases during the latter portion of the heating seasonas the storage inventory is reduced by seasonal withdrawals.

 

The average cost per Mcf of natural gas purchased by LG&E was $7.18in 2004, $6.30 in 2003, and $4.19 in 2002. Natural gas prices in the unregulated wholesale market generally haveincreased significantly over the last few years beginning in 2000.  These increases in natural gas prices, causedin part by decreased natural gas production, decreased liquidity in themarketplace, and increased demand for natural gas as a fuel for electricgeneration have been significantly affected by changing national gas storageinventory levels.  LG&E relies uponstorage to mitigate the price volatility to which customers might otherwise beexposed.

 

Environmental Matters

 

Protection of the environment is a major priority for LG&E.  Federal, state, and local regulatory agencieshave 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 2004,expenditures for pollution control facilities represented $247 million or 25%of total construction expenditures. LG&E estimates that construction expenditures for environmentalprotection equipment from 2005 through 2009 will be approximately $56million.  For a discussion of environmentalmatters, see Rates and Regulation for LG&E under Item 7 and Note 11 ofLG&E’s Notes to Financial Statements under Item 8.

 

Competition

 

In the last several years, LG&E has taken many steps to keep itsrates low while maintaining high levels of customer satisfaction, including areduction in the number of employees; aggressive cost cutting; an increase infocus on commercial, industrial and residential customers; an increase inemployee involvement and training; and continuous modifications of its organizationalstructure.  LG&E will take additionalsteps to better position itself should retail competition come to Kentucky.

 

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At this time, neither the Kentucky General Assembly nor the KentuckyCommission has adopted or approved a plan or timetable for retail electricindustry competition in Kentucky.  Thenature or timing of the ultimate legislative or regulatory actions regardingindustry restructuring and their impact on LG&E, which may be significant,cannot currently be predicted.  Somestates that have already deregulated have begun discussions that could lead tore-regulation.

 

In February 2005,Kentucky’s Governor signed an executive order directing the KentuckyCommission, in conjunction with the Commerce Cabinet and the Environmental andPublic Protection Cabinet, to ‘develop a Strategic Blueprint for the continueduse and development of electric energy.’ This Strategic Blueprint will bedesigned to promote future investment in electric infrastructure for theCommonwealth of Kentucky, to protect Kentucky’s low-cost electric advantage, tomaintain affordable rates for all Kentuckians, and to preserve Kentucky’scommitment to environmental protection.” In March 2005, the Kentucky Commission established AdministrativeCase No. 2005-00090 to collect information from all jurisdictional utilities inKentucky, including LG&E, pertaining to Kentucky electric generation,transmission and distribution systems. The KPSC must provide its Strategic Blueprint to the Governor in early August 2005.  LG&E must respond to the KentuckyCommission’s first set of data requests by the end of March 2005.

 

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KENTUCKYUTILITIES COMPANY

 

General

 

KU, incorporated in Kentucky in 1912 and incorporated in Virginia in1991, is a regulated public utility engaged in producing, transmitting andselling electric energy.  KU provideselectric service to approximately 488,000 customers in over 600 communities andadjacent suburban and rural areas in 77 counties in central, southeastern andwestern Kentucky, to approximately 30,000 customers in 5****countiesin southwestern Virginia and to less than 10 customers in Tennessee.  In Virginia, KU operates under the name OldDominion Power Company.  KU operatesunder appropriate franchises in substantially all of the 160 Kentuckyincorporated municipalities served.  Nofranchises are required in unincorporated Kentucky or Virginiacommunities.  The lack of franchises isnot expected to have a material adverse effect on KU’s operations**. **KU also sellswholesale electric energy to 12 municipalities.

 

ElectricOperations

 

The sources of KU’s electric operating revenues and the volumes ofsales for the three years ended December 31, 2004, were as follows:

 
| **(in thousands)**                        | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|-------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| ELECTRIC  OPERATING REVENUES              |       |     |       |     |       |     |       |
| Residential                               |       | $        | 303,635    |     | $          | 278,461  |       | $ | 274,660 |   |
| Commercial                                |       | 206,931  |       | 189,113  |       | 178,694  |       |
| Industrial                                |       | 190,560  |       | 175,601  |       | 163,372  |       |
| Mine power                                |       | 31,703   |       | 29,584   |       | 28,664   |       |
| Public  authorities                       |       | 72,158   |       | 66,452   |       | 62,490   |       |
| Total retail                              |       | 804,987  |       | 739,211  |       | 707,880  |       |
| Wholesale  sales                          |       | 160,002  |       | 138,003  |       | 117,252  |       |
| Provision  for rate collections (refunds) |       | 4,751    |       | (8,534   | )          | 15,481   |       |
| Miscellaneous                             |       | 25,622   |       | 23,098   |       | 21,051   |       |
| Total                                     |       | $        | 995,362    |     | $          | 891,778  |       | $ | 861,664 |   |

 
| **(Thousands of Mwh)** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
|------------------------|------------|------------|------------|------------|------------|------------|------------|
| ELECTRIC  SALES        |       |       |       |       |       |       |       |
| Residential            |       | 6,160      |       | 6,001      |       | 6,198      |       |
| Commercial             |       | 4,323      |       | 4,210      |       | 4,161      |       |
| Industrial             |       | 5,400      |       | 5,110      |       | 4,975      |       |
| Mine power             |       | 732        |       | 722        |       | 766        |       |
| Public  authorities    |       | 1,597      |       | 1,551      |       | 1,533      |       |
| Total retail           |       | 18,212     |       | 17,594     |       | 17,633     |       |
| Wholesale  sales       |       | 5,707      |       | 5,591      |       | 4,794      |       |
| Total                  |       | 23,919     |       | 23,185     |       | 22,427     |       |

 

KU’s weighted-average system-wide emission rate for sulfur dioxide in2004 was approximately****1.4****lbs./MMBtu****of heat input,with every generating unit below its emission limit established by the KentuckyDivision for Air Quality.

 

KU set an annual peak load of 3,768 Mw on January 7, 2004, whenthe temperature was 13 degrees F.  On January 18,2005, KU achieved the highest hourly customer demand in KU’s history, with apeak load of 4,065 Mw.

 

The electric utility business is affected by seasonal weatherpatterns.  As a result, operatingrevenues (and associated operating expenses) are not generated evenlythroughout the year.  See KU’s Results ofOperations

 

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under Item 7.

 

KU currently maintains a 13% -15% reserve margin range.  At December 31, 2004, KU owned steam andcombustion turbine generating facilities with a net summer capability of 4,433Mw and a 28 Mw nameplate-rated hydroelectric facility with a summer capabilityof 24 Mw.  See Item 2, Properties.  KU obtains power from other utilities underbulk power purchase and interchange contracts.  At December 31, 2004, KU’s system netsummer capability, including purchases from others and excluding the hydroelectricfacility, was 4,934 Mw.

 

Under a contract expiring in 2020 with OMU, KU has agreed to purchasefrom OMU the surplus output of the 142-Mw and 265-Mw generating units at OMU’sElmer Smith station.  Purchases under thecontract are made under a contractual formula resulting in costs which areexpected to be comparable to the cost of other power purchased or generated byKU.  Such power equated to approximately9% of KU’s net generation system output during 2004.  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 a1,000-Mw generating station in southern Illinois.  KU is entitled to take 20% of the availablecapacity of the station.  Purchases from EEIare made under a contractual formula which has resulted in costs which were andare expected to be comparable to the cost of other power generated by KU.  This contract governing the purchases fromEEI will terminate on December 31, 2005. Such power equated to approximately 10% of KU’s net generation systemoutput in 2004.  See Note 11 of KU’s Notes to FinancialStatements under Item 8.

 

KU and 11 other electric utilities are participating owners of OVEC,located in Piketon, Ohio.  KU’sinvestment in OVEC is the equivalent of 2.5% of OVEC’s common stock.  OVEC owns and operates two power plants thatburn coal to generate electricity, Kyger Creek Station in Ohio and Clifty CreekStation in Indiana.  KU’s share is 2.5%,approximately 55 Mw of generation capacity.

 

KU is a member of the MISO and therefore has turned over operationalcontrol of transmission facilities 100 kV and above, but continues to controland operate the lower voltage transmission subject to the terms and conditionsof the MISO.  The MISO currently controlsover 100,000 miles of transmission over 1.1 million square miles located in thenorthern Midwest between Manitoba, Canada and Kentucky.  As a transmission-owning member of the MISO,KU also incurs costs under the MISO Open Access Transmission Tariff, includingthe Schedule 10 adder which recovers the operational and capital costsincurred by the MISO.  For discussion ofcurrent MISO matters, see Rates and Regulation for KU under Item 7 and Note 3of KU’s Notes to Financial Statements under Item 8.

 

Rates andRegulation

 

As a subsidiary ofa registered holding company under PUHCA, KU is subject to extensive regulationby the SEC under PUHCA with respect to issuances and sales of securities,acquisitions and sales of certain utility properties, and intra-system sales ofcertain goods and services.  In addition,PUHCA generally limits the ability of registered holding companies to acquireadditional public utility systems and to acquire and retain businessesunrelated to the utility operations of the holding company.  KU believes that it has adequate authority(including financing authority) under existing SEC orders and regulations toconduct its business.  KU will seekadditional authorization when necessary.  E.ON’s general financing approval order under PUHCA (including certainKU components) expires in May 2005 and an application has been submitted to theSEC for renewed or modified financing authorizations for an additional threeyear period.  KU anticipates receiving atimely approval from the SEC, but such approval cannot be assured.

 

The Kentucky Commission and the Virginia Commission have regulatoryjurisdiction over KU’s retail rates and service, and over the issuance ofcertain of its securities.  By reason ofowning and operating a small amount of

 

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electric utility property in one county in Tennessee (having a grossbook value of approximately $0.3 million) from which KU served 5 customers at December 31,2004, KU is subject to the jurisdiction of the Tennessee RegulatoryAuthority.  FERC has classified KU as a “publicutility” as defined in the FPA.  TheDepartment of Energy and FERC have jurisdiction under the FPA over certain ofthe electric utility facilities and operations, wholesale sale of power andrelated transactions, accounting practices of KU, and in certain other respectsas provided in the FPA.

 

Pursuant to Kentucky law, the Kentucky Commission has established theboundaries of the service territory or area of each retail electric supplier inKentucky (including KU), other than municipal corporations.  Within this service territory each suchsupplier has the exclusive right to render retail electric service.

 

KU’s Kentucky retail electric rates contain a FAC, whereby increasesand decreases in the cost of fuel for electric generation are reflected in therates charged to retail electric customers. The Kentucky Commission requires public hearings at six-month intervalsto examine past fuel adjustments, and at two-year intervals to review pastoperations of the fuel clause and transfer of the then current fuel adjustmentcharge or credit to the base charges. The Kentucky Commission also requires that electric utilities, includingKU, file certain documents relating to fuel procurement and the purchase ofpower and energy from other utilities. The FAC mechanism for Virginia customers uses an average fuel costfactor based primarily on projected fuel costs. The fuel cost factor may be adjusted annually for over or under collectionsof fuel costs from the previous year.

 

Prior to 2004, KU’s Kentucky retail electric rates were subject to anESM.  KU and the Kentucky Commissionagreed to a termination of the ESM relating to all periods after 2003.  The ESM, initially in place for three yearsbeginning in 2000, set an upper and lower point for rate of return on equity,whereby if KU’s rate of return for the calendar year fell within the range of10.5% to 12.5%, no action was necessary. If earnings were above the upper limit, the excess earnings were shared40% with ratepayers and 60% with shareholders; if earnings were below the lowerlimit, the earnings deficiency was recovered 40% from ratepayers and 60% fromshareholders**. **Byorder of the Kentucky Commission, rate changes prompted by the ESM filing wentinto effect in April of each year subject to a balancing adjustment insuccessive periods.  There is no ESM forVirginia retail electric rates.  Fordiscussion of current ESM matters, see Rates and Regulation for KU under Item 7and Note 3 of KU’s Notes to Financial Statements under Item 8.

 

KU’s Kentucky retail rates contain an ECR surcharge which recoverscertain costs incurred by KU that are required to comply with the Clean Air Actand other environmental regulations.  SeeRates and Regulation for KU under Item 7 and Note 3 of KU’s Notes toFinancial Statements under Item 8.

 

Integrated resource planning regulations in Kentucky require KU and theother major utilities to make triennial filings with the Kentucky Commission ofvarious historical and forecasted information relating to load, capacitymargins and demand-side management techniques. KU filed its most recent IRP in October 2002.  The Kentucky Commission issued its StaffReport and ordered the case closed in December 2003 with no significantfindings.  The next IRP is due April 2005,and will incorporate the recommendations from the Staff Report regarding the2002 IRP.

 

The Commonwealth of Virginia passed the Virginia Electric UtilityRestructuring Act in 1999.  This act gaveVirginia customers the ability to choose their electric supplier.  Rates are capped at current levels through December 2010.  The Virginia Commission will continue torequire each Virginia utility to make annual filings of either a base ratechange or an Annual Informational Filing consisting of a set of standardfinancial schedules.  The Virginia Staffwill issue a Staff Report regarding the individual utility’s financialperformance during the historic 12-month period.  The Staff Report can lead to an adjustment inrates, but through December 2010 rates are subject to the capped rateperiod and essentially “frozen”. However, KU may petition the

 

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Virginia Commission for a one-time adjustment in rates during thecapped rate period.  Effective July 1,2003, the General Assembly of Virginiaamended and reenacted Section 56-580 of the Code of Virginia with languagethat effectively exempts all KU Virginia service territory from retail choiceuntil such time as retail choice is offered to customers in KU’s other serviceterritories.

 

In December 2003, KU filed an application with the KentuckyCommission requesting an adjustment in KU’s electric rates.  KU asked for a general adjustment in electricrates based on the twelve month test year ended September 30, 2003.  The revenue increase requested was $58.3million.  In June 2004, the KentuckyCommission issued an order approving an increase in KU’s annual electric baserates of approximately $46.1 million (6.8%). The rate increase took effect on July 1,2004.

 

DuringJuly 2004, the AG served subpoenas on KU, as well as on the KentuckyCommission and its staff, requesting information regarding allegedly impropercommunications between KU and the Kentucky Commission, particularly during theperiod covered by the rate case.  TheKentucky Commission has procedurally reopened the rate cases for the limitedpurpose of taking evidence, if any, as to the communication issues.

 

KU believes no improprieties have occurred in its communications withthe Kentucky Commission and is cooperating with the proceedings before the AGand the Kentucky Commission.  KU iscurrently unable to determine the ultimate impact, if any, of, or any possiblefuture actions of the AG or the Kentucky Commission arising out of, the AG’sreport and investigation, including whether there will be further actions to appeal,review or otherwise challenge the granted increases in base rates.

 

For a further discussion of regulatory matters, see Rates andRegulation for KU under Item 7 and Note 3 of KU’s Notes to the FinancialStatements under Item 8.

 

Construction Program andFinancing

 

KU’s construction program is designed to ensure that there will beadequate capacity and reliability to meet the electric needs of its servicearea.  These needs are continually beingreassessed and appropriate revisions are made, when necessary, in constructionschedules.  KU’s estimates of itsconstruction expenditures can vary substantially due to numerous items beyondKU’s control, such as changes in interest rates, economic conditions,construction costs, and new environmental or other governmental laws andregulations.

 

During the five years ended December 31, 2004, gross propertyadditions amounted to approximately $1 billion.  Internally generated funds and externalfinancings for the five-year period were utilized to provide for these grossadditions.  The gross additions duringthis period amounted to approximately 26% of total utility plant at December 31,2004.  Gross retirements during the sameperiod were $114 million.

 

Capital expendituresduring the five years ending December 31, 2009 are estimated to beapproximately $1.9 billion.  The majorexpenditures during this period relate to the development and construction ofTrimble County Unit 2, of which KU’s portion totals approximately $672 million,and the installation of FGDs on Ghent and Brown units, totaling approximately$678 million.  Expenditures for TrimbleCounty Unit 2 and the FGDs are contingent upon approval of the Company’sapplication for CCNs by the Kentucky Commission.

 

Coal Supply

 

Coal-fired generating units provided over 98.7% of KU’s netkilowatt-hour generation for 2004.  Theremaining net generation for 2004 was provided by natural gas and oil-fueledcombustion turbine peaking units (0.7%) and

 

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hydroelectric plants (0.6%). Coal is expected to be the predominant fuel used by KU in theforeseeable future, with natural gas and oil being used for peaking capacityand flame stabilization in coal-fired boilers or in emergencies.  KU has no nuclear generating units and has noplans to build any in the foreseeable future.

 

KU maintains its fuel inventory at levels estimated to be necessary toavoid operational disruptions at its coal-fired generating units.  Reliability of coal deliveries can beaffected from time to time by a number of factors, including fluctuations indemand, coal mine production issues and other supplier or transporter operatingdifficulties.

 

KU has entered into coal supply agreements with various suppliers forcoal deliveries for 2005 and beyond.  TheCompany normally augments its coal supply agreements with spot marketpurchases.  KU has a coal inventorypolicy which it believes provides adequate protection under mostcontingencies.  It had a coal inventoryof approximately 1.0 million tons, or a 49-day supply, on hand at December 31,2004.

 

KU expects to continue purchasing most of its coal, which has a sulfurcontent in the 0.7% - 3.5% range, from western and eastern Kentucky, WestVirginia, southern Indiana, Wyoming and Colorado 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 and truck.

 

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

 
| ** **                          | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|-------------------------------------|------------|----------|------------|----------|------------|----------|------------|
|                                |       |     |       |     |       |     |       |
| Per ton                             |       | $        | 37.69      |     | $          | 34.57    |       | $ | 31.44 |   |
| Per MMBtu                           |       | $        | 1.56       |     | $          | 1.47     |       | $ | 1.35 |   |
| Spot  purchases as % of all sources |       | 14       | %          | 11       | %          | 18       | %          |

 

KU’s historical average cost of coal purchased is higher than LG&E’sdue to the lower sulfur content of the coal KU purchases for use at its Ghentplant and higher cost to transport coal to the E.W. Brown plant.  The delivered cost of coal for 2005 isexpected to increase due to market conditions.

 

EnvironmentalMatters

 

Protection of the environment is a major priority for KU.  Federal, state, and local regulatory agencieshave issued KU permits for various activities subject to air quality, waterquality, and waste management laws and regulations.  For the five-year period ending with 2004,expenditures for pollution control facilities represented $246 million or 25%of total construction expenditures.  KUestimates that construction expenditures for environmental control equipmentfrom 2005 through 2009, primarily related to the installation of FGDs on threeGhent units, will be approximately $719 million.  For a discussion of environmental matters,see Rates and Regulation for KU under Item 7 and Note 11 of KU’s Notes toFinancial Statements under Item 8.

 

Competition

 

In the last several years, KU has taken many steps to keep its rateslow while maintaining high levels of customer satisfaction, including areduction in the number of employees; aggressive cost cutting; an increase infocus on commercial, industrial and residential customers; an increase inemployee involvement and training; and

 

18

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continuous modifications of its organizational structure.  KU will take additional steps to betterposition itself should retail competition come to Kentucky.

 

At this time, neither the Kentucky General Assembly nor the KentuckyCommission has adopted or approved a plan or timetable for retail electricindustry competition in Kentucky.  Thenature or timing of the ultimate legislative or regulatory actions regardingindustry restructuring and their impact on KU, which may be significant, cannotcurrently be predicted.  Some states thathave already deregulated have begun discussions that could lead tore-regulation.

 

In February 2005,Kentucky’s Governor signed an executive order directing the KentuckyCommission, in conjunction with the Commerce Cabinet and the Environmental andPublic Protection Cabinet, to ‘develop a Strategic Blueprint for the continueduse and development of electric energy.’ This Strategic Blueprint will bedesigned to promote future investment in electric infrastructure for theCommonwealth of Kentucky, to protect Kentucky’s low-cost electric advantage, tomaintain affordable rates for all Kentuckians, and to preserve Kentucky’scommitment to environmental protection. In March 2005, the Kentucky Commission established AdministrativeCase No. 2005-00090 to collect information from all jurisdictional utilities inKentucky, including KU, pertaining to Kentucky electric generation,transmission and distribution systems. The KPSC must provide its Strategic Blueprint to the Governor in early August 2005.  KU must respond to the Kentucky Commission’sfirst set of data requests by the end of March 2005.

 

Virginia has enacted a phase-in of customer choice through the VirginiaElectric Restructuring Act.  The VirginiaCommission is promulgating regulations to govern the various activitiesrequired by the Act.  Effective July 1, 2003, the General Assemblyof Virginia amended and reenacted Section 56-580 of the Code of Virginiawith language that effectively exempts all KU Virginia service territory fromretail choice until such time as retail choice is offered to customers in KU’sother service territories.

 

EMPLOYEES ANDLABOR RELATIONS

 

LG&E had approximately 887 full-time regular employees and KU hadapproximately 934 full-time regular employees at February 28, 2005. Of theLG&E total, 643 operating, maintenance, and construction employees wererepresented by IBEW Local 2100.  LG&Eand employees represented by IBEW Local 2100 signed a four-year collectivebargaining agreement in November 2001 and completed wage and benefitsre-opener negotiations in October 2003. New wage and benefit rates went into effect in November 2003.  Of the KU total, approximately 158 operating,maintenance, and construction employees were represented by IBEW Local 2100 andUSWA Local 9447-01.  In August 2003,KU and employees represented by IBEW Local 2100 entered into a three-yearcollective bargaining agreement.  KU andemployees represented by USWA Local 9447-01 entered into a three-yearcollective bargaining agreement effective August 2002 and expiring August 2005.

 

LG&E Services provides certain services to affiliated entities,including LG&E and KU, at cost as required under PUHCA.  On February 28, 2005 approximately 965employees worked for LG&E Services.

 

**SeeNote 3 of LG&E’s Notes to Financial Statements and Note 3 of KU’s Notes toFinancial Statements under Item 8 for the workforce separation program ineffect for 2001.**

 

19

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**Executive Officers of LG&E and KU**at February 28, 2005:

 
| **Name**            | ** ** | **Age** | ** ** | **Position**                                                        | ** ** | **Effective Date of  Election to Present  Position** |
|---------------------|------------|---------|------------|---------------------------------------------------------------------|------------|------------------------------------------------------|
|                |       |    |       |                                                                |       |                                                 |
| Victor A. Staffieri |       | 49      |       | Chairman of the Board,  President and Chief  Executive Officer      |       | May 1, 2001                                          |
|                |       |    |       |                                                                |       |                                                 |
| John R. McCall      |       | 61      |       | Executive Vice President,  General Counsel and  Corporate Secretary |       | July 1, 1994                                    |
|                |       |    |       |                                                                |       |                                                 |
| S. Bradford Rives   |       | 46      |       | Chief Financial Officer                                             |       | September 15, 2003                              |
|                |       |    |       |                                                                |       |                                                 |
| Paul W. Thompson    |       | 48      |       | Senior Vice President -  Energy Services                            |       | June 7, 2000                                    |
|                |       |    |       |                                                                |       |                                                 |
| Chris Hermann       |       | 57      |       | Senior Vice President -  Energy Delivery                            |       | February 14, 2003                               |
|                |       |    |       |                                                                |       |                                                 |
| Wendy C. Welsh      |       | 51      |       | Senior Vice President -  Information Technology                     |       | December 11, 2000                               |
|                |       |    |       |                                                                |       |                                                 |
| Martyn Gallus       |       | 40      |       | Senior Vice President -  Energy Marketing                           |       | December 11, 2000                               |

 

Other Officers of LG&E and KU at February 28,2005:

 
| David A. Vogel      |   | 39     |   | Vice President - Retail  and Gas Storage Operations |   | March 1, 2003      |
|---------------------|--------|--------|--------|-----------------------------------------------------|--------|-------------------------|
|                |   |   |   |                                                |   |                    |
| Daniel K. Arbough   |   | 43     |   | Treasurer                                           |   | December 11, 2000  |
|                |   |   |   |                                                |   |                    |
| Michael S. Beer     |   | 46     |   | Vice President  Federal Regulation and Policy       |   | September 27, 2004 |
|                |   |   |   |                                                |   |                    |
| George R. Siemens   |   | 55     |   | Vice President - External  Affairs                  |   | January 11, 2001   |
|                |   |   |   |                                                |   |                    |
| Paula H. Pottinger  |   | 48     |   | Vice President -  Human Resources                   |   | June 1, 2002       |
|                |   |   |   |                                                |   |                    |
| D. Ralph Bowling    |   | 47     |   | Vice President -  Power Operations WKE              |   | August 1, 2002     |
|                |   |   |   |                                                |   |                    |
| R. W. Chip Keeling  |   | 48     |   | Vice President -  Communications                    |   | March 18, 2002     |
|                |   |   |   |                                                |   |                    |
| John N. Voyles, Jr. |   | 50     |   | Vice President -  Regulated Generation              |   | June 16, 2003      |
|                |   |   |   |                                                |   |                    |
| Valerie L. Scott    |   | 48     |   | Controller                                          |   | January 1, 2005    |

 

The present term of office of each of the above executive and otherofficers extends to the meeting of the Board of Directors following the 2005Annual Meeting of Shareholders.

 

20

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There are no family relationships between or among executive and otherofficers of LG&E and KU.  The abovetables indicate officers serving as executive officers of both LG&E and KUat February 28, 2005.  Each of theabove officers serves in the same capacity for LG&E and KU.

 

Before he was elected to his current positions, Mr. Staffieri was ChiefFinancial Officer of LG&E Energy 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 from March 1999to April 2001 (including President of LG&E and KU from June 2000to April 2001).

 

Mr. McCall has been Executive Vice President, General Counsel andCorporate Secretary of LG&E Energy and LG&E since July 1994.  He became Executive Vice President, GeneralCounsel and Corporate Secretary of KU in May 1998.

 

Before he was elected to his current positions, Mr. Rives was SeniorVice President - Finance and Business Development from February 1999 to December 2000and Senior Vice President - Finance and Controller of LG&E Energy, LG&Eand KU from December 2000 to September 2003.

 

Before he was elected to his current positions, Mr. Thompson was GroupVice President for LG&E Energy Marketing, Inc. from June 1998 to August 1999;Vice President, Retail Electric Business for LG&E from December 1998to August 1999; and Senior Vice President - Energy Services for LG&EEnergy from August 1999 to June 2000.

 

Before he was elected to his current positions, Mr. Hermann was VicePresident, Power Generation and Engineering Services, of LG&E from May 1998to December 1999; Vice President Supply Chain and Operating Services from December 1999to 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 VicePresident - Information Technology from February 1998 to December 2000.

 

Before he was elected to his current positions, Mr. Gallus was VicePresident, Energy Marketing from August 1998 to December 2000 forLG&E Energy.

 

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

 

In addition to being elected to his current positions, Mr. Arbough hasheld the positions of Director, Corporate Finance of LG&E Energy, LG&Eand KU from May 1998 to present.

 

Before he was elected to his current positions, Mr. Beer was SeniorCorporate Attorney from February 1998 to February 2000; SeniorCounsel Specialist, Regulatory from February 2000 to February 2001,and Vice President – Rates and Regulatory from February 2001 to September 2004.

 

Before he was elected to his current positions, Mr. Siemens held theposition of Director of External Affairs for LG&E Energy from August 1982to January 2001.

 

Before she was elected to her current positions, Ms. Pottinger wasManager, Human Resources Development

 

21

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from May 1994 to May 1997; and Director, Human Resources from June 1997to June 2002.

 

Before he was elected to his current positions, Mr. Bowling was PlantGeneral Manager at Western Kentucky Energy from July 1998 to December 2001;and General Manager Black Fossil Operations for Powergen in the United Kingdomfrom January 2002 to August 2002.

 

Before he was elected to his current positions, Mr. Keeling was GeneralManager, Marketing Communications for General Electric Company from January 1988to January 1999.  He joined LG&EEnergy and held the title Manager, Media Relations from January 1999 to February 2000;and Director, Corporate Communications for LG&E Energy from February 2000to March 2002.

 

Before he was elected to his current positions, Mr. Voyles was GeneralManager, Cane Run, Ohio Falls and Combustion Turbines, November 1998 to February 2003;and Director, Generation Services, February 2003 to June 2003.

 

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

 

22

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**ITEM 2.  Properties**.

 

LG&E’s power generating system consists of the coal-fired unitsoperated at its three steam generating stations.  Combustion turbines supplement the systemduring peak or emergency periods. LG&E owns and operates the following electric generating stationsunless otherwise stated:

 
| ** **                                           | ** ** | **Summer Capability  Rating (Kw)** | ** ** |
|------------------------------------------------------|------------|------------------------------------|------------|
| Steam  Stations:                                     |       |                               |       |
| Mill Creek -  Kosmosdale, KY                         |       |                               |       |
| Unit 1                                               |       | 303,000                            |       |
| Unit 2                                               |       | 301,000                            |       |
| Unit 3                                               |       | 391,000                            |       |
| Unit 4                                               |       | 477,000                            |       |
| Total Mill  Creek                                    |       | 1,472,000                          |       |
|                                                 |       |                               |       |
| Cane Run -  near Louisville, KY                      |       |                               |       |
| Unit 4                                               |       | 155,000                            |       |
| Unit 5                                               |       | 168,000                            |       |
| Unit 6                                               |       | 240,000                            |       |
| Total Cane  Run                                      |       | 563,000                            |       |
|                                                 |       |                               |       |
| Trimble  County - Bedford, KY (a)                    |       |                               |       |
| Unit 1                                               |       | 383,000                            |       |
|                                                 |       |                               |       |
| Combustion  Turbine Generators (Peaking capability): |       |                               |       |
| Zorn                                                 |       | 14,000                             |       |
| Paddy’s Run  (b)                                |       | 119,000                            |       |
| Cane Run                                             |       | 14,000                             |       |
| Waterside                                            |       | 22,000                             |       |
| E.W. Brown –  Burgin, KY (c)                    |       | 190,000                            |       |
| Trimble  County – Bedford, KY (d)               |       | 328,000                            |       |
| Total  combustion turbine generators                 |       | 687,000                            |       |
|                                                 |       |                               |       |
| Total  capability rating                             |       | 3,105,000                          |       |

 

----

(a)          Amount shown represents LG&E’s 75% interest in Trimble County1.  See Notes 11 and 12 of LG&E’sNotes to Financial Statements under Item 8 for further discussion on ownership.

(b)         Amount shown represents LG&E’s 53% interest in Paddy’s Run Unit 13and 100% ownership of Paddy’s Run Units 11 and 12.  See Notes 11 and 12 of LG&E’s Notes toFinancial Statement, under Item 8 for further discussion on ownership.

(c)          Amount shown represents LG&E’s 53% interest in Unit 5, 38% interestin Units 6 and 7 at E.W. Brown and 10% of the Inlet Air Cooling system,attributable to Brown Unit 5.  See Notes11 and 12 of LG&E’s Notes to Financial Statements, under Item 8 for furtherdiscussion on ownership.  KU operates theunits on behalf of LG&E.

(d)         Amount shown represents LG&E’s 29% interest in Units 5 and 6 and LG&E’s37% interest in Units 7, 8, 9 and 10 at Trimble County.  See Notes 11 and 12 of LG&E’s Notes toFinancial Statements, under Item 8 for further discussion on ownership.

 

LG&E also owns an 80 Mw nameplate-rated hydroelectric generatingstation located in Louisville (Ohio Falls), with an expected summer capabilityrating of 48 Mw, operated under a license issued by the FERC.

 

At December 31, 2004, LG&E’s electric transmission systemincluded 21 substations dedicated solely to transmission and an additional 20substations shared with the distribution system with a total capacity ofapproximately 11,878,000 Kva and approximately 670 structure miles oflines.  The electric distribution system

 

23

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included 93 substations (20 of which are shared by the transmissionsystem) with a total capacity of approximately 4,860,500 Kva, 3,923 structuremiles of overhead lines and 1,859 miles of underground conduit.

 

LG&E’s gas transmission system includes 255 miles of transmissionmains, and the gas distribution system includes 4,026 miles of distributionmains.

 

LG&E operates underground gas storage facilities with a currentworking gas capacity of approximately****15.1****million Mcf.** **See Gas Supply under Item 1.

 

In 1990, LG&E entered into an operating lease for its corporateoffice building located in downtown Louisville, Kentucky.  The lease was renegotiated in 2002 and isscheduled to expire July 31, 2015.

 

Other properties owned by LG&E include office buildings, servicecenters, warehouses, garages, and other structures and equipment, the use ofwhich is common to both the electric and gas departments.

 

The trust indenture securing LG&E’s first mortgage bondsconstitutes a direct first mortgage lien upon much of the property owned byLG&E.  In addition, FideliaCorporation, a financing subsidiary of E.ON, has a second lien on the propertysubject to the first mortgage bond lien. The second lien secures loans provided by Fidelia.

 

KU’s power generating system consists of the coal-fired units operatedat its four steam generating stations. Combustion turbines supplement the system during peak or emergencyperiods.  KU owns and operates thefollowing electric generating stations unless otherwise stated:

 
| ** **                                           | ** ** | **Summer Capability  Rating (Kw)** | ** ** |
|------------------------------------------------------|------------|------------------------------------|------------|
| Steam  Stations:                                     |       |                               |       |
| Tyrone -  Tyrone, KY                                 |       |                               |       |
| Unit 1                                               |       | 27,000                             |       |
| Unit 2                                               |       | 31,000                             |       |
| Unit 3                                               |       | 71,000                             |       |
| Total Tyrone                                         |       | 129,000                            |       |
|                                                 |       |                               |       |
| Green River  – South Carrollton, KY             |       |                               |       |
| Unit 3                                               |       | 68,000                             |       |
| Unit 4                                               |       | 95,000                             |       |
| Total Green  River                                   |       | 163,000                            |       |
|                                                 |       |                               |       |
| E.W. Brown –  Burgin, KY                        |       |                               |       |
| Unit 1                                               |       | 101,000                            |       |
| Unit 2                                               |       | 167,000                            |       |
| Unit 3                                               |       | 429,000                            |       |
| Total E.W.  Brown                                    |       | 697,000                            |       |
|                                                 |       |                               |       |
| Ghent –  Ghent, KY                              |       |                               |       |
| Unit 1                                               |       | 475,000                            |       |
| Unit 2                                               |       | 484,000                            |       |
| Unit 3                                               |       | 493,000                            |       |
| Unit 4                                               |       | 493,000                            |       |
| Total Ghent                                          |       | 1,945,000                          |       |
|                                                 |       |                               |       |
| Combustion  Turbine Generators (Peaking capability): |       |                               |       |
| E.W. Brown –  Burgin, KY (Units 5-11) (a)       |       | 757,000                            |       |
| Haefling –  Lexington, KY                       |       | 36,000                             |       |
| Paddy’s Run  – Louisville, KY (b)          |       | 74,000                             |       |
| Trimble  County – Bedford, KY (c)               |       | 632,000                            |       |
|                                                 |       |                               |       |
| Total  combustion turbine generators                 |       | 1,499,000                          |       |
|                                                 |       |                               |       |
| Total  capability rating                             |       | 4,433,000                          |       |

 

24

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----

(a)          Amount shown represents KU’s 47% interestin Unit 5, 62% interest in Units 6 and 7, 100% of units 8-11 at E.W. Brown and90% of the Inlet Air Coolingsystem, attributable to E.W. Brown CT Unit 5 and Units 8 to 11. See Notes 11 and 12 of KU’s Notes to Financial Statements, under Item 8for further discussion on ownership.

(b)         Amount shown represents KU’s 47% interestin Unit 13 at Paddy’s Run.  See Notes 11and 12 of KU’s Notes to Financial Statements, under Item 8 for furtherdiscussion on ownership.  LG&Eoperates this unit on behalf of KU.

(c)          Amount shown represents KU’s 71% interestin Units 5 and 6 and KU’s 63% interest in Units 7, 8, 9 and 10 at TrimbleCounty.  See Notes 11 and 12 of KU’sNotes to Financial Statements, under Item 8 for further discussion onownership.  LG&E operates these unitson behalf of KU.

 

KU also owns a 28 Mw nameplate-rated hydroelectric generating stationlocated in Burgin, Kentucky (Dix Dam), with an expected summer capabilityrating of 24 Mw, operated under a license issued by the FERC.

 

At December 31, 2004, KU’s electric transmission system included108 substations with a total capacity of approximately 16,978,000 Kva andapproximately 4,239 structure miles of lines. The electric distribution system included 491 substations with a totalcapacity of approximately 6,220,400 Kva and 15,182 structure miles of lines.

 

Other properties owned by KU include office buildings, service centers,warehouses, garages, and other structures and equipment.

 

The trust indenture securing KU’s first mortgage bonds constitutes adirect first mortgage lien upon much of the property owned by KU.  In addition, Fidelia has a second lien on theproperty subject to the first mortgage bond lien.  The second lien secures loans provided byFidelia.

 

# **ITEM 3.  Legal Proceedings**.

# ** **

Rates andRegulatory Matters

 

For adiscussion of current rate and regulatory matters, including electric and gasbase rate increase proceedings, the Kentucky attorney general investigation,ESM proceedings, FERC or MISO proceedings, and other rate or regulatory mattersaffecting LG&E and KU, see Rates and Regulation for LG&E and KU underItem 1 and Item 7, and Note 3 of LG&E’s Notes to Financial Statements andNote 3 of KU’s Notes to Financial Statements under Item 8.

 

Environmental

 

For adiscussion of environmental matters including currently proposed reductions inSO2 and NOx emission limits; items regarding LG&E’s Mill Creekgenerating plant, KU’s E.W. Brown plant and LG&E’s and KU’s manufacturedgas plant sites; and other environmental items affecting LG&E and KU, seeExecutive Summary  (EnvironmentalPressures) and Rates and Regulations for LG&E and KU (EnvironmentalMatters) under Item 7 and Note 11 of LG&E’s Notes to Financial Statementsand Note 11 of KU’s Notes to Financial Statements under Item 8, respectively.

 

25

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LG&EEmployment Discrimination Case

 

In October 2001,approximately 30 employees or former employees filed a complaint againstLG&E claiming past and current instances of employment discriminationagainst LG&E.  LG&E has removedthe case to the U.S. District Court for the Western District of Kentucky andfiled an answer denying all plaintiffs’ claims. The U.S. Equal Employment Opportunity Commission has declined to proceedto litigation on any claims reviewed.  Throughcontinuing mediation, settlements have been reached with the majority ofplaintiffs, including the lead plaintiff. Negotiations continue with eight plaintiffs.  The complaint contains a claimed damageamount of $100 million as well as requests for injunctive relief.  Prior settlements have been for non-materialamounts and LG&E does not anticipate that the remaining outcome will have amaterial impact on its operations or financial condition.

 

OwensboroContract Litigation

 

In May 2004,the City of Owensboro, Kentucky and Owensboro Municipal Utilities (collectively“OMU”), filed suit in Davies County, Kentucky District Court against KUconcerning a long-term power supply contract (the “OMU Agreement”) with KU.  The dispute involves interpretationaldifferences regarding certain issues under the OMU Agreement, including variouspayments or charges between KU and OMU and rights concerning excess power,termination and emissions allowances, respectively.  The complaint seeks approximately $6 millionin damages for historical periods, as well as injunctive and other relief,including a declaration that KU is in material breach.  KU has removed this litigation to the U.S.District Court for the Western District of Kentucky, filed an answer in thatcourt denying the OMU claims and presenting certain counterclaims and commenceda FERC proceeding to request FERC jurisdiction on certain issues.  In October 2004, FERC declined toexercise exclusive jurisdiction regarding the issues in dispute, which rulingKU has appealed.  In December 2004,KU filed in federal court for summary judgment on certain issues.

 

OVEC PowerAgreement and Share Purchase

 

On April 30,2004, OVEC and its shareholders, including LG&E and KU, entered into anAmended and Restated Inter-Company Power Agreement, to be effective beginning March 2006,upon the expiration of the current power contract among the parties.  Under the new contract, which has a 20-yearterm from its effective date, LG&E and KU have purchase rights for 5.63%and 2.5%, respectively, of OVEC power at marginal cost-based rates.  LG&E and KU are entitled to 7% and 2.5%of OVEC power, respectively, under the current contract.  In addition, LG&E has purchased from AEPan additional 0.73% interest in OVEC for a purchase price of approximately $0.1million, resulting in an increase in LG&E ownership in OVEC from 4.9% to5.63%.  The parties received SEC approvalunder PUHCA of the Amended and Restated Inter-Company Power Agreement during February 2005and completed the share purchase transaction during March 2005.

 

Other

 

In the normalcourse of business, other lawsuits, claims, environmental actions, and othergovernmental proceedings arise against LG&E and KU.  To the extent that damages are assessed inany of these lawsuits, LG&E and KU believe that their insurance coverage isadequate.  Management, after consultationwith legal counsel, does not anticipate that liabilities arising out of othercurrently pending or threatened lawsuits and claims will have a materialadverse effect on LG&E’s or KU’s consolidated financial position or resultsof operations, respectively.

 

26

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ITEM 4.  Submission of Matters toa Vote of Security Holders.

 

None.

 

PART II.

 

**ITEM 5****.  Market for the Registrant’s Common Equity,Related Stockholder Matters** and Issuer Purchases of EquitySecurities.

 

LG&E:

All LG&E common stock, 21,294,223 shares, is held by LG&EEnergy.  Therefore, there is no publicmarket for LG&E’s common stock.

 

The following table sets forth LG&E’s cash distributions on commonstock paid to LG&E Energy during 2004.

 
| **(in thousands)** | ** ** | ** ** | ** ** |
|--------------------|------------|------------|------------|
| First  quarter     |       | $          | —     |   |
| Second  quarter    |       | 21,000     |       |
| Third  quarter     |       | 21,000     |       |
| Fourth  quarter    |       | 15,000     |       |
|                    |            |            |            |  |

 

LG&E had no cash distributions on common stock paid to LG&EEnergy in 2003. In 2002, LG&E paid $69 million in cash distribution on commonstock to LG&E Energy. 

 

KU:

All KU common stock, 37,817,878 shares, is held by LG&EEnergy.  Therefore, there is no publicmarket for KU’s common stock.

 

The following table sets forth KU’s cash distributions on common stockpaid to LG&E Energy during 2004.

 
| **(in thousands)** | ** ** | ** ** | ** ** |
|--------------------|------------|------------|------------|
| First  quarter     |       | $          | —     |   |
| Second  quarter    |       | 21,000     |       |
| Third  quarter     |       | 21,000     |       |
| Fourth  quarter    |       | 21,000     |       |
|                    |            |            |            |  |

 

KU paid no cash distributions on common stock to LG&E Energy in2003 or 2002.

 

27

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# **ITEM6.  Selected Financial Data**.

# ** **

The 2000 consolidated financial data werederived from financial statements audited by Arthur Andersen LLP, independentaccountants, who expressed an unqualified opinion on those financial statementsin their report dated January 26, 2001, before the revisions required byEITF 02-03 and the reclassification of income taxes.  Arthur Andersen LLP has ceasedoperations.  The amounts shown below forsuch period, reclassified pursuant to the adoption of EITF 02-03 and reclassifieddue to the change in presentation of income taxes, are unaudited.

 
| ** **                                                     | ** ** | **Years Ended December 31** | ** ** |
|----------------------------------------------------------------|------------|----------------------------------|------------|
| **(in thousands)**                                             | ** ** | **2004**                         | ** ** | **2003** | ** ** | **2002** | ** ** | **2001** | ** ** | **2000** | ** ** |
| LG&E:                                                      |       |                             |       |   |   |   |   |   |   |   |   |
| Operating  revenues                                            |       | $                                | 1,172,768  |   | $ | 1,093,521 |   | $ | 1,003,735 |   | $ | 964,547 |   | $ | 931,704 |   |
|                                                           |       |                             |       |   |   |   |   |   |   |   |   |
| Net  operating income                                          |       | $                                | 185,031    |   | $ | 178,752 |   | $ | 172,949 |   | $ | 205,225 |   | $ | 213,295 |   |
|                                                           |       |                             |       |   |   |   |   |   |   |   |   |
| Net income                                                     |       | $                                | 95,618     |   | $ | 90,839 |   | $ | 88,929 |   | $ | 106,781 |   | $ | 110,573 |   |
|                                                           |       |                             |       |   |   |   |   |   |   |   |   |
| Total assets                                                   |       | $                                | 2,966,552  |   | $ | 2,882,082 |   | $ | 2,768,930 |   | $ | 2,448,354 |   | $ | 2,226,084 |   |
|                                                           |       |                             |       |   |   |   |   |   |   |   |   |
| Long-term  obligations (including amounts due within one year) |       | $                                | 871,804    |   | $ | 798,054 |   | $ | 616,904 |   | $ | 616,904 |   | $ | 606,800 |   |
|                                                           |       |                             |       |   |   |   |   |   |   |   |   |
| Dividends  declared per common share                           |       | $                                | 2.68       |   | $ | — |   | $ | 3.24 |   | $ | 1.08 |   | $ | 2.35 |   |

 

LG&E’sManagement’s Discussion and Analysis of Financial Condition and Resultsof Operation and LG&E’s Notes to Financial Statements should be read inconjunction with the above information.

 
| ** **                                                     | ** ** | **Years Ended December 31** | ** ** |
|----------------------------------------------------------------|------------|----------------------------------|------------|
| **(in thousands)**                                             | ** ** | **2004**                         | ** ** | **2003** | ** ** | **2002** | ** ** | **2001** | ** ** | **2000** | ** ** |
| KU:                                                            |       |                             |       |   |   |   |   |   |   |   |   |
| Operating  revenues                                            |       | $                                | 995,362    |   | $ | 891,778 |   | $ | 861,664 |   | $ | 820,721 |   | $ | 793,409 |   |
|                                                           |       |                             |       |   |   |   |   |   |   |   |   |
| Net  operating income                                          |       | $                                | 227,847    |   | $ | 162,210 |   | $ | 162,675 |   | $ | 178,852 |   | $ | 180,099 |   |
|                                                           |       |                             |       |   |   |   |   |   |   |   |   |
| Net income                                                     |       | $                                | 133,471    |   | $ | 91,402 |   | $ | 93,384 |   | $ | 96,414 |   | $ | 95,524 |   |
|                                                           |       |                             |       |   |   |   |   |   |   |   |   |
| Total assets                                                   |       | $                                | 2,610,439  |   | $ | 2,505,094 |   | $ | 2,251,638 |   | $ | 1,826,902 |   | $ | 1,739,518 |   |
|                                                           |       |                             |       |   |   |   |   |   |   |   |   |
| Long-term  obligations (including amounts due within one year) |       | $                                | 726,211    |   | $ | 687,576 |   | $ | 500,492 |   | $ | 488,506 |   | $ | 484,830 |   |
|                                                           |       |                             |       |   |   |   |   |   |   |   |   |
| Dividends  declared per common share                           |       | $                                | 1.67       |   | $ | — |   | $ | — |   | $ | 0.81 |   | $ | 2.00 |   |

 

KU’s Management’s Discussion and Analysis ofFinancial Condition and Results of Operation and KU’s Notes to FinancialStatements should be read in conjunction with the above information.

 

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**ITEM 7.  Management’s Discussionand Analysis of Financial Condition and Results of Operations**.

 

GENERAL

 

The following discussion and analysis by management focuses on thosefactors that had a material effect on LG&E and KU’s financial results ofoperations and financial condition during 2004, 2003, and 2002 and should beread in connection with the financial statements and notes thereto.

 

Some of the following discussion may contain forward-looking statementsthat are subject to certain risks, uncertainties and assumptions.  Such forward-looking statements are intendedto 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 tomaterially differ include: general economic conditions; business and competitiveconditions in the energy industry; changes in federal or state legislation;unusual weather; actions by state or federal regulatory agencies; actions bycredit rating agencies; and other factors described from time to time inLG&E’s and KU’s reports to the SEC, including Exhibit No. 99.01 to thisreport on Form 10-K.

 

EXECUTIVE SUMMARY

 

Our Business

 

LG&E and KUare each subsidiaries of LG&E Energy LLC, which is an indirect subsidiary of E.ON, a Germancompany.  LG&E and KU maintainseparate corporate identities and serve customers in Kentucky, Virginia andTennessee under their respective names.

 

LG&E, incorporated in 1913 in Kentucky, is a regulated publicutility that supplies natural gas to approximately 318,000 customers andelectricity to approximately 390,000 customers in Louisville and adjacent areasin Kentucky.  LG&E’s service areacovers approximately 700 square miles in 17 counties and has an estimatedpopulation of one million.  LG&E alsoprovides gas service in limited additional areas.  LG&E’s coal-fired electric generatingplants, all equipped with systems to reduce sulfur dioxide emissions, producemost of LG&E’s electricity.  Theremainder is generated by a hydroelectric power plant and combustionturbines.  Underground natural gasstorage fields help LG&E provide economical and reliable gas service tocustomers.

 

KU, incorporated in Kentucky in 1912 and incorporated in Virginia in1991, is a regulated public utility engaged in producing, transmitting andselling electric energy.  KU provideselectric service to approximately 488,000 customers in over 600 communities andadjacent suburban and rural areas in 77 counties in central, southeastern andwestern Kentucky, to approximately 30,000 customers in 5****countiesin southwestern Virginia and to less than 10 customers in Tennessee.  In Virginia, KU operates under the name OldDominion Power Company.  KU also sellswholesale electric energy to 12 municipalities.

 

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Our Customers

 

The following table provides statistics regarding LG&E and KUretail customers:

 
| ** **                  | ** ** | **LG&E** | ** ** | **KU**   | ** ** | **2004 % Retail Revenues** | ** ** |
|-----------------------------|------------|--------------|------------|----------|------------|----------------------------|------------|
| **Customers  (000s)**       | ** ** | **Electric** | ** ** | **Gas**  | ** ** | **Electric**               | ** ** | **LG&E** | ** ** | **KU** | ** ** |
| ** **                  | ** ** | **2004**     | ** ** | **2003** | ** ** | **2004**                   | ** ** | **2003** | ** ** | **2004** | ** ** | **2003** | ** ** | **Electric** | ** ** | **Gas** | ** ** | **Electric** | ** ** |
| Retail Customer Data        |       |         |       |     |       |                       |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Residential                 |       | 343          |       | 337      |       | 293                        |       | 287 |   | 426 |   | 421 |   | 39 | % | 65 | % | 38 | % |
| Industrial & Commercial |       | 41           |       | 41       |       | 24                         |       | 24 |   | 82 |   | 82 |   | 51 | % | 30 | % | 53 | % |
| Other                       |       | 6            |       | 6        |       | 1                          |       | 1 |   | 10 |   | 9 |   | 10 | % | 5 | % | 9 | % |
| Total Retail                |       | 390          |       | 384      |       | 318                        |       | 312 |   | 518 |   | 512 |   | 100 | % | 100 | % | 100 | % |

 

Our Mission

 

The mission of LG&E and KU is to build on our tradition and achieveworld-class status providing reliable, low-cost energy services and superiorcustomer satisfaction; and to promote safety, financial success and quality oflife for our employees, communities and other stakeholders.

 

Our Strategy

 

LG&E and KU’s strategy focuses on the following:

 

•                  Execute all ourbusiness processes to secure a world-class competitive advantage

•                  Develop and transferbest practices in generation, customer service, distribution and supply

•                  Operate ourcommercial hub to enhance margins and manage risks across the company

•                  Pursue flexibleasset portfolio management

•                  Attract, retainand develop the best people

 

Low Rates

 

LG&E and KU believe they are well positioned in the regulatedKentucky market. LG&E and KU continue to sustain high customersatisfaction, ranking top amongst large electric utilities in the Midwest forthe 5th time in six years in the J.D. Power and Associates 2004survey of residential electric customers. This excellent performance is balanced with cost control.  The customer benefits of the LG&E and KUculture of cost management are evident in rate comparisons among U.S.utilities.  The following chart comparesthe total residential average rates per thousand Kwh of U.S. investor-ownedutilities as of July 1, 2004:

 

 

Source: Edison Electric Institute, Summer 2004 Typical Bills andAverage Rates Report; Residential rates in effect July 1, 2004, basedon 1,000 Kwh monthly usage.

 

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Thecompany must continue to address new cost pressures. The Kentucky Commissionaccepted the settlement agreements reached by the majority of the parties inthe rate cases filed by LG&E and KU in December 2003.  New rates, implemented in July 2004, produce$55.3 million of revenue for LG&E and $46.1 million of revenue for KU for afull year.  Under the ruling, theLG&E utility base electric rates have increased $43.4 million (7.7%) andbase gas rates have increased $11.9 million (3.4%), on an annual basis.  Base electric rates at KU have increased$46.1 million (6.8%) annually.  The 2004increases were the first increases in electric base rates for LG&E and KUin 13 and 20 years, respectively; the last gas rate increase for the LG&Egas utility took effect in September 2000. Competitors also face these samecost pressures that caused LG&E and KU to initiate rate cases (e.g.pensions, benefits, and reliability expenditures) and many other utilitycompanies already have rate cases in process.  Despite these increases, LG&E and KUrates remain significantly lower than the national average.

 

### CommodityPrices: Fuel and Electricity

 

Wholesale natural gas prices stayed aroundthe $6/MMBtu level during summer 2004. The U.S. supply-demand imbalance problem has continued, with U.S.reserves in decline and gas demand for electric generation continuing toincrease.

 

Coal prices, which moderated after increasesin 2001-2002, rose in late 2003 and maintained strength during 2004.  Coal production in the U.S. has not kept pacewith demand, and mining companies are exercising market discipline in theirproduction decisions.  Lower sulfurCentral Appalachian coal led the price increases.  Prices for Powder River Basin (“PRB”) lowsulfur coal from the western U.S. have risen much less than eastern coals,largely due to transportation constraints between the mines and eastern markets.  However, LG&E and KU generation plantsare limited in the amount of PRB coal that can be burned.

 

The graph displays theLG&E, KU and combined utility average utility gas and coal purchase prices.

 

 

Actualgas costs are recovered from customers through the GSC.  The GSC also contains an incentive component,the PBR component, which is determined for each 12-month period ending October31.

 

Actualfuel costs associated with retail electric sales are recovered from customersthrough the FAC.  The Utilities’ baserates contain an embedded fuel cost component. The FAC reconciles the difference between this fuel cost component andthe actual fuel cost, including transportation costs.  Refunds to customers occur if the actualcosts are below the embedded cost component. Additional charges to customers occur if the actual costs exceed theembedded cost component.

 

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Withrespect to wholesale electricity prices, generation overcapacity in the Midwestis forecasted to persist, with reserve margins still topping 25% for ECAR in2005. However, the overcapacity resulted largely from the construction ofhigh-cost simple cycle gas-fired units. Therefore, high gas prices have supported higher wholesale electricityprices, advantaging coal-fired generation. While the regional reserve margin is expected to decline over time asnew capacity construction slows and demand grows, gas-fired generation isexpected to set prices, particularly during times of higher loads. Thisexpectation, combined with the expectation that gas prices will remain high,indicates that on-peak electricity prices are expected to remain high.

 

GenerationReliability

 

Generationreliability also remains a key aspect to meeting our strategy. LG&E and KUbelieve that they have maintained good performance and reliability in the keyarea of utility generation operation. While maintaining low cost levels, LG&E and KU have also been ableto generate increasing volumes and expect to continue high levels ofavailability and low outage levels. This performance is also important tomaintaining margins from off-system sales.

 

GenerationCapacity

 

Withthe recent installation of four combustion turbines at Trimble County,near-term regulated load growth in Kentucky is expected to be satisfied. Theinstallation of Trimble County Units 7-10 increased total system capability by9%. However, the IRP submitted by LG&E and KU to the Kentucky Commission in2002, outlining the least cost alternative to meet Kentucky’s needs, indicatedthe requirement for additional base-load capacity in the longer-term.   Consequently, LG&E and KU have begundevelopment efforts for another base-load coal-fired unit at the Trimble Countysite. LG&E and KU believe this is the least cost alternative to meet thefuture needs of customers.  Trimble CountyUnit 2, with a 732 MW capacity rating, is expected to be jointly owned byLG&E and KU (75% owners of the unit) and IMEA and IMPA (25% owners).   An application for a construction CCN wasfiled with the Kentucky Commission in December 2004, and the proposed airpermit was filed with the Kentucky Department of Air Quality in December2004.  LG&E’s and KU’s share of thetotal capital cost of $885 million for Trimble County Unit 2 is estimated to be$168 million and $717 million, respectively, through 2010.

 

Environmental Pressures

 

In addition to the Trimble County Unit 2 project, the second majorutility investment area is environmental expenditures.  The need for additional FGD units iscontinuously assessed based on the expected changes in SO2allowance prices, coal cost, and environmental legislation.  The analysis supports building additional FGDunits to mitigate the declining SO2 allowance bank at KU over the next several years.  The LG&E utility fleet is fullyscrubbed.  SO2 allowance prices have risen significantly and, coupledwith the high price of low sulfur coal, indicate the need for FGDs on three ofKU’s Ghent units and at E.W. Brown.  InDecember 2004, KU filed with the Kentucky Commission an application for a CCNto construct four FGDs; a decision is expected by late June 2005.

 

LG&E and KU completed the NOx SCRprojects before the May 2004 deadline. Expenditures on NOx investments, totaling approximately $186 million atLG&E and $219 million at KU, are being recovered currently through thecompanies’ ECR mechanism (see “Rates and Regulation”).

 

Additional environmentalregulations are probable in the areas of New Source Review (a preconstructionpermitting program established as part of the Clean Air Act), mercury and CO2.The mercury standard will most likely be achieved through the operation ofconventional air pollution control equipment (FGDs). The

 

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Companies believe that CO2regulation is a longer-term issue as there is no current nationwide consensusto adopt Kyoto-like restrictions.

 

Kentucky law permits LG&E and KU to recover the costs of complyingwith the Federal Clean Air Act, including a return of operating expenses, and areturn of and on capital invested, through the ECR mechanism. The mechanismpermits LG&E and KU to earn a reasonable return on these capitalinvestments outside of base rates. Related operation and maintenance expenses are also recoverable.  Approximately 80% of the applicableenvironmental costs, including investment and operating costs, are recoverablethrough ECR. The remaining 20%, attributable to off-system andFERC-jurisdictional sales, are not recoverable through the ECR, but can beincluded in the determination of base rate cases.

 

Weather

 

The utility business is affected by various weather patterns.  Seasonal weather patterns can cause extremevariability in load due to higher or lower temperatures than normal.  The Companies maintain generation reservemargins and natural gas storage fields to accommodate higher than normalloads.  Lower than normal loads canimpact the profitability of the Companies due to lower revenues.  A WNA mechanism, effective November throughApril, adjusts for the over- and under-recovery of costs associated withnatural gas in periods of abnormal winter usage.

 

Severe snow and ice storms, thunderstorms, tornadoes and flooding canresult in extensive damage to the infrastructure of the Companies’ transmissionand distribution systems.  The Companiesmaintain a comprehensive storm management plan for efficient and timelyrestoration of service to customers after major storm events.

 

Business Disruption Risks

 

LG&E and KU face certain operational risks common to the electricand gas utility industries, as applicable. These include, without limitation, the risk of disruptions or outagesrelating to major operating or delivery facilities, such as generating units,transmission or distribution assets and information technology or dataprocessing components, whether due to terrorist or other attack, civil unrestor labor action, break-down or mechanical failure, severe weather or other actsof God.

 

While LG&E and KU believe they have appropriate prevention ormitigation measures in place, where possible, with respect to these potentialbusiness disruptions, no assurances can be given that such events will notoccur in the future or will not negatively affect the Companies’ financialcondition or results of operations.

 

MERGERS AND ACQUISITIONS

 

LG&E and KU are each subsidiaries of LG&E Energy.  On December 11, 2000, LG&E EnergyCorp., now LG&E Energy LLC, was acquired by Powergen plc, now known asPowergen Limited, for cash of approximately $3.2 billion and the assumption ofall of LG&E Energy’s debt.  As aresult of the acquisition, LG&E Energy became a wholly owned subsidiary ofPowergen and, as a result, LG&E and KU became indirect subsidiaries ofPowergen.

 

On July 1, 2002, E.ON, aGerman company, completed its acquisition of Powergen plc (now PowergenLimited).  As a result, LG&E and KU became indirect subsidiaries ofE.ON.  E.ON had announced itspre-conditional cash offer of £5.1 billion ($7.3 billion) for Powergen on April9, 2001.

 

Ascontemplated in their regulatory filings in connection with the E.ONacquisition, E.ON, Powergen and LG&E Energy completed an administrativereorganization to move the LG&E Energy group from an indirect Powergensubsidiary to an indirect E.ON subsidiary.  This reorganization was effective in March 2003.  In early 2004, LG&E Energy began directreporting arrangements to E.ON.

 

The utility operations of LG&E Energy have continued their separateidentities as LG&E and KU.  Thepreferred stock and debt securities of LG&E and KU were not affected bythese transactions.

 

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

 

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RESULTS OF OPERATIONS

 

LG&E

 

Net Income

 

LG&E’s net income in 2004 increased $4.8million (5.3%) compared to 2003.  Theincrease resulted primarily from higher electric revenues due to increased baserates implemented for service rendered on and after July 1, 2004, following theelectric rate case order and higher wholesale revenues, somewhat offset byhigher maintenance expenses related to storm restoration costs.  Operating expenses for 2004 reflect $12.7million in expenses related to severe May and July storms.

 

LG&E’s net income in 2004 related to theelectric business increased $6.6 million (8.2%) compared to 2003.  Electric operating revenues increased $47.5million (6.2%), offset by higher fuel for electric generation and powerpurchased of $22.6 million (8.2%).  Otherelectric operations and maintenance expenses increased $11.1 million(4.9%).  Electric depreciation expenseincreased $3.5 million (3.6%).  Interestexpense increased $1.6 million (6.3%).

 

LG&E’s net income in 2004 related to the gasbusiness decreased $1.9 million (18.2%) compared to 2003.  Gas operating revenues increased $31.7million (9.8%) offset by higher gas supply expenses of $32.4 million(13.9%).  Other gas operations andmaintenance expenses increased $2.0 million (4.2%).

 

LG&E’s net income in 2003 increased $1.9million (2.1%) as compared to 2002.  The increaseresulted primarily from increased electric sales.

 

LG&E’s net income in 2003 related to theelectric business increased $1.4 million (1.8%) compared to 2002.  Electric operating revenues increased $32.1million (4.4%), offset by higher fuel for electric generation and powerpurchased of $19.8 million (7.8%).  Otherelectric operations expense increased $2.2 million (1.3%).  Electric depreciation expense increased $6.2million (7.0%).  Other income decreased$1.6 million (126.6%) and interest expense increased $0.9 million (3.5%).

 

LG&E’s net income in 2003related to the gas business increased $0.5 million (5.7%) compared to2002.  Gas operating revenues increased$57.6 million (21.6%) offset by higher gas supply expenses of $51.5 million(28.3%).  Other gas operations expenseincreased $3.1 million (8.4%) and maintenance expense increased $0.3 million(4.4%).  Gas depreciation increased $1.1million (7.3%).  Other income decreased$0.5 million (112.4%).

 

Revenues

 

The following table presents a comparison ofoperating revenues for the years 2004 and 2003 with the immediately precedingyear.

 

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| ** **                               | ** ** | **Increase (Decrease) From Prior Period** | ** ** |
|------------------------------------------|------------|-------------------------------------------|------------|
| **(in thousands)**                       | ** ** | **Electric Revenues**                     | ** ** | **Gas Revenues** | ** ** |
| **Cause**                                | ** ** | **2004**                                  | ** ** | **2003** | ** ** | **2004** | ** ** | **2003** | ** ** |
| Retail sales:                            |       |                                      |       |   |   |   |   |   |   |
| Fuel and gas supply adjustments          |       | $                                         | 1,093      |   | $ | 6,620 |   | $ | 33,546 |   | $ | 50,972 |   |
| LG&E/KU Merger surcredit             |       | (2,329                                    | )          | (2,288 | ) | — |   | — |   |
| Environmental cost recovery surcharge    |       | 12,747                                    |       | (269 | ) | — |   | — |   |
| Earnings sharing mechanism               |       | 4,489                                     |       | 9,768 |   | — |   | — |   |
| Demand side management                   |       | 403                                       |       | 1,362 |   | (555 | ) | 267 |   |
| VDT surcredit                            |       | (1,140                                    | )          | (3,394 | ) | 87 |   | (1,283 | ) |
| Weather normalization                    |       | —                                    |       | — |   | 3,188 |   | (506 | ) |
| Rate changes                             |       | 16,824                                    |       | — |   | 6,947 |   | — |   |
| Variation in sales volumes and other     |       | 11,809                                    |       | (18,451 | ) | (5,773 | ) | 12,070 |   |
| Provision for Rate Collections (Refunds) |       | (11,006                                   | )          | (12,067 | ) | — |   | — |   |
| Total retail sales                       |       | 32,890                                    |       | (18,719 | ) | 37,440 |   | 61,520 |   |
| Wholesale                                |       | 15,781                                    |       | 49,230 |   | (5,083 | ) | (4,106 | ) |
| Gas transportation-net                   |       | —                                    |       | — |   | 95 |   | (186 | ) |
| Other                                    |       | (1,162                                    | )          | 1,635 |   | (714 | ) | 412 |   |
| Total                                    |       | $                                         | 47,509     |   | $ | 32,146 |   | $ | 31,738 |   | $ | 57,640 |   |

 

Electric revenues increased in 2004 primarily due to new ratesimplemented in July 2004. Retail revenues increased 2.0% due to higher salesvolume, primarily due to warmer summer weather than 2003.  Cooling degree days increased 21% compared to2003 and were 2% higher than the 20-year average.  Electric revenues increased in 2003 primarilydue to an increase in wholesale sales due to both higher market prices andhigher sales volume as compared to 2002. Retail revenues decreased due to 2.6% lower sales volume, primarily inthe residential sector due to milder summer weather than 2002.  Cooling degree days decreased 33% compared to2002 and were 14% below the 20-year average.

 

Gas revenues in 2004increased due to higher gas supply cost billed to customers through the gassupply clause and increased gas rates. New gas rates took effect in July 2004increasing revenues by 2.3% in 2004. These increases were partially offset bylower retail sales due to warmer winter weather and lower wholesale sales.  Heating degree days decreased 8% as comparedto 2003 and were 8% lower than the 20-year average. Gas revenues in 2003increased compared to 2002, due to higher gas supply cost billed to customersthrough the gas supply clause and increased gas retail sales due to coolerwinter weather, offset by lower off-system gas sales.  Heating degree days increased 5% as comparedto 2002 and were the same as the 20-year average.

 

The decrease in the provisionfor rate collections (refunds) in 2004 from 2003 ($11.0 million) resultsprimarily from a decrease in the ESM accrual ($12.7 million) and a decrease in2004 ECR accruals ($5.4 million), partially offset by an increase in fuel accruals($7.1 million). The decrease in the provision for rate collections (refunds) in2003 from 2002 ($12.1 million) results primarily from ESM revenues billed tocustomers during 2003 ($10.0 million), a decrease in the ESM accrual ($2.4million) and a decrease in fuel accruals ($2.6 million), partially offset by anincrease in ECR accruals ($2.9 million).

 

Expenses

 

Fuel for electric generation and gas supply expenses comprise a largecomponent of LG&E’s total operating costs. The retail electric rates containa FAC and gas rates contain a GSC, whereby increases or decreases in the costof fuel and gas supply are reflected in the FAC and GSC factors, subject toapproval by the Kentucky Commission, and passed through to LG&E’s retailcustomers.

 

Fuel for electric generation increased $10.1 million (5.1%) in 2004 dueto increased generation ($3.7 million) and higher cost of fuel burned ($6.4million).   Fuel for electric generationincreased $2.1 million (1.1%) in

 

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2003 due to increased generation ($5.8 million) offset by lower cost offuel burned ($3.7 million), primarily due to greater percentage of steamgeneration vs. combustion turbine generation in 2003.  The average delivered cost per MMBtu of coalpurchased was $1.15 in 2004, $1.12 in 2003 and $1.11 in 2002.

 

Power purchased increased $12.4 million (15.6%) in 2004 due to a 4%increase in purchases to meet off-system sales requirements ($3.4 million), andan 11% higher unit cost of purchases ($9.0 million).   Power purchased expenses increased $17.7million (28.7%) in 2003 due to an increase in purchases to meet off-systemsales requirements ($9.0 million), and a 12% higher unit cost of purchases($8.7 million).

 

Gas supply expenses increased $32.4 million (13.9%) in 2004 due to anincrease in cost of net gas supply ($52.2 million) offset by a decrease in thevolume of gas delivered to the distribution system ($19.8 million). Gas supplyexpenses increased $51.5 million (28.3%) in 2003 due to an increase in cost ofnet gas supply ($50.2 million) and an increase in the volume of gas deliveredto the distribution system ($4.1 million), partially offset by lower cost ofpurchases for wholesale sales ($2.8 million).

 

Other operations and maintenance expenses increased $14.7 million(5.1%) in 2004.

 

Other operation expenses decreased $2.5 million (1.2%) in 2004primarily due to:

•                  The KU/LG&Emerger costs and the One Utility initiative costs were fully amortized in 2003,resulting in $2.8 million lower expense in 2004.

•                  Decreased steamgeneration expense ($1.2 million).

•                  Decreasedbenefits expense ($1.7 million), primarily due to lower pension expense ($2.1million) as a result of the $34.5 million pension funding in January 2004, partiallyoffset by higher medical insurance expense.

•                  Incrementaloperations expense due to storm restoration costs related to severe storms inMay and July 2004 ($3.1 million).

 

Maintenance expenses for 2004 increased $15.6 million (27.3%) primarilydue to:

•                  Increasedmaintenance expense due to storm restoration costs related to severe May andJuly storms ($9.3 million).

•                  Increaseddistribution maintenance, excluding the storm restoration costs ($0.7 million).

•                  Increased steamgeneration expense due to timing of scheduled maintenance ($1.4 million).

•                  Increasedcombustion turbine maintenance ($1.1 million).

•                  Increased hydrogeneration maintenance, primarily due to Ohio Falls rehabilitation ($0.5million).

 

Property and other taxes increased $1.6 million (10.2%) in 2004primarily due to:

•                  Increasedproperty taxes ($1.2 million).

•                  Increasedpayroll taxes ($0.4 million).

 

Other operations and maintenance increased $5.3 million (1.9%) in 2003.

 

Other operation expenses increased $8.7million (4.2%) in 2003 primarily due to:

•                  Increasedelectric transmission and distribution expense ($5.4 million).

•                  Increased employeebenefits costs ($4.0 million).

•                  Increased demandside management program expenses ($2.5 million).

•                  Increaseduncollectible customer accounts ($1.6 million).

•                  Decreasedamortization of regulatory assets ($3.5 million).

•                  Decreased injuryand damage liabilities ($2.1 million).

 

Maintenance expenses for 2003 decreased $3.0million (5.0%) primarily due to:

 

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•                  Decreased maintenanceof electric distribution ($1.1 million) and gas distribution ($0.8 million).

•                  Decreasedcommunications maintenance expenses ($0.9 million).

 

Property and other taxes decreased $0.4million (2.3%) in 2003 primarily due to:

•                  Reduced propertytaxes due to a $1.2 million coal credit ($1.1 million).

•                  Increased payrolltaxes ($0.7 million).

 

Depreciation and amortization increased $3.3 million (2.9%) in 2004 and$7.4 million (7.0%) in 2003 due to additional utility plant in service.

 

Other income (expense) - net increased $3.9 million (53.7%) in2004.  In 2003, write-offs of $3.0million decreased other income (see below). Other income (expense) - net decreased $5.7 million (367.2%) in 2003 dueprimarily to the write-off of amounts from CWIP for a terminated plant project($2.4 million) and a terminated software project ($0.6 million) partiallyoffset by a decrease in benefit costs ($1.7 million).

 

Total interest expense for 2004 increased $2.1 million (7.0%) due toincreased borrowing from Fidelia ($6.9 million), higher cost of the interestrate swaps ($3.0 million) resulting from the first full year of an additional$128 million of swaps and higher interest rates on variable-rate debt ($0.8million), partially offset by savings from retired first mortgage debt ($7.2million) and reduced borrowing from the money pool ($1.4 million).

 

Interest charges for 2003 increased $0.8 million (2.8%) due to newfixed-rate debt with Fidelia ($5.0 million) offset by a decrease in averageoutstanding balances borrowed from the money pool ($0.4 million) and savingsfrom lower average interest rates on variable-rate long-term bonds ($3.7million).

 

The weighted average interest rate on variable-rate long-term bonds for2004, 2003 and 2002 was 1.28%, 1.10% and 1.54%, respectively.  At December 31, 2004, 2003 and 2002, LG&E’spercentage of long-term bonds having a variable-rate, including the impact ofinterest rate swaps,  was 35.1% at $306.0million, 38.3% at $306.0 million and 46.8% at $289.0 million, respectively.  LG&E’s weighted average cost of long-termdebt, including amortization of debt expense and interest rate swaps, was3.92%, 3.58%, and 3.87% at December 31, 2004, 2003 and 2002, respectively.  See Note 9 of LG&E’s Notes to FinancialStatements under Item 8.

 

Variations in income tax expenses are largely attributable to changesin pre-tax income. LG&E’s 2004 effective income tax rate increased to 35.8%from the 35.5% rate in 2003.   See Note 7of LG&E’s Notes to Financial Statements under Item 8.

 

The rate of inflation may have a significant impact on LG&E’soperations, its ability to control costs and the need to seek timely andadequate rate adjustments. However, relatively low rates of inflation in thepast few years have moderated the impact on current operating results.

 

CRITICAL ACCOUNTING POLICIES/ESTIMATES

 

Preparation of financial statements and related disclosures incompliance with generally accepted accounting principles requires theapplication of appropriate technical accounting rules and guidance, as well asthe use of estimates.  The application ofthese policies necessarily involves judgments regarding future events,including legal and regulatory challenges and anticipated recovery of costs.  These judgments, in and of themselves, couldmaterially impact the financial statements and disclosures based on varyingassumptions, which may be appropriate to use. In addition, the financial and operating environment also may have asignificant effect, not only on the operation of the business, but on the resultsreported through the application of accounting measures used in preparing thefinancial statements and related disclosures, even if the nature of theaccounting policies

 

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applied has not changed.  Specificrisks for these critical accounting policies are described in the followingparagraphs.  Each of these has a higherlikelihood of resulting in materially different reported amounts underdifferent conditions or using different assumptions.  Events rarely develop exactly as forecast andthe best estimates routinely require adjustment.  See also Note 1 of LG&E’s Notes toFinancial Statements under Item 8.

 

Financial Instruments**-** LG&Euses over-the-counter interest-rate swap agreements to hedge its exposure tofluctuations in the interest rates it pays on variable-rate debt.  Gains and losses on interest-rate swaps usedto hedge interest rate risk are reflected in other comprehensive income.  LG&E uses sales of market-traded electricforward contracts for periods less than one year to hedge the price volatilityof its forecasted peak electric off-system sales.  Gains and losses resulting fromineffectiveness are shown in other income (expense) and to the extent that thehedging relationship has been effective, gains and losses are reflected inother comprehensive income.  Wholesalesales of excess asset capacity and wholesale purchases to be used to servenative load are treated as normal sales and purchases under SFAS No. 133, *Accounting for Derivative Instruments**and**Hedging Activities*, SFAS No. 138,*Accounting for Certain Derivative Instruments and Certain HedgingActivities* and SFAS No. 149,*Amendment of Statement133 on Derivative Instruments and Hedging Activities,* and are notmarked-to-market.  See Note 4 and Note 15of LG&E’s Notes to Financial Statements under Item 8.

 

Unbilled Revenue – At each month end LG&E preparesa financial estimate that projects electric and gas usage that has been used bycustomers, but not billed.  The estimatedusage is based on allocating the daily system net deliveries between billedvolumes and unbilled volumes.  Theallocation is based on a daily ratio of the number of meter reading cyclesremaining in the month to the total number of meter reading cycles in each month.  Each day’s ratio is then multiplied by eachday’s system net deliveries to determine an estimated billed and unbilledvolume for each day of the accounting period. At December 31, 2004, a 10% change in these estimated quantities wouldcause revenue and accounts receivable to change by approximately $6.3 million,including $2.7 million for electric usage and $3.6 million for gas usage.  See also Note 1 of LG&E’s Notes toFinancial Statements under Item 8.

 

Allowance for Doubtful Accounts – At December 31, 2004 and 2003, theLG&E allowance for doubtful accounts was $0.8 million and $3.5 million,respectively.  The allowance is based onthe ratio of the amounts charged-off during the last twelve months to the retailrevenues billed over the same period multiplied by the retail revenues billedover the last four months.  Accounts withno payment activity are charged-off after four months.

 

Benefit Plan Accounting –LG&E’s costs of providing defined-benefit pension retirement plans isdependent upon a number of factors, such as the rates of return on plan assets,healthcare cost trend rates, discount rate, contributions made to the plan, andother actuarial assumptions used to value benefit obligations.  In 2002, LG&E was required to recognizean additional minimum liability of $26.0 million as prescribed by SFAS No. 87 *Employers’ Accounting for Pensions*since the fair value ofthe plan assets was less than the accumulated benefit obligation at thattime.  During 2002, the combination ofpoor market performance and historically low corporate bond rates created adivergence in the potential value of the pension liabilities and the actualvalue of the pension assets.  Theliability was recorded as a reduction to other comprehensive income, and didnot affect net income.  In 2003, LG&Erecognized a reduction of the minimum pension liability of $3.1 million.  During 2004 LG&E recognized an additionalminimum pension liability of $10.2 million. If the fair value of the plan assets exceeds the accumulated benefit obligation,the recorded liability will be reduced and other comprehensive income will berestored in the consolidated balance sheet.

 

Should poor marketconditions return, these conditions could result in an increase in LG&E’sunfunded accumulated benefit obligations and future pension expense.  The primary assumptions that drive the valueof the unfunded accumulated benefit obligations are the discount rate andexpected return on plan assets.

 

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The assumptions used in the measurement of LG&E’s net periodicbenefit cost are shown in the following table:

 
| ** **                               | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
|                                     |       |     |       |     |       |     |       |
| Discount rate                            |       | 6.25     | %          | 6.75     | %          | 7.25     | %          |
| Expected long-term return on plan assets |       | 8.50     | %          | 9.00     | %          | 9.50     | %          |
| Rate of compensation increase            |       | 3.50     | %          | 3.75     | %          | 4.25     | %          |

 

LG&E made contributions tothe pension plan of $34.5 million in January 2004 and $89.1 million during2003.

 

A 1% increase or decreasein the assumed discount rate could have an approximate $39.9 million positiveor negative impact to the accumulated benefit obligation of LG&E.

 

See also Note 6 and Note 15 of LG&E’s Notes to Financial Statementsunder Item 8.

 

Regulatory Mechanisms – Judgments and uncertainties include futureregulatory decisions, the impact of deregulation and competition on ratemakingprocess, and external regulator decisions.

 

Regulatory assetsrepresent incurred costs that have been deferred because they are probable offuture recovery in customer rates based upon Kentucky Commission orders.  Regulatory liabilities generally representobligations to make refunds to customers for previous collections based uponorders by the Kentucky Commission. Management believes, based on orders, the existing regulatory assets andliabilities are probable of recovery.   Thisdetermination reflects the current regulatory climate in the state.  If future recovery of costs ceases to beprobable the assets would be required to be recognized in current periodearnings.

 

See also Note 3 ofLG&E’s Notes to Financial Statements under Item 8.

 

IncomeTaxes**-**Income taxes are accounted for underSFAS No.109, *Accounting for Income Taxes*.  Inaccordance with this statement, deferred tax assets and liabilities arerecognized for the future tax consequences attributable to differences betweenthe financial statement carrying amounts of existing assets andliabilities and their respective tax bases, as measured by enacted tax ratesthat are expected to be in effect in the periods when the deferred tax assetsand liabilities are expected to be settled or realized. Significant judgment isrequired in determining the provision for income taxes, and there aremany transactions for which the ultimate tax outcome is uncertain.

 

Toprovide for these uncertainties or exposures, an allowance is maintainedfor tax contingencies, the balance of which management believes isadequate.  Tax contingencies are analyzed periodicallyand adjustments are made when events occur to warrant a change. The company is currently in the examination phase of IRS audits forthe years 1999 to 2003 and expects some or all of these audits to becompleted within the next 12 months.  The results of auditassessments by taxing authorities are not anticipated to have a materialadverse effect on cash flows or results of operations.

 

H. R. 4520, known as the “American Jobs Creation Act of 2004” allowselectric utilities to take a deduction of up to 3% of their generation taxableincome in 2005. On a stand-alone basis, LG&E expects to generate adeduction in 2005 which will reduce LG&E’s effective tax rate by less than1%.

 

Kentucky HouseBill 272, also known as Kentucky’s Tax Modernization Plan, was signed into lawin March  2005.  This bill contains a number of changes inKentucky’s tax system, including the reduction of the Corporate income tax ratefrom 8.25% to 7% effective January 1, 2005, and a further reduction to 6%effective January 1, 2007.  The impact ofthese reduced rates is expected to decrease LG&E’s income tax expense infuture periods.  Furthermore, thesereduced rates will result in the reversal of accumulated temporary differencesat lower rates than originally provided. LG&E is presently evaluating the impact of this and other changes tothe Kentucky tax system, however, no material adverse impacts on cash flows orresults of operations are expected.

 

LG&E issubject to periodic changes in state tax law, regulation or interpretation, aswell as enforcement proceedings. LG&E is currently undergoing a routine Kentucky sales tax audit forthe period October 1997 through 2001. The possible assessment or amount at issue is not known at this time,but is not expected to have a material adverse effect on cashflows or resultsof operations.

 

See Note 1 and Note 7 of LG&E’s Notes to Financial Statements underItem 8.

 

Deferred Income Taxes - LG&E expects to have adequate levels oftaxable income to realize its recorded deferred tax assets.  See Note 7 of LG&E’s Notes to FinancialStatements under Item 8 for a breakdown of deferred tax assets.

 

NEW ACCOUNTINGPRONOUNCEMENTS

 

The following recent accounting pronouncements affected LG&E in2004 and 2003:

 

SFAS No. 143

 

SFAS No. 143, *Accounting for AssetRetirement Obligations* was issued in 2001.  SFAS No. 143 establishes accounting andreporting standards for obligations associated with the retirement of tangiblelong-lived assets and the associated asset retirement costs.

 

The effective implementation date for SFAS No. 143 was January 1,2003.  Management has calculated theimpact of SFAS No. 143 and FERC Final Order No. 631 issued in Docket No.RM02-7, *Accounting, Financial Reporting, and Rate FilingRequirements for Asset Retirement Obligations*.  As of January 1, 2003, LG&E recorded AROassets in the amount of $4.6 million and liabilities in the amount of $9.3million.  LG&E also recorded acumulative effect adjustment in the amount of $5.3 million to reflect theaccumulated depreciation and accretion of ARO assets at the transition dateless amounts previously accrued under regulatory depreciation.  LG&E recorded offsetting regulatoryassets of $5.3 million, pursuant to regulatory treatment prescribed under SFASNo. 71, *Accounting for the Effects of Certain Types ofRegulation*.  Also pursuant toSFAS No. 71, LG&E recorded regulatory liabilities in the amount of $0.1million offsetting removal costs previously accrued under regulatory accountingin excess of amounts allowed under SFAS No. 143.

 

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Had SFAS No. 143 been in effect for the 2002 reporting period, LG&Ewould have established asset retirement obligations as described in thefollowing table:

 
| **(in thousands)**             | ** ** | ** ** | ** ** |
|--------------------------------|------------|------------|------------|
| Provision at January 1, 2002   |       | $          | 8,752      |   |
| Accretion expense              |       | 578        |       |
| Provision at December 31, 2002 |       | $          | 9,330      |   |

 

As of December 31, 2004, LG&E had ARO assets, net of accumulateddepreciation, of $3.3 million and liabilities of $10.3 million.  As of December 31, 2003, LG&E had AROassets, net of accumulated depreciation, of $3.5 million and liabilities of$9.7 million.  LG&E recordedoffsetting regulatory assets of $6.9 million and $6.0 million and regulatory liabilitiesof $0.1 million as of both December 31, 2004 and 2003, respectively.

 

For the year ended December 31, 2004, LG&E recorded AROaccretion expense of approximately $0.7 million, ARO depreciation expense of$0.2 million and an offsetting regulatory credit in the income statement of$0.9 million, pursuant to regulatory treatment prescribed under SFAS No.71.  For the year ended December 31,2003, LG&E recorded ARO accretion expense of approximately $0.6 million,ARO depreciation expense of $0.1 million and an offsetting regulatory credit inthe income statement of $0.7 million. Removal costs incurred and charged against the ARO liability during 2004and 2003 were $0.1 million and $0.2 million, respectively.  SFAS No. 143 has no impact on the results ofoperations of LG&E.

 

LG&E AROs are primarily related to final retirement of assetsassociated with generating units.  Forassets associated with AROs, the removal cost accrued through depreciationunder regulatory accounting is established as a regulatory asset or liabilitypursuant to regulatory treatment prescribed under SFAS No. 71.  For the years ended December 31, 2004and 2003, LG&E recorded immaterial amounts (less than $0.1 million) ofdepreciation expense related to the cost of removal of ARO related assets.  An offsetting regulatory liability wasestablished pursuant to regulatory treatment prescribed under SFAS No. 71.

 

LG&E also continues to include a cost of removal component indepreciation for assets that do not have a legal ARO.  As of December 31, 2004 and 2003, LG&Ehas segregated this cost of removal, embedded in accumulated depreciation, of$220.2 million and $216.5 million, respectively, in accordance with FERC OrderNo. 631*.* For reporting purposesin its Consolidated Balance Sheets included in Item 8, LG&E has presentedthis cost of removal as a regulatory liability pursuant to SFAS No. 71.

 

LG&E transmission and distribution lines largely operate underperpetual property easement agreements which do not generally requirerestoration upon removal of the property. Therefore, under SFAS No. 143, no material asset retirement obligationsare recorded for transmission and distribution assets.

 

EITF No. 02-03

 

LG&E adopted EITF No. 98-10, *Accounting for EnergyTrading and Risk Management Activities,*effective January 1,1999.  This pronouncement required thatenergy trading contracts be marked to market on the balance sheet, with thegains and losses shown net in the income statement.  Effective January 1, 2003, LG&E adoptedEITF No. 02-03, *Issues Involved in Accounting for DerivativeContracts Held for Trading Purposes and Contracts Involved in Energy Tradingand Risk Management Activities*. EITF No. 02-03 established the following:

 

•                  Rescinded EITFNo. 98-10,

 

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•                  Contractsthatdo not meet the definition of a derivative under SFAS No. 133 should not bemarked to fair market value, and

•                  Revenues shouldbe shown in the income statement net of costs associated with tradingactivities, whether or not the trades are physically settled.

 

With the rescission of EITF No. 98-10, energy trading contracts that donot also meet the definition of a derivative under SFAS No. 133 must beaccounted for as executory contracts. Contracts previously recorded at fair value under EITF No. 98-10 thatare not also derivatives under SFAS No. 133 must be restated to historical costthrough a cumulative effect adjustment. The rescission of this standard had no impact on financial position orresults of operations of LG&E since all forward and option contracts markedto market under EITF No. 98-10 were also within the scope of SFAS No. 133.

 

As a result of EITF No. 02-03, LG&E hasnetted the power purchased expense for trading activities against electricoperating revenue to reflect this accounting change.  LG&E applied this guidance to previouslyreported 2002 balances as shown below. The reclassifications had no impact onpreviously reported net income or common equity.

 
| **(in thousands)**                                        | ** ** | ** ** | ** ** |
|-----------------------------------------------------------|------------|------------|------------|
| Gross electric operating revenues as  previously reported |       | $          | 1,026,184  |   |
| Less costs reclassified from power  purchased             |       | 22,449     |       |
| Net electric operating revenues                           |       | $          | 1,003,735  |   |
|                                                      |       |       |       |
| Gross power purchased as previously  reported             |       | $          | 84,330     |   |
| Less costs reclassified to revenues                       |       | 22,449     |       |
| Net power purchased                                       |       | $          | 61,881     |   |

 

SFAS No. 150

 

In May 2003,the Financial Accounting Standards Board issued SFAS No. 150, *Accounting for Certain Financial Instruments with Characteristics ofboth Liabilities and Equity*. SFAS No. 150 was effective immediately for financial instruments enteredinto or modified after May 31, 2003, and otherwise was effective for interimreporting periods beginning after June 15, 2003, except for certain instrumentsand certain entities which have been deferred by the FASB.  Such deferrals do not affect LG&E.

 

LG&E has$5.875 series mandatorily redeemable preferred stock outstanding having acurrent redemption price of $100 per share. The preferred stock has a sinkingfund requirement sufficient to retire a minimum of 12,500 shares on July 15 ofeach year commencing with July 15, 2003, and the remaining 187,500 shares onJuly 15, 2008 at $100 per share. LG&E redeemed 12,500 shares in accordance with these provisions onJuly 15, 2003 and 2004, leaving 225,000 shares currently outstanding.  Beginning with the three months endedSeptember 30, 2003, LG&E reclassified its $5.875 series preferred stock aslong-term debt with the minimum shares mandatorily redeemable within one yearclassified as current portion of long-term debt.  Dividends accrued beginning July 1, 2003, arecharged as interest expense.

 

FIN 46

 

In January 2003, the Financial Accounting Standards Board issuedFinancial Accounting Standards Board Interpretation No. 46, *Consolidation of Variable Interest Entities*, anInterpretation of ARB No. 51 (“FIN 46”). FIN 46 requires certain variable interest entities to be consolidated bythe primary beneficiary of the entity if the equity investors in the entity donot have the characteristics of a controlling financial interest or do not havesufficient equity at risk for the entity to finance its activities withoutadditional subordinated financial support

 

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from other parties.  FIN 46 waseffective immediately for all new variable interest entities created oracquired after January 31, 2003.  Forvariable interest entities created or acquired prior to February 1, 2003, theprovisions of FIN 46 must have been applied for the first interim or annualperiod beginning after June 15, 2003.

 

In December 2003, FIN 46 was revised, delaying the effective dates forcertain entities created before February 1, 2003, and making other amendmentsto clarify application of the guidance. For potential variable interest entities other than special purposeentities, the revised FIN 46 (“FIN 46R”) was required to be applied no laterthan the end of the first fiscal year or interim reporting period ending afterMarch 15, 2004.  The original guidance underFIN 46 was applicable, however, for all special purpose entities created priorto February 1, 2003, at the end of the first interim or annual reporting periodending after December 15, 2003.  FIN 46Rmay be applied prospectively with a cumulative-effect adjustment as of the dateit is first applied, or by restating previously issued financial statementswith a cumulative-effect adjustment as of the beginning of the first yearrestated.  FIN 46R also requires certaindisclosures of an entity’s relationship with variable interest entities. Theadoption of FIN 46 and FIN 46R had no impact on the financial position orresults of operations for LG&E.

 

Although LG&E holds an investment interest in OVEC, it is not theprimary beneficiary of OVEC and, therefore, OVEC is not consolidated into thefinancial statements of LG&E.  LG&Eand 11 other electric utilities are participating owners of OVEC, located inPiketon, Ohio. OVEC owns and operates two power plants that burn coal togenerate electricity, Kyger Creek Station in Ohio and Clifty Creek Station inIndiana.  LG&E’s share is 7%,representing approximately 155 Mw of generation capacity.

 

LG&E’s original investment in OVEC was made in 1952. As of December31, 2004, LG&E’s investment in OVEC totaled $0.5 million.  In March 2005, LG&E purchased from AEP anadditional 0.73% interest in OVEC for a purchase price of approximately $0.1million, which resulted in an increase in LG&E ownership in OVEC from 4.9%to 5.63%.  LG&E’s investment in OVECis accounted for under the cost method of accounting.

 

LG&E’s maximum exposure to loss as a result of its involvement withOVEC is limited to the value of the investments.  In the event of the inability of OVEC tofulfill its power provision requirements, LG&E would substitute such powersupply with either owned generation or market purchases and would generallyrecover associated incremental costs through regulatory rate mechanisms.  See Note 11 of LG&E’s Notes to FinancialStatements under Item 8 for further discussion of developments regardingLG&E’s ownership interest and power purchase rights.

 

FSP 106-2

 

In May 2004,the FASB finalized FSP 106-2, *Accounting and DisclosureRequirements Related to the Medicare Prescription Drug, Improvement andModernization Act of 2003* (“Medicare Act”) with guidance onaccounting for subsidies provided under the Medicare Act which became law inDecember 2003.  FSP No. 106-2 is effectivefor the first interim or annual period beginning after June 15, 2004.  FSP 106-2 does not have a material impact onLG&E.

 

FSP 109-1

 

In December2004, the FASB finalized FSP 109-1, *Accountingfor Income Taxes, Application of FAS 109 to the Tax Deduction on QualifiedProduction Activities Provided by the American Jobs Creation Act of 2004,*which**requires the tax deduction on qualifiedproduction activities to be treated as a special deduction in accordance withFAS 109.  FSP 109-1 became effectiveDecember 21, 2004, and does not have a material impact on LG&E.

 

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LIQUIDITY AND CAPITAL RESOURCES

 

LG&E uses net cash generated from its operations and externalfinancing (including financing from affiliates) to fund construction of plantand equipment and the payment of dividends. LG&E believes that such sources of funds will be sufficient to meetthe needs of its business in the foreseeable future.

 

As of December 31, 2004, LG&E is in a negative working capitalposition in part because of the classification of certain variable-ratepollution control bonds that are subject to tender for purchase at the optionof the holder as current portion of long-term debt. Backup credit facilitiestotaling $185 million are in place to fund such tenders if necessary.  LG&E has never had to access thesefacilities.  LG&E expects to coverany working capital deficiencies with cash flow from operations, money poolborrowings, and borrowings from Fidelia.

 

Operating Activities

 

Cash provided by operations was $171.6 million, $163.3 million and$212.4 million in 2004, 2003, and 2002, respectively.  The 2004 increase of $8.3 million compared to2003 resulted largely from the reduction in pension funding of $54.6 million,higher gas supply cost recovery of $15.0 million, higher earnings sharingmechanism of $10.1 million and receipt of a litigation settlement of $7.0 million.These increases were largely offset by a reduction in accounts receivable of$66.3 million, including the termination of the accounts receivablesecuritization program, and a reduction in accrued income taxes of $22.4 million.The 2003 decrease compared to 2002 of $49.1 million resulted primarily frompension funding in 2003 of $89.1 million and an increase in accounts receivablebalances of $33.4 million, including the sale of accounts receivable throughthe accounts receivable securitization program, partially offset by an increasein accounts payable and accrued income taxes of $35.0 million and $36.0million, respectively.  See Note 4 ofLG&E’s Notes to Financial Statements under Item 8 for a discussion ofaccounts receivable securitization.

 

Investing Activities

 

LG&E’s primary use of funds for investing activities continues tobe for capital expenditures.  Capitalexpenditures were $148.3 million, $213.0 million and $220.4 million in 2004,2003, and 2002, respectively.  LG&Eexpects its capital expenditures for 2005 and 2006 to total approximately $268million, which consists primarily of construction estimates associated with theredevelopment of the Ohio Falls hydro facility, totaling $19.6 million,construction of Trimble County Unit 2, totaling $8.8 million, and on-goingconstruction related to generation and distribution assets.

 

Net cash used for investing activities decreased $64.6 million in 2004compared to 2003, primarily due to the level of construction expenditures.  NOx equipment expenditures were approximately$5.3 million in 2004 and $29.6 million in 2003, while CT expenditures wereapproximately $8.1 million in 2004 and $71.4 million in 2003.    Net cash used for investing activitiesdecreased $7.2 million in 2003 compared to 2002 primarily due to the level ofconstruction expenditures.

 

Financing Activities

 

Net cash inflows (outflows) for financing activities were $(18.3)million in 2004, $34.2 million in 2003 and $22.5 million in 2002.

 

In January 2004, LG&E entered into two long-term loans fromFidelia, one totaling $25 million with an interest

 

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rate of 4.33% that matures in January 2012, and one totaling $100million with an interest rate of 1.53% that matured in January 2005.  The loans are collateralized by a pledge ofsubstantially all assets of LG&E that is subordinated to the first mortgagebond lien. The proceeds were used to fund a pension contribution and to repayother debt obligations.  In April 2004,LG&E prepaid $50 million of the $100 million 1.53% note payable toFidelia.  The prepayment was paid out ofcash balances.  The remaining $50 millionunder this note was paid at maturity in January 2005.

 

In November 2003, LG&E issued $128 million variable-rate pollutioncontrol bonds due October 1, 2033, and exercised its call option on the $102million, 5.625% pollution control bonds due August 15, 2019 and on the $26million, 5.45% pollution control bonds due October 15, 2020.

 

During 2003, LG&E entered into two long-term loans from Fideliatotaling $200 million.  $100 million ofthis total is unsecured and the remaining $100 million is collateralized by apledge of substantially all assets of LG&E that is subordinated to thefirst mortgage bond lien.

 

LG&E first mortgage bond, 6% Series of $42.6 million matured inAugust 2003 and was retired.

 

In March 2002, LG&E refinanced its $22.5 million and $27.5 millionunsecured 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. LG&E alsorefinanced its two $35 million unsecured pollution control bonds due November1, 2027.  The replacement variable-ratebonds are secured by pollution control series bonds treated as first mortgagebonds and will mature November 1, 2027.

 

In October 2002, LG&E issued $41.7 million variable-rate pollutioncontrol bonds due October 1, 2032, and exercised its call option on $41.7million, 6.55% pollution control bonds due November 1, 2020.

 

Under the provisions of certain variable-rate pollution control bondstotaling $246.2 million, the bonds are subject to tender for purchase byLG&E at the option of the holder and to mandatory tender for purchase uponthe occurrence of certain events, causing the bonds to be classified as currentportion of long-term debt.  Backup creditfacilities totaling $185 million are in place to fund such tenders ifnecessary.  LG&E has never had toaccess these facilities.

 

Future Capital Requirements

 

Future capital requirements may be affected in varying degrees byfactors such as electric energy demand load growth, changes in constructionexpenditure levels, rate actions by regulatory agencies, new legislation,market entry of competing electric power generators, changes in environmentalregulations and other regulatory requirements. LG&E anticipates funding future capital requirements throughoperating cash flow, debt, and/or infusions of capital from its parent.

 

LG&E has a variety of funding alternatives available to meet itscapital requirements.  The Companymaintains a series of bilateral credit facilities with banks totaling $185million.  Several intercompany financingarrangements are also available. LG&E participates in an intercompany money pool agreement whereinLG&E Energy and KU make funds available to LG&E at market-based ratesup to $400 million.  Fidelia alsoprovides long-term intercompany funding to LG&E.

 

Certain regulatoryapprovals are required for the Company to incur additional debt.  The SEC authorizes the issuance of short-termdebt while the Kentucky Commission authorizes issuance of long-term debt.  As of December 31, 2004 the Company hasreceived approvals from the SEC to borrow up to $400 million in short-termfunds.

 

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LG&E’s debt ratings as of December 31, 2004, were:

 
| ** **           | ** ** | **Moody’s** | ** ** | **S&P** | ** ** |
|----------------------|------------|------------------|------------|-------------|------------|
|                 |       |             |       |        |       |
| First mortgage bonds |       | A1               |       | A-          |       |
| Preferred stock      |       | Baa1             |       | BBB-        |       |
| Commercial paper     |       | P-1              |       | A-2         |       |

 

These ratings reflect the views of Moody’s and S&P.  A security rating is not a recommendation tobuy, sell or hold securities and is subject to revision or withdrawal at anytime by the rating agency.

 

Contractual Obligations

 

The following is provided to summarize LG&E’s contractualcash obligations for periods after December 31, 2004.  LG&E anticipates cash from operations andexternal financing will be sufficient to fund future obligations.

 
| **(****in  thousands****)**                   | ** ** | **Payments Due by Period** | ** ** |
|-----------------------------------------------|------------|----------------------------|------------|
| **Contractual Cash Obligations**              | ** ** | **2005**                   | ** ** | **2006** | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** | **Thereafter** | ** ** | **Total** | ** ** |
| Short-term debt (a)                           |       | $                          | 58,220     |   | $ | — |   | $ | — |   | $ | — |   | $ | — |   | $ | — |   | $ | 58,220 |   |
| Long-term debt                                |       | 297,450                    |       | 1,250 |   | 1,250 |   | 18,750 |   | — |   | 553,104 | (b) | 871,804 |   |
| Operating lease (c)                           |       | 3,469                      |       | 3,538 |   | 3,609 |   | 3,681 |   | 3,754 |   | 22,375 |   | 40,426 |   |
| Unconditional power purchase obligations  (d) |       | 11,230                     |       | 10,098 |   | 9,726 |   | 9,932 |   | 10,145 |   | 181,089 |   | 232,220 |   |
| Coal and gas purchase obligations (e)         |       | 202,450                    |       | 95,478 |   | 52,656 |   | 49,396 |   | 6,037 |   | 6,037 |   | 412,054 |   |
| Retirement obligations (f)                    |       | 9,250                      |       | 10,106 |   | 13,305 |   | 10,992 |   | 15,839 |   | — |   | 59,492 |   |
| Other long-term obligations (g)               |       | 14,767                     |       | — |   | — |   | — |   | — |   | — |   | 14,767 |   |
| Total contractual cash obligations            |       | $                          | 596,836    |   | $ |  120,470 |   | $ | 80,546 |   | $ | 92,751 |   | $ | 35,775 |   | $ | 762,605 |   | $ | 1,688,983 |   |

 

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(a)          Represents borrowings from affiliated companydue within one year.

(b)         Includes long-term debt of $246.2 millionclassified as current liabilities because these bonds are subject to tender forpurchase at the option of the holder and to mandatory tender for purchase uponthe occurrence of certain events. Maturity dates for these bonds range from 2013 to 2027.  LG&E does not expect to pay these amountsin 2005.

(c)          Operating lease represents the lease ofLG&E’s administrative office building.

(d)         Represents future minimum payments under OVECpurchased power agreements through 2024.

(e)          Represents contracts to purchase coal andnatural gas.

(f)            Represents currently projected cash flows forpension plans and other post-employment benefits as calculated by the actuary.

(g)         Represents construction commitments.

 

Sale and Leaseback Transaction

 

LG&E is aparticipant in a sale and leaseback transaction involving its 38% interest intwo jointly-owned CTs at KU’s E.W. Brown generating station (Units 6 and7).  Commencing in December 1999,LG&E and KU entered into a tax-efficient, 18-year lease of the CTs.  LG&E and KU have provided funds to fullydefease the lease, and have executed an irrevocable notice to exercise an earlypurchase option contained in the lease after 15.5 years.  The financial statement treatment of thistransaction is no different than if LG&E had retained its ownership.  The leasing transaction was entered intofollowing receipt of required state and federal regulatory approvals.

 

In case ofdefault under the lease, LG&E is obligated to pay to the lessor its shareof certain fees or amounts. Primary events of default include loss ordestruction of the CTs, failure to insure or maintain the CTs and

 

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unwinding ofthe transaction due to governmental actions. No events of default currently exist with respect to the lease.  Upon any termination of the lease, whether bydefault or expiration of its term, title to the CTs reverts jointly to LG&Eand KU.

 

At December 31,2004, the maximum aggregate amount of default fees or amounts, which decreaseover the term of the lease, was $9.5 million, of which LG&E would beresponsible for $3.6 million (38%). LG&E has made arrangements with LG&E Energy, via guarantee andregulatory commitment, for LG&E Energy to pay its full portion of anydefault fees or amounts.

 

MARKET RISKS

 

LG&E is exposed to market risks from changes in interest rates andcommodity prices.  To mitigate changes incash flows attributable to these exposures, LG&E uses various financialinstruments including derivatives. Derivative positions are monitored using techniques that include marketvalue and sensitivity analysis.  SeeNotes 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 obligationsoutstanding.  At December 31, 2004, thepotential change in interest expense associated with a 1% change in baseinterest rates of LG&E’s unhedged debt is estimated at $3.6 million afterthe impact of interest rate swaps.

 

Interest rate swaps are used to hedge LG&E’s underlyingvariable-rate debt obligations.  Theseswaps hedge specific debt issuances and, consistent with management’sdesignation, are accorded hedge accounting treatment.  See Note 4 of LG&E’s Notes to FinancialStatements under Item 8.

 

As of December 31, 2004, LG&E had swaps with a combined notionalvalue of $228.3 million.  The swapsexchange floating-rate interest payments for fixed rate interest payments to reducethe impact of interest rate changes on LG&E’s pollution control bonds.  The potential loss in fair value resultingfrom a hypothetical 1% adverse movement in base interest rates is estimated atapproximately $25.7 million as of December 31, 2004.  This estimate is derived from third-partyvaluations. Changes in the market value of these swaps if held to maturity, asLG&E intends to do, will have no effect on LG&E’s net income or cashflow.  See Note 4 of LG&E’s Notes toFinancial Statements under Item 8.

 

Commodity Price Sensitivity

 

LG&E has limited exposure to market price volatility in prices offuel and electricity, since its retail tariffs include the FAC and GSCcommodity price pass-through mechanisms. LG&E is exposed to market price volatility of fuel and electricityin its wholesale activities.

 

# **EnergyTrading & Risk Management Activities**

# ** **

LG&E conducts energy trading and risk management activities tomaximize the value of power sales from physical assets it owns, in addition tothe wholesale sale of excess asset capacity. Certain energy trading activities are accounted for on a mark-to-marketbasis in accordance with SFAS No. 133*,*SFAS No. 138**and SFAS No. 149. Wholesale sales of excess asset capacity are treated as normal salesunder these pronouncements and are not marked to market.  To be eligible for the normal sales exclusionunder SFAS No. 133, sales are limited to the forecasted excess capacity ofLG&E’s generation assets over what is needed to serve native load.  To be eligible for the normal purchasesexclusion under SFAS No. 133 purchases must be used to serve LG&E’s

 

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native load.  Without the normalsales and purchases exclusion these transactions would be consideredderivatives and marked to market under SFAS No. 133.

 

The rescission of EITFNo. 98-10 for fiscal periods ending after December 15, 2002, had no impact onLG&E’s energy trading and risk management reporting as all forward andoption contracts marked to market under EITF No. 98-10 are also within thescope of SFAS No. 133.

 

The table belowsummarizes LG&E’s energy trading and risk management activities for 2004and 2003:

 
| **(in thousands)**                                                     | ** ** | **2004** | ** ** | **2003** | ** ** |
|------------------------------------------------------------------------|------------|----------|------------|----------|------------|
| Fair value of contracts at beginning of  period, net asset (liability) |       | $        | 572        |     | $          | (156 | ) |
| Fair value of contracts when entered into  during the period           |       | (75      | )          | 2,654    |       |
| Contracts realized or otherwise settled  during the period             |       | (858     | )          | (569     | )          |
| Changes in fair values due to changes in  assumptions                  |       | 164      |       | (1,357   | )          |
| Fair value of contracts at end of period,  net (liability) asset       |       | $        | (197       | )        | $          | 572 |   |

 

No changes to valuation techniques for energy tradingand risk management activities occurred during 2004.  Changes in market pricing, interest rate andvolatility assumptions were made during both years.  The outstanding mark-to-market value issensitive to changes in prices, price volatilities, and interest rates.  The Company estimates that a movement inprices of $1 and a change in interest and volatilities of 1% would not resultin a change of a material amount.  Allcontracts outstanding at December 31, 2004, have a maturity of less than oneyear and are valued using prices actively quoted for proposed or executedtransactions or quoted by brokers.

 

LG&E maintains policies intended to minimize credit risk andrevalues credit exposures daily to monitor compliance with those policies.  At December 31, 2004, 100% of the trading andrisk management commitments were with counterparties rated BBB-/Baa3 equivalentor better.

 

Accounts Receivable Securitization

 

On February 6, 2001, LG&E implemented an accounts receivablesecuritization program.  LG&Eterminated the accounts receivable securitization program in January 2004, andin May 2004, dissolved its inactive accounts receivable securitization-relatedsubsidiary, LG&E R. The purpose of this program was to enable LG&E toaccelerate the receipt of cash from the collection of retail accountsreceivable, thereby reducing dependence upon more costly sources of workingcapital.  The securitization programallowed for a percentage of eligible receivables to be sold.  Eligible receivables were generally allreceivables associated with retail sales that had standard terms and were notpast due.  LG&E was able to terminatethe program at any time without penalty.

 

As part of the program, LG&E sold retail accounts receivable toLG&E R.  Simultaneously, LG&E Rentered into two separate three-year accounts receivable securitizationfacilities with two financial institutions and their affiliates wherebyLG&E R could sell, on a revolving basis, an undivided interest in certainof its receivables and receive up to $75 million from unrelated third-partypurchasers.  The effective cost of thereceivables program was comparable to LG&E’s lowest cost source of capital,and was based on prime rated commercial paper. LG&E retained servicing rights of the sold receivables through twoseparate servicing agreements with the third-party purchasers.  LG&E obtained an opinion from independentlegal counsel indicating these transactions qualified as a true sale ofreceivables.

 

To determine LG&E’s retained interest, the proceeds on the sale ofreceivables to the financial institutions was netted against the amount ofeligible receivables sold by LG&E to LG&E R.  Interest expense, program fees,

 

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and facility fees paid to the financial institutions and an allowancefor doubtful accounts were deducted to arrive at the future value of retainedinterest.  The future value was discountedusing the prime rate plus 25 basis points, assuming a 45-day receivablelife.  No material pre-tax gains orlosses from the sale of the receivables occurred in 2004, 2003, and 2002.  LG&E’s net cash flows from LG&E Rwere $(58.1) million, $(6.2) million, and $20.2 million for 2004, 2003 and2002, respectively.

 

The allowance for doubtful accounts associated with the eligiblesecuritized receivables at December 31, 2003 and 2002 was $1.4 million and $1.9million, respectively.  This allowancewas based on historical experience of LG&E. Each securitization facilitycontained a fully funded reserve for uncollectible receivables.

 

RATES AND REGULATION

 

LG&E is subject to the jurisdiction of the Kentucky Commission invirtually all matters related to electric and gas utility regulation, and assuch, its accounting is subject to SFAS No. 71. Given LG&E’s competitive position in the marketplace and the statusof regulation in Kentucky, LG&E has no plans or intentions to discontinueits application of SFAS No. 71.  See Note3 of LG&E’s Notes to Financial Statements under Item 8.

 

**Electric and Gas Rate Cases. **InDecember 2003, LG&E filed applications with the Kentucky Commissionrequesting adjustments in LG&E’s electric and gas rates.  LG&E requested general adjustments inelectric and gas rates based on the twelve month test year ended September 30,2003.  The revenue increases requestedwere $63.8 million for electric and $19.1 million for gas.

 

In June 2004, the KentuckyCommission issued an order approving increases in the base electric and gasrates of LG&E.  The KentuckyCommission’s order largely accepted proposed settlement agreements filed in May2004 by LG&E and a majority of the parties to the rate caseproceedings.   The rate increases tookeffect on July 1, 2004.

 

In the Kentucky Commission’sorder, LG&E was granted increases in annual base electric rates of approximately$43.4 million (7.7%) and in annual base gas rates of approximately $11.9million (3.4%).  Other provisions of theorder include decisions on certain depreciation, gas supply clause, ECR and VDTamounts or mechanisms and a termination of the ESM with respect to all periodsafter 2003.  The order also provided fora recovery before March 31, 2005, by LG&E of previously requested amountsrelating to the ESM during 2003.

 

DuringJuly 2004, the AG served subpoenas on LG&E, as well as on the KentuckyCommission and its staff, requesting information regarding allegedly impropercommunications between LG&E and the Kentucky Commission, particularlyduring the period covered by the rate cases. The Kentucky Commission has procedurallyreopened the rate cases for the limited purpose of taking evidence, if any, asto the communication issues. Subsequently, the AG filed pleadings with theKentucky Commission requesting rehearing of the rate cases on certaincomputational components of the increased rates, including income tax, cost ofremoval and depreciation amounts. In August 2004, the Kentucky Commissiondenied the AG’s rehearing request on the cost of removal and depreciationissues, with the effect that the rate increase order is final as to thesematters, subject to the parties’ rights to judicial appeals. The KentuckyCommission further agreed to hold in abeyance further proceedings in the rate cases,including the AG’s concerns about alleged improper communications, until the AGcould file with the Kentucky Commission an investigative reportregarding the latter issue. In addition, the Kentucky Commission granted arehearing on the income tax component once the abeyance discussed above islifted.

 

In Septemberand October 2004, various proceedings were held in circuit courts in Franklinand Jefferson Counties, Kentucky regarding the scope and timing of documentproduction or other information required or

 

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agreed to beproduced under the AG’s subpoenas and matters were consolidated into theFranklin County court. In October 2004, the AG filed a motion with the KentuckyCommission requesting that the previously granted rate increases be set aside,that LG&E resubmit any applications for rate increases and that relevantKentucky Commission personnel be recused from participation in rate caseproceedings.  In November 2004, theFranklin County, Kentucky court denied an AG request for sanctions on LG&Erelating to production matters and narrowed the AG’s permitted scope ofdiscovery.   In January 2005, the AGconducted interviews of certain Company individuals.

 

In January2005, the AG submitted its report to the Franklin County, Kentucky CircuitCourt in confidence.  Concurrently the AGfiled a motion summarizing the report as containing evidence of impropercommunications and record-keeping errors by LG&E in its conduct ofactivities before the Kentucky Commission or other state governmental entitiesand requesting release of the report to such agencies.  During February 2005 the court ruled that thereport be forwarded to the Kentucky Commission under continued confidentialtreatment to allow it to consider the report, including its impact, if any, oncompleting its investigation and any remaining steps in the rate cases,including ending the current abeyance. To date, LG&E has neither seen nor requested copies of the report orits contents.

 

LG&E believes no improprieties have occurred in its communicationswith the Kentucky Commission and is cooperating with the proceedings before theAG and the Kentucky Commission.

 

LG&E is currently unable to determine the ultimate impact, if any,of, or any possible future actions of the AG or the Kentucky Commission arisingout of, the AG’s report and investigation, including whether there will befurther actions to appeal, review or otherwise challenge the granted increasesin base rates.

 

**VDT Costs - Kentucky Commission Settlement Order.**  During the first quarter 2001, LG&Erecorded a $144 million charge for a workforce reduction program.  Primary components of the charge wereseparation benefits, enhanced early retirement benefits, and healthcarebenefits.  The result of this workforcereduction was the elimination of approximately 700 positions, accomplishedprimarily through a voluntary enhanced severance program.

 

In June 2001, LG&E filed an application (“VDT case”) with theKentucky Commission to create a regulatory asset relating to these firstquarter 2001 charges.  The applicationrequested permission to amortize these costs over a four-year period.  The Kentucky Commission also opened a case toreview a new depreciation study and resulting depreciation rates implemented in2001.

 

In December 2001, the Kentucky Commission approved a settlement in theVDT case as well as other cases involving the depreciation rates and ESM.  The order approving the settlement allowedLG&E to set up a regulatory asset of $141 million for the workforcereduction costs and begin amortizing these costs over a five year periodstarting in April 2001.  The firstquarter 2001 charge of $144 million represented all employees who had accepteda voluntary enhanced severance program. Some employees rescinded their participation in the voluntary enhancedseverance program, thereby decreasing the original charge to the regulatoryasset from $144 million to $141 million. The settlement reduces revenues approximately $26 million through a surcrediton bills to ratepayers over the same five-year period.  The surcredit represents net savingsstipulated by LG&E.

 

As mentioned, the current five-year VDT amortization period isscheduled to expire in March 2006.  Aspart of the settlement agreements in the electric and gas rate cases, LG&Eshall file with the Kentucky Commission a plan for the future ratemakingtreatment of the VDT surcredits and costs six months prior to the March 2006expiration.  The surcredit shall remainin effect following the expiration of the fifth year until the Commissionenters an order on the future disposition of VDT-related issues.

 

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**Merger Surcredit. **Aspart of the LG&E Energy merger with KU Energy in 1998, LG&E Energyestimated non-fuel savings over a ten-year period following the merger.  Costs to achieve these savings for LG&Eof $50.2 million were recorded in the second quarter of 1998, $18.1 million ofwhich was deferred and amortized over a five-year period pursuant to regulatoryorders.  Primary components of the mergercosts were separation benefits, relocation costs, and transaction fees, themajority of which were paid by December 31, 1998.  LG&E expensed the remaining costsassociated with the merger ($32.1 million) in the second quarter of 1998.

 

In approving the merger, the Kentucky Commission adopted LG&E’sproposal to reduce its retail customers’ bills based on one-half of theestimated merger-related savings, net of deferred and amortized amounts, over afive-year period.  The surcreditmechanism provides that 50% of the net non-fuel cost savings estimated to beachieved from the merger be provided to ratepayers through a monthly billcredit, and 50% be retained by LG&E and KU, over a five-year period.  The surcredit was allocated 53% to KU and 47%to LG&E.  In that same order, theKentucky Commission required LG&E and KU, after the end of the five-yearperiod, to present a plan for sharing with ratepayers the then-projectednon-fuel savings associated with the merger. The Companies submitted this filing in January 2003, proposing tocontinue to share with ratepayers, on a 50%/50% basis, the estimated fifth-yeargross level of non-fuel savings associated with the merger.  In October 2003, the Kentucky Commissionissued an order approving a settlement agreement reached with the parties inthe case. LG&E’s merger surcredit will remain in place for anotherfive-year term beginning July 1, 2003 and the merger savings will continue tobe shared 50% with ratepayers and 50% with shareholders.

 

**ESM. **Priorto 2004, LG&E’s retail electric rates were subject to an ESM.  The ESM, initially in place for three yearsbeginning in 2000, set an upper and lower point for rate of return on equity,whereby if LG&E’s rate of return for the calendar year fell within therange of 10.5% to 12.5%, no action was necessary.  If earnings were above the upper limit, theexcess earnings were shared 40% with ratepayers and 60% with shareholders; if earningswere below the lower limit, the earnings deficiency was recovered 40% fromratepayers and 60% from shareholders.  Byorder of the Kentucky Commission, rate changes prompted by the ESM filing wentinto effect in April of each year subject to a balancing adjustment insuccessive periods.

 

In November 2002, LG&E filed a revised ESM tariff which proposedcontinuance of the existing ESM through December 2005.  In addition, the Kentucky Commission initiated a focused management audit to review the ESMplan and reassess its reasonableness.  LG&Eand interested parties had the opportunity to provide recommendations formodification and continuance of the ESM or other forms of alternative orincentive regulation.

 

LG&E filedits final 2003 ESM calculations with the Kentucky Commission on March 1, 2004,and applied for recovery of $13.0 million. Based upon estimates, LG&Epreviously accrued $8.9 million for the 2003 ESM as of December 31, 2003.

 

On June 30,2004, the Kentucky Commission issued an order largely accepting proposedsettlement agreements by LG&E and all intervenors regarding the ESM.  Under the ESM settlements, LG&E willcontinue to collect approximately $13.0 million of previously requested 2003ESM revenue amounts through March 2005. As part of the settlement, the parties agreed to a termination of theESM relating to all periods after 2003.

 

As a result ofthe settlement, LG&E accrued an additional $4.1 million in June 2004,related to 2003 ESM revenue.

 

**FAC. **LG&E’sretail electric rates contain a FAC, whereby increases or decreases in the costof fuel for electric generation are reflected in the rates charged to retailelectric customers.  In January 2003, the Kentucky

 

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Commission reviewed KU’s FAC and, as part of the Order in that case,required that an independent audit be conducted to examine operational andmanagement aspects of both LG&E’s and KU’s fuel procurement functions.  The final report was issued in February 2004.The report’s recommendations related to documentation and process improvements.  Management Audit Action Plans were agreedupon by LG&E and the Kentucky Commission Staff in the second quarter of2004.  LG&E filed its first AuditProgress Report with the Kentucky Commission Staff in November 2004.  A second Audit Progress Report is due in May2005.

 

The Kentucky Commission requires public hearings at six-month intervalsto examine past fuel adjustments, and at two-year intervals to review pastoperations of the fuel clause and transfer of the then current fuel adjustmentcharge or credit to the base charges.  Nosignificant issues have been identified as a result of these reviews.

 

In December 2004, the Kentucky Commissioninitiated a two-year review of LG&E’s past operations of the fuel clauseand transfer of fuel costs from the fuel adjustment clause to base rates.  A public hearing on the matter was held onMarch 17, 2005.  An order by the KentuckyCommission is expected in April 2005. LG&E is seeking to increase the fuel component of base rates.  LG&E does not anticipate any issues willarise during the regulatory proceeding.

 

**DSM. **LG&E’srates contain a DSM provision.  Theprovision includes a rate mechanism that provides concurrent recovery of DSMcosts and provides an incentive for implementing DSM programs.  This provision allowed LG&E to recoverrevenues from lost sales associated with the DSM programs.  In May 2001, the Kentucky Commission approvedLG&E’s plan to continue DSM programs. This plan called for the expansion of the LG&E DSM programs into theservice territory served by KU and proposed a mechanism to recover revenuesfrom lost sales associated with DSM programs based on program plan engineeringestimates and post-implementation evaluations.

 

**Gas Supply Cost PBR Mechanism.  **SinceNovember 1, 1997, LG&E has operated under an experimental PBR mechanismrelated to its gas procurement activities.  LG&E’s rates are adjusted annually to recover its portion of thesavings (or expenses) incurred during each PBR year (12 months ending October31). Since its implementation on November 1, 1997, through October 31, 2004, LG&Ehas achieved $60.7 million in savings. Of that total savings amount, LG&E’sportion has been $22.7 million and the ratepayers’ portion has been $38.0million.  Pursuant to the extension ofLG&E’s gas supply cost PBR mechanism effective November 1, 2001, thesharing mechanism under PBR requires savings (and expenses) to be shared 25%with shareholders and 75% with ratepayers up to 4.5% of the benchmarked gascosts.  Savings (and expenses) in excessof 4.5% of the benchmarked gas costs are shared 50% with shareholders and 50%with ratepayers.  LG&E filed a reportand assessment with the Kentucky Commission in December 2004, seekingmodification and extension of the mechanism.

 

**ECR.**  InMay 2002, the Kentucky Commission initiated a periodic two-year review ofLG&E’s environmental surcharge.  Thereview included the operation of the surcharge mechanism, determination of theappropriateness of costs included in the surcharge mechanism, recalculation ofthe cost of debt to reflect actual costs for the period under review, finaldetermination of the amount of environmental revenues over-collected fromcustomers, and a final determination of the amount of environmental costs andrevenues to be “rolled-in” to base rates. A final order was issued in October 2002, in which LG&E was orderedto refund $0.3 million to customers over the four month period beginningNovember 2002 and ending February 2003. Additionally, LG&E was ordered to roll $4.1 million into base ratesand make corresponding adjustments to the monthly environmental surchargefilings to reflect that portion of environmental rate base now included in baserates.

 

In August 2002, LG&E filed an application with the KentuckyCommission to amend its compliance plan to

 

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allow recovery of the cost of new and additional environmentalcompliance facilities.  The estimatedcapital cost of the additional facilities is $71.1 million. A final order wasissued in February 2003, approving recovery of four new environmentalcompliance facilities totaling $43.1 million. A fifth project, expansion of the landfill facility at the Mill CreekStation, was denied without prejudice with an invitation to reapply forrecovery when required construction permits are approved.  Cost recovery through the environmentalsurcharge of the four approved projects began with bills rendered in April2003.

 

In January 2003, the Kentucky Commission initiated a six-month review ofLG&E’s environmental surcharge.  Afinal order was issued in April 2003, in which LG&E was ordered to refund$2.9 million it had previously over-collected from customers.  In July 2003, the Kentucky Commissioninitiated a two-year review of LG&E’s environmental surcharge.  A final order was issued in December 2003, inwhich LG&E was ordered to roll $15.2 million of environmental assets intobase rates and make corresponding adjustments to the monthly environmentalsurcharge filings to reflect that portion of environmental rate base nowincluded in base rates on a going-forward basis.  Additionally, LG&E was ordered to collect$0.2 million to correct for amounts under-collected from customers.  The rates of return for LG&E’s 1995 andpost-1995 plans were reset to 3.32% and 10.92%, respectively.

 

In June 2004, the Kentucky Commission issuedan order approving a settlement agreement that, among other things, revised therate of return for LG&E’s post-1995 plan to 10.72%, with an 11% return oncommon equity.  The order also approvedthe elimination of LG&E’s 1995 plan from its ECR billing mechanism, withall remaining costs associated with that plan to be included in their entiretyin base rates.

 

In December 2004, LG&E filed an application with the Kentucky Commissionto amend its compliance plan to allow recovery of the cost of new andadditional environmental compliance facilities, including the expansion of theMill Creek landfill. The estimated capital cost of the additional facilities is$40.2 million.  LG&E requested anoverall rate of return of 10.72%, including an 11% return on commonequity.  A final order in the case isanticipated in June 2005.

 

**MISO.  **LG&Eis a founding member of the MISO.  Membershipwas obtained in 1998 in response to and consistent with federal policyinitiatives.  In February 2002, LG&Eturned over operational control of its high voltage transmission facilities(100kV and above) to the MISO.  The MISOcurrently controls over 100,000 miles of transmission over 1.1 million square mileslocated in the northern Midwest between Manitoba, Canada and Kentucky.  In September 2002, FERC granted a 12.88% ROEon transmission facilities for LG&E and the rest of the MISO owners.  On February 18, 2005, the United States Courtof Appeals for the District of Columbia Circuit ruled that FERC did not provideproper notice that it would consider an incentive adder of 50 basis points, butaffirmed the September 2002 FERC order in all other respects.  Effective ROE, retroactive to February 1,2002, is 12.38% for LG&E and the original MISO owners.

 

In October 2001, the FERC issued an order requiring that the bundledretail load and grandfathered wholesale load of each member transmission ownerbe included in the current calculation of the MISO’s “cost-adder,” the Schedule10 charges designed to recover the MISO’s costs of operation, includingstart-up capital (debt) costs.  LG&E,along with several other transmission owners, opposed the FERC’s ruling on thismatter. The opposition was rejected by the FERC in 2002.   Later that year, the MISO’s transmissionowners, appealed the FERC’s decision to the United States Court of Appeals forthe District of Columbia Circuit.  Inresponse, in November 2002, the FERC requested that the Court issue a partialremand of its challenged orders to allow the FERC to revisit certain issues,and requested that the case be held in abeyance pending the agency’s resolutionof such issues.  The Court granted theFERC’s petition in December 2002.   InFebruary 2003, FERC issued an order reaffirming its position concerning thecalculation of the Schedule 10 charges and in July 2003 denied arehearing.  LG&E, along with severalother transmission owners, again petitioned the District Court of

 

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Columbia Circuit for review. In July 2004 the court affirmed the FERCruling.

 

In August 2004, the MISO filed its FERC-required proposed Transmissionand Energy Markets Tariff (“TEMT”).  InSeptember and October 2004, many MISO-related parties (including LG&E)filed proposals with the FERC regarding pending MISO-filed changes totransmission pricing principles, including the TEMT and elimination of RegionalThrough and Out Rates (“RTORs”). Additional filings of the companies beforeFERC in September 2004 sought to address issues relating to the treatment ofcertain “grandfathered” transmission agreements (“GFA’s”) should TEMT becomeeffective. The utility proposals generally seek to appropriately delay theRTORs and TEMT effective dates based upon errors in administrative orprocedural processes used by FERC or to appropriately limit potentialreductions in transmission revenues received by the utilities should the RTORs,TEMT or GFA structures be implemented. At present, existing FERC orders conditionally approve elimination ofRTORs and implementation of general TEMT rates in the MISO by spring 2005.  At this time, LG&E cannot predict theoutcome or effects of the various FERC proceedings described above, includingwhether such will have a material impact on the financial condition or resultsof operations of the companies. Financial consequences (changes in transmissionrevenues and costs) associated with the upcoming transmission market tariffchanges are subject to varying assumptions and calculations and are thereforedifficult to estimate. Changes in revenues and costs related to broader shiftsin energy market practices and economics are not currently estimable.  Should LG&E be ordered to exit MISO,current MISO rules may also impose an exit fee. LG&E is not able to predict the estimated outcome or economic impactof any of the MISO-related matters. While LG&E believes legal and regulatory precedent should permitmost or many of the MISO-related costs to be recovered in their rates charged tocustomers, they can give no assurance that state or federal regulators willultimately agree with such position with respect to all costs, components ortiming of recovery.

 

The MISO plans to implement a Day-ahead and Real-time market, includinga congestion management system in April 2005. This system will be similar tothe Locational Marginal Pricing (“LMP”) system currently used by the PJM RTOand contemplated in FERC’s SMD NOPR, currently being discussed.  The MISO filed with FERC a mechanism for recoveryof costs for the congestion management system. They proposed the addition of two new Schedules, 16 and 17.  Schedule 16 is the MISO’s cost recoverymechanism for the Financial Transmission Rights Administrative Service it willprovide.  Schedule 17 is the MISO’smechanism for recovering costs it will incur for providing Energy MarketingSupport Administrative Service.  The MISOtransmission owners, including LG&E, have objected to the allocation ofcosts among market participants and retail native load. FERC ruled in 2004 infavor of the MISO.

 

The Kentucky Commission opened an investigation into LG&E’smembership in the MISO in July 2003. The Kentucky Commission directed LG&Eto file testimony addressing the costs and benefits of the MISO membership bothcurrently and over the next five years and other legal issues surroundingcontinued membership.  LG&E engagedan independent third-party to conduct a cost benefit analysis on this issue.  The information was filed with the KentuckyCommission in September 2003.  Theanalysis and testimony supported the exit from the MISO, under certainconditions.  The MISO filed its owntestimony and cost benefit analysis in December 2003.  A final Kentucky Commission order wasexpected in the second quarter of 2004; that ruling has since been delayeduntil summer 2005 due to the Kentucky Commission’s request for additionaltestimony on the MISO’s Market Tariff filing at FERC.

 

**Kentucky Commission Administrative Case forSystem Adequacy. **InJune 2001, Kentucky’s Governor issued Executive Order 2001-771, which directedthe Kentucky Commission to review and study issues relating to the need for anddevelopment of new electric generating capacity in Kentucky.  In response to that Executive Order, in July2001 the Kentucky Commission opened Administrative Case No. 387 to review theadequacy of Kentucky’s generation capacity and transmission system.  Specifically, the items reviewed were theappropriate level of reliance on purchased power, the appropriate reservemargins to meet existing and future electric demand, the impact of spikes innatural gas prices on electric utility planning strategies, and the adequacy ofKentucky’s electric transmission facilities. In December 2001, the Kentucky Commission issued an order in which itnoted that LG&E is responsibly addressing the long-term supply needs ofnative load customers and that current reserve margins are appropriate.  However, due to the rapid pace of change inthe industry, the order also requires LG&E to provide an annual assessmentof supply resources, future demand, reserve margin, and the need for newresources.

 

Regarding the transmission system, the Kentucky Commission concludedthat the transmission system within Kentucky can reliably serve native load anda significant portion of the proposed new unregulated power plants. However, itwill not be able to handle the volume of transactions envisioned by FERCwithout future upgrades, the costs of which should be borne by those for whomthe upgrades are required.

 

The Kentucky Commission pledged to continue to monitor all relevantissues and advocate Kentucky’s interests at all opportunities.

 

**KentuckyCommission Strategic Blueprint.**  In February 2005, Kentucky’s Governor signedan executive order directing the Kentucky Commission, in conjunction with theCommerce Cabinet and the Environmental and Public Protection Cabinet, to ‘developa Strategic Blueprint for the continued use and development of electric energy.’This Strategic Blueprint will be designed to promote future investment inelectric infrastructure for the Commonwealth of Kentucky, to protect Kentucky’slow-cost electric advantage, to maintain affordable rates for all Kentuckians,and to preserve Kentucky’s commitment to environmental protection.  In March

 

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2005, theKentucky Commission established Administrative Case No. 2005-00090 to collectinformation from all jurisdictional utilities in Kentucky, including LG&E,pertaining to Kentucky electric generation, transmission and distributionsystems.  The Kentucky Commission mustprovide its Strategic Blueprint to the Governor in early August 2005.  LG&E must respond to the KentuckyCommission’s first set of data requests by the end of March 2005.

 

**FERC SMD NOPR. **InJuly 2002, the FERC issued a NOPR in Docket No. RM01-12-000 which wouldsubstantially alter the regulations governing the nation’s wholesaleelectricity markets by establishing a common set of rules, defined as SMD. TheSMD NOPR would require each public utility that owns, operates, or controlsinterstate transmission facilities to become an Independent TransmissionProvider (“ITP”), belong to an RTO that is an ITP, or contract with an ITP foroperation of its transmission assets. It would also establish a standardizedcongestion management system, real-time and day-ahead energy markets, and asingle transmission service for network and point-to-point transmissioncustomers. Review of the proposed rulemaking is underway and no time frame hasbeen established by the FERC for adoption of a final rule.  While it is expected that the SMD final rulewill affect LG&E’s revenues and expenses, the specific impact of therulemaking is not known at this time.

 

**Kentucky Commission Administrative Case forAffiliate Transactions. **InDecember 1997, the Kentucky Commission opened Administrative Case No. 369 toconsider Kentucky Commission policy regarding cost allocations, affiliatetransactions and codes of conduct governing the relationship between utilitiesand their non-utility operations and affiliates.  The Kentucky Commission intended to addresstwo major areas in the proceedings: the tools and conditions needed to preventcost shifting and cross-subsidization between regulated and non-utilityoperations; and whether a code of conduct should be established to assure thatnon-utility segments of the holding company are not engaged in practices thatcould result in unfair competition caused by cost shifting from the non-utilityaffiliate to the utility.  In early 2000,the Kentucky General Assemblyenacted legislation, House Bill 897, which authorized the Kentucky Commissionto require utilities that provide nonregulated activities to keep separateaccounts and allocate costs in accordance with procedures established by theKentucky Commission.  In the same bill,the General Assembly set forth provisions to govern a utility’s activitiesrelated to the sharing of information, databases, and resources between itsemployees or an affiliate involved in the marketing or the provision ofnonregulated activities and its employees or an affiliate involved in theprovision of regulated services. The legislation became law in July 2000 andLG&E has been operating pursuant thereto since that time.  In February 2001, the Kentucky Commissionpublished notice of their intent to promulgate new administrative regulationsunder the auspices of the new law.  Thiseffort is still ongoing.

 

**Wholesale Natural Gas Prices. **OnSeptember 12, 2000, the Kentucky Commission issued an order establishingAdministrative Case No. 384 – “An Investigation of Increasing Wholesale NaturalGas Prices and the Impacts of such Increase on the Retail Customers Served byKentucky’s Jurisdictional Natural Gas Distribution Companies”.

 

Subsequent to thisinvestigation, the Kentucky Commission issued an order on July 17, 2001,encouraging the natural gas distribution companies in Kentucky to take variousactions, among them to propose a natural gas hedge plan, considerperformance-based ratemaking mechanisms, and to increase the use of storage.

 

In May 2004, in Case No. 2004-148, LG&E proposed a hedge plan forthe 2004/2005 winter heating season relying upon LG&E’s storage to mitigatecustomer exposure to price volatility. In August 2004, the Kentucky Commissionapproved LG&E’s proposed hedge plan, validating the effectiveness ofstorage to mitigate potential volatility associated with high winter gas pricesby approving this natural gas hedge plan. The Kentucky Commission also ordered that LG&E need not file hedgeplans in the future unless it intended to utilize financial hedginginstruments.

 

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**Environmental Matters.  **LG&E is subject to SO2and NOx emission limits on its electric generating units pursuant to the CleanAir Act.  LG&E was exempt from PhaseI SO2 requirements due to its low emission rates. LG&E optedinto the Phase I NOx program to take advantage of the less stringentrequirements and installed burner modifications as needed to meet theselimitations.  LG&E’s strategy for Phase II SO2 reductions,which commenced January 1, 2000, is to increase FGD removal efficiency to delayadditional capital expenditures and may also include fuel switching orupgrading FGDs.  LG&E met the NOxemission requirements of the Act through installation of low-NOx burnersystems.  LG&E’s compliance plans are subject to many factorsincluding developments in the emission allowance and fuel markets, futureregulatory and legislative initiatives, and advances in clean air controltechnology.  LG&E will continue tomonitor these developments to ensure that its environmental obligations are metin the most efficient and cost-effective manner.

 

In September 1998, the EPA announced its final “NOx SIP Call” rulerequiring states to impose significant additional reductions in NOx emissionsby May 2003, in order to mitigate alleged ozone transport impacts on theNortheast region.  The Commonwealth ofKentucky SIP, which was approved by the EPA on June 24, 2003, requiresreductions in NOx emissions from coal-fired generating units to the 0.15lb./MMBtu level on a system-wide basis. In related proceedings in response to petitions filed by variousNortheast states, in December 1999, the EPA issued a final rule pursuant toSection 126 of the Clean Air Act directing similar NOx reductions from a numberof specifically targeted generating units including all LG&E units.  As a result of appeals to both rules, thecompliance date was extended to May 31, 2004. All LG&E generating units are in compliance with these NOx emissionsreduction rules.

 

LG&E has added significant NOx controls to its generating unitsthrough the installation of SCR systems, advanced low-NOx burners and neuralnetworks.  The NOx controls projectcommenced in late 2000 with the controls being placed into operation prior tothe 2004 Summer Ozone Season. As of December 31, 2004, LG&E incurred totalcapital costs of approximately $186 million to reduce its NOx emissions belowthe 0.15 lb./MMBtu level on a company-wide basis.  In addition, LG&E will incur additionaloperating and maintenance costs in operating new NOx controls.  LG&E believes its costs in this regard tobe comparable to those of similarly situated utilities with like generationassets. LG&E anticipated that such capital and operating costs are the typeof costs that are eligible for recovery from customers under its environmentalsurcharge mechanism and believed that a significant portion of such costs couldbe recovered.  In April 2001, theKentucky Commission granted recovery of these costs for LG&E.

 

LG&E is also monitoring several other air quality issues which maypotentially impact coal-fired power plants, including EPA’s revised air qualitystandards for ozone and particulate matter, measures to implement EPA’sregional haze rule, and EPA’s Clean Air Mercury Rule which regulates mercuryemissions from steam electric generating units and reductions in emissions ofSO2 and NOx required under the Clean Air Interstate Rule.  In addition, LG&E has worked with localregulatory authorities to review the effectiveness of remedial measures aimedat controlling particulate matter emissions from its Mill Creek Station.  LG&E previously settled a number ofproperty damage claims from adjacent residents and completed significantremedial measures as part of its ongoing capital construction program. LG&Ehas converted the Mill Creek Station to wet stack operation in an effort toresolve all outstanding issues related to particulate matter emissions.

 

LG&E owns or formerly owned three properties which are the locationof past MGP operations.  Variouscontaminants are typically found at such former MGP sites and environmentalremediation measures are frequently required. With respect to the sites, LG&E has completed cleanups, obtainedregulatory approval of site management plans, or reached agreements for otherparties to assume responsibility for cleanup. Based on currently available information, management estimates that itcould incur additional costs of $0.4 million for additional cleanup.  Accordingly, an accrual for this amount hasbeen recorded in the accompanying financial

 

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statements at December 31, 2004 and 2003.

 

See Note 11 of LG&E’s Notes to Financial Statements under Item 8for an additional discussion of environmental issues.

 

FUTURE OUTLOOK

 

Competition and Customer Choice

 

In the last several years, LG&E has taken many steps to keep itsrates low while maintaining high levels of

 

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customer satisfaction, including a reduction in the number ofemployees; aggressive cost cutting; an increase in focus on commercial,industrial and residential customers; an increase in employee involvement andtraining; and continuous modifications of its organizational structure.  LG&E will take additional steps to betterposition itself should retail competition come to Kentucky.

 

At this time, neither the Kentucky General Assembly nor the KentuckyCommission has adopted or approved a plan or timetable for retail electricindustry competition in Kentucky.  Thenature or timing of the ultimate legislative or regulatory actions regardingindustry restructuring and their impact on LG&E, which may be significant,cannot currently be predicted.  Somestates that have already deregulated have begun discussions that could lead tore-regulation.

 

In February2005, Kentucky’s Governor signed an executive order directing the KentuckyCommission, in conjunction with the Commerce Cabinet and the Environmental andPublic Protection Cabinet, to ‘develop a Strategic Blueprint for the continueduse and development of electric energy.’ This Strategic Blueprint will bedesigned to promote future investment in electric infrastructure for theCommonwealth of Kentucky, to protect Kentucky’s low-cost electric advantage, tomaintain affordable rates for all Kentuckians, and to preserve Kentucky’scommitment to environmental protection.” In March 2005, the Kentucky Commission established Administrative Case No.2005-00090 to collect information from all jurisdictional utilities inKentucky, including LG&E, pertaining to Kentucky electric generation,transmission and distribution systems. The Kentucky Commission must provide its Strategic Blueprint to the Governorin early August 2005.  LG&E mustrespond to the Kentucky Commission’s first set of data requests by the end ofMarch 2005.

 

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KU

 

RESULTS OF OPERATIONS

 

Net Income

 

KU’s net income in 2004 increased $42.1 million (46.0%) compared to2003.  The increase resulted primarilyfrom higher revenues, primarily in the retail sector, due to increased baserates resulting from the rate case order and higher volumes due to a warmersummer.  Offsetting the increase somewhatwere $2.7 million in operating expenses related to severe May and July stormsin 2004.

 

KU’s net income in 2003 decreased $2.0 million (2.1%) compared to2002.  The decrease resulted primarilyfrom increased depreciation expense due to plant additions, partially offset byincreased sales to retail and wholesale customers.

 

Revenues

 

The following table presents a comparison of operating revenues for theyears 2004 and 2003 with the immediately preceding year.

 
| **(in thousands)**                       | ** ** | **Increase (Decrease)  From Prior Period** | ** ** |
|------------------------------------------|------------|--------------------------------------------|------------|
| **Cause**                                | ** ** | **2004**                                   | ** ** | **2003** | ** ** |
| Retail sales:                            |       |                                       |       |   |   |
| Fuel clause adjustments                  |       | $                                          | 7,549      |   | $ | 20,959 |   |
| KU/LG&E Merger surcredit             |       | (2,593                                     | )          | (1,254 | ) |
| Environmental cost recovery surcharge    |       | 6,276                                      |       | 6,038 |   |
| Earnings sharing mechanism               |       | 7,749                                      |       | 8,718 |   |
| Demand side management                   |       | 1,011                                      |       | 365 |   |
| VDT surcredit                            |       | (486                                       | )          | (1,740 | ) |
| Rate and rate structure                  |       | 21,694                                     |       | — |   |
| Variation in sales volumes, and other    |       | 24,575                                     |       | (1,755 | ) |
| Provision for rate collections (refunds) |       | 13,285                                     |       | (24,015 | ) |
| Total retail sales                       |       | 79,060                                     |       | 7,316 |   |
| Wholesale sales                          |       | 21,999                                     |       | 20,751 |   |
| Other                                    |       | 2,525                                      |       | 2,047 |   |
| Total                                    |       | $                                          | 103,584    |   | $ | 30,114 |   |

 

Electric revenues increased in 2004 primarily due to an increase inrates and a change in the rate structure. New rates, implemented in July 2004 and theelimination of a volume dependent step rate structure, increased revenues by3.1% in 2004. Retail volumes increased 3.3% due to a 1.4% increase inthe customer base and 2.6% increase in demand due to weather. The KU servicearea experienced a warmer summer in 2004, partially offset by a milderwinter.  Cooling degree days for 2004increased 2.9% from 2003 and were 20% below the 20-year average while heatingdegree days decreased 6.8% from 2003 and were 4% below the 20-year average.Wholesale revenues increased due to a combination of a 14.2% increase in pricesand 1.7% higher volumes.

 

Electric revenues increased in 2003 primarily due to an increase in therecovery of fuel costs passed through the FAC and higher wholesale sales.  Retail volumes decreased 0.2% as lower salesdue to a milder summer than the previous year were offset by higher salesduring the winter, when weather was colder than the previous year.Coolingdegree days for 2003 decreased 38% from 2002 and were 21% below the 20-yearaverage while heating degree days increased 3% from 2002 and were 3% above the20-year average.  Wholesale revenues

 

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increased due to a combination of a 28.6% increase in volumes and 3.8%higher prices.

 

The provision for ratecollections (refunds) increased $13.3 million in 2004. This increase resultedprimarily from fuel ($18.1 million) and ECR ($12.8 million) accruals partiallyoffset by a decrease in the ESM ($17.6 million) accruals. The decrease in theprovision for rate collections (refunds) in 2003 from 2002 ($24.0 million)results primarily from a decrease in the ESM accruals ($13.5 million), adecrease in 2003 fuel accruals ($6.0 million), and a decrease in ECR accrualsduring 2003 ($4.5 million).

 

Expenses

 

Fuel for electric generation comprises a large component of KU’s totaloperating expenses.  KU’s Kentuckyjurisdictional electric rates are subject to a FAC whereby increases ordecreases are reflected in the FAC factor, subject to the approval of theKentucky Commission and passed through to KU’s retail customers.   KU’s municipal and Virginia jurisdictionalelectric rates contain a fuel adjustment clause whereby increases or decreasesin the cost of fuel are reflected in rates, subject to the approval of FERC andthe Virginia Commission, respectively.

 

Fuel for electric generation increased $26.1 million (9.8%) in 2004because of a 6% increase in the cost of fuel burned ($16.8 million) and anincrease in generation ($9.3 million).  Fuel for electric generation increased $15.8 million (6.3%) in 2003because of an increase in the cost of fuel burned ($18.9 million), partiallyoffset by a decrease in generation ($3.1 million).   The average delivered cost per MMBtu of coalpurchased was $1.56 in 2004, $1.47 in 2003 and $1.35 in 2002.

 

Power purchased expense in 2004 increased $4.2 million (3.0%) over2003, primarily due to an increase in purchases to meet off-system salesrequirements ($5.1 million) partially offset by a decrease in purchase price($0.9 million).    Power purchasedexpense in 2003 increased $8.7 million (6.6%) over 2002, primarily due to anincrease in purchases to meet off-system sales requirements ($15.1 million)partially offset by a decrease in purchase price ($6.4 million).

 

Other operation and maintenance expenses increased $0.8 million (0.4%)in 2004.

 

Other operation expenses decreased $0.4 million (0.3%) in 2004primarily due to:

•                  Decreasedbenefits expense ($3.7 million), primarily due to lower pension expense.

•                  The KU/LG&Emerger costs and the One Utility initiative costs were fully amortized in 2003,resulting in $2.9 million lower expense in 2004.

•                  Increasedemission allowance expense ($4.5 million).

•                  Incrementaloperations expense due to storm restoration costs related to severe storms inMay and July 2004 ($0.5 million).

•                  Increasedcombustion turbine operations expense ($0.9 million); 2003 included Alstomsettlement payments, lowering expense.

 

Maintenance expenses increased $0.6 million (1.0%) in 2004 primarilydue to:

•                  Increasedmaintenance expense due to storm restoration costs related to severe May andJuly storms ($2.2 million).

•                  Increasedcombustion turbine maintenance ($2.3 million); 2003 included Alstom settlementpayments, lowering expense.

•                  Decreasedexpense due to reclassification of maintenance expense to a regulatory asset($4.0 million) of costs related to the 2003 ice storm based on an order fromthe Kentucky Commission, to be amortized

 

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through June 2009.  KU earns a return of these amortized costs,which are included in KU’s jurisdictional operating expenses.

 

Property and other taxes increased $0.8million (4.8%) in 2004 primarily due to:

•                  Increasedproperty taxes of $0.6 million.

•                  Increasedpayroll taxes of $0.3 million.

 

Other operations and maintenance expenses decreased $0.2 million (0.1%)in 2003.

 

Otheroperation expenses increased $1.5 million (1.0%) in 2003 primarily due to:

•                  Increasedemployee benefits costs ($4.7 million).

•                  Increasedproperty insurance expenses ($1.4 million).

•                  Decreasedamortization of regulatory assets ($4.7 million).

 

Maintenance expenses decreased $2.6 million(4.2%) in 2003 primarily due to:

•                  Decreasedsteam generation and combustion turbine generation maintenance due tocancellation and postponement of scheduled outages ($5.1 million).

•                  Decreasedcommunications maintenance expenses ($1.0 million).

•                  Increasedmaintenance to electric distribution equipment due to an ice storm ($4.1million, net of $8.9 million in insurance recoveries).

 

Property and other taxes increased $0.9million (6.0%) in 2003 primarily due to:

•                  Increasedproperty taxes ($0.5 million)

•                  IncreasedKentucky Commission assessment ($0.4 million).

 

Depreciation and amortization increased $6.8 million (6.7%) in 2004 and$6.3 million (6.6%) in 2003 primarily due to an increase in plant in service.

 

Other income - net increased $3.0 million (66.2%) in 2004.  In 2003, write-offs of $1.3 million decreasedother income (see below).  In addition,2004 miscellaneous non-operating income was $0.6 million higher and gainsrelated to sale of property were $0.4 million higher. Other income - netdecreased $1.9 million (30.1%) in 2003 due primarily to a decrease in earningsfrom KU’s equity earnings in a minority interest ($3.4 million) and write-offfrom CWIP for terminated plant projects ($1.0 million) and a terminatedsoftware project ($0.6 million), partially offset by a decrease in benefitcosts ($1.3 million) and an increase in AFUDC income ($1.0 million) associatedprimarily with construction on NOx and CT projects.

 

Total interest expense increased $0.3 million (1.0%) in 2004 dueprimarily to increased borrowing from Fidelia ($9.0 million), partially offsetby savings from retired first mortgage debt ($4.4 million), lower cost ofinterest rate swaps ($3.5 million) and reduced borrowing from the money pool($0.8 million).

 

Total interest expense decreased $0.4 million (1.7%) in 2003 dueprimarily to savings from lower average interest rates on variable-ratelong-term bonds ($9.0 million) and an increase in interest income from interestrate swaps ($0.8 million), offset by interest expense on new fixed-rate debtwith Fidelia ($4.7 million) and additional expenses recognized frommark-to-market adjustments of underlying debt associated with the interest rateswaps ($5.1 million).

 

The weighted average interest rate on variable-rate long-term bonds for2004, 2003 and 2002 was 1.32%, 1.07% and 1.56%, respectively.  At December 31, 2004, 2003 and 2002, KU’spercentage of long-term bonds having a

 

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variable-rate, including the impact of interest rate swaps, was 48.6%at $349.0 million, 53.6% at $386.6 million and 73.8% at $369.5 million,respectively.  KU’s weighted average costof long-term debt, including amortization of debt expense and interest rateswaps, was 3.43%, 2.96%, and 3.30% at December 31, 2004, 2003, and 2002,respectively.  See Note 9 of KU’s Notesto the Financial Statements under Item 8.

 

Variations in income tax expense are largely attributable to changes inpre-tax income.  KU’s 2004 effectiveincome tax rate increased to 36.4% from the 35.4% rate in 2003.  See Note 7 of KU’s Notes to FinancialStatements 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 rateadjustments.  However, relatively lowrates of inflation in the past few years have moderated the impact on currentoperating results.

 

CRITICAL ACCOUNTING POLICIES/ESTIMATES

 

Preparation of financial statements and related disclosures incompliance with generally accepted accounting principles requires theapplication of appropriate technical accounting rules and guidance, as well asthe use of estimates.  The application ofthese policies necessarily involves judgments regarding future events,including legal and regulatory challenges and anticipated recovery of costs.  These judgments, in and of themselves, couldmaterially impact the financial statements and disclosures based on varyingassumptions, which may be appropriate to use. In addition, the financial and operating environment also may have asignificant effect, not only on the operation of the business, but on theresults reported through the application of accounting measures used inpreparing the financial statements and related disclosures, even if the natureof the accounting policies applied has not changed.  Specific risks for these critical accountingpolicies are described in the following paragraphs.  Each of these has a higher likelihood ofresulting in materially different reported amounts under different conditionsor using different assumptions.  Eventsrarely develop exactly as forecast and the best estimates routinely requireadjustment.  See also Note 1 of KU’sNotes to Financial Statements under Item 8.

 

Financial Instruments**-** KU usesover-the-counter interest-rate swap agreements to hedge its exposure tointerest rates.  Gains and losses oninterest-rate swaps used to hedge interest rate risk are reflected in interestcharges monthly.  KU uses sales ofmarket-traded electric forward contracts for periods less than one year tohedge the price volatility of its forecasted peak electric off-system sales.  Gains and losses resulting fromineffectiveness are shown in other income (expense) and to the extent that thehedging relationship has been effective, gains and losses are reflected inother comprehensive income.  Wholesalesales of excess asset capacity and wholesale purchases to be used to servenative load are treated as normal sales and purchases under SFAS No. 133, SFASNo. 138 and SFAS No. 149 and are not marked-to-market.   See Note 4 and Note 14 of KU’s Notes toFinancial Statements under Item 8.

 

Unbilled Revenue –At each month end KU prepares a financial estimate that projects electric usagethat has been used by customers, but not billed.  The estimated usage is based on allocatingthe daily system net deliveries between billed volumes and unbilled volumes.The allocation is based on a daily ratio of the number of meter reading cyclesremaining in the month to the total number of meter reading cycles in eachmonth.  Each day’s ratio is thenmultiplied by each day’s system net deliveries to determine an estimated billedand unbilled volume for each day of the accounting period.  At December 31, 2004, a 10% change inthese estimated quantities would cause revenue and accounts receivable tochange by approximately $4.8 million. See also Note 1 of KU’s Notes to Financial Statements under Item 8.

 

Allowance for Doubtful Accounts - At December 31, 2004 and 2003,the KU allowance for doubtful accounts

 

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was $0.6 million and $0.7 million, respectively.  The allowance is based on the ratio of theamounts charged-off during the last twelve months to the retail revenues billedover the same period multiplied by the retail revenues billed over the lastfour months.  Accounts with no paymentactivity are charged-off after four months.

 

Benefit Plan Accounting -KU’s costs of providing defined-benefit pension retirement plans is dependentupon a number of factors, such as the rates of return on plan assets,healthcare cost trend rates, discount rate, contributions made to the plan, andother actuarial assumptions used to value benefit obligations.  In 2002, KU was required to recognize a minimum liability of $17.5 millionas prescribed by SFAS No. 87 *Employers’ Accounting forPensions*since the fair value of the plan assets was less than theaccumulated benefit obligation at that time. During 2002, the combination of poor market performance and historicallylow corporate bond rates created a divergence in the potential value of thepension liabilities and the actual value of the pension assets.  The liability was recorded as a reduction toother comprehensive income, and did not affect net income.  In 2003, KU recognized a reduction of theminimum pension liability of $7.7 million. During 2004, KU recognized an additional minimum pension liability of$12.4 million.  If the fair value of theplan assets exceeds the accumulated benefit obligation, the recorded liabilitywill be reduced and other comprehensive income will be restored in theconsolidated balance sheet.

 

Should poor marketconditions return, these conditions could result in an increase in KU’sunfunded accumulated benefit obligations and future pension expense.  The primary assumptions that drive the valueof the unfunded accumulated benefit obligations are the discount rate andexpected return on plan assets.

 

The assumptions used in the measurement of KU’s net periodic benefitcost are shown in the following table:

 
| ** **                                | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|-------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
|                                      |       |     |       |     |       |     |       |
| Discount  rate                            |       | 6.25     | %          | 6.75     | %          | 7.25     | %          |
| Expected long-term  return on plan assets |       | 8.50     | %          | 9.00     | %          | 9.50     | %          |
| Rate of  compensation increase            |       | 3.50     | %          | 3.75     | %          | 4.25     | %          |

 

KU made contributions tothe pension plan of $43.4 million in January 2004 and $10.2 million during2003.

 

A 1% increase or decreasein the assumed discount rate could have an approximate $26.8 million positiveor negative impact to the accumulated benefit obligation of KU.

 

See also Note 6 and Note 14 of KU’s Notes to Financial Statements underItem 8.

 

Regulatory Mechanisms – Judgments and uncertainties include futureregulatory decisions, the impact of deregulation and competition on theratemaking process and external regulator decisions.

 

Regulatory assetsrepresent incurred costs that have been deferred because they are probable offuture recovery in customer rates based upon Kentucky Commission orders.  Regulatory liabilities generally representobligations to make refunds to customers for previous collections based uponorders by the Kentucky Commission. Management believes, based on orders, the existing regulatory assets andliabilities are probable of recovery.  This determination reflects the current regulatory climate in thestate.  If future recovery of costs ceasesto be probable the assets would be required to be recognized in current periodearnings.

 

See also Note 3 of KU’sNotes to Financial Statements under Item 8.

 

Income Taxes - Incometaxes are accounted for under SFAS No.109. In accordance with this statement, deferred tax assets and liabilitiesare recognized for the future tax consequences attributable to differencesbetween the financial statement carrying amounts of existing assets andliabilities and their respective tax bases, as measured by enacted tax ratesthat are expected to be in effect in the periods when the deferred tax assetsand liabilities are expected to be settled or realized. Significant judgment isrequired in determining the provision for income taxes, and there are manytransactions for which the ultimate tax outcome is uncertain.  

 

To provide for theseuncertainties or exposures, an allowance is maintained for tax contingencies,the balance of which management believes is adequate.  Tax contingencies are analyzed periodicallyand adjustments are made when events occur to warrant a change. The company iscurrently in the examination phase of IRS audits for the years 1999 to 2003 andexpects some or all of these audits to be completed within the next 12months.  The results of audit assessmentsby taxing authorities are not anticipated to have a material adverse effect oncash flows or results of operations.

 

H. R. 4520, known as the“American Jobs Creation Act of 2004” allows electric utilities to take adeduction of up to 3% of their generation taxable income in 2005. On astand-alone basis, KU expects to generate a deduction in 2005 which will reduceKU’s effective tax rate by less than 1%. See Note 1 and Note 7 of KU’s Notes toFinancial Statements under Item 8.

 

Kentucky House Bill 272,also known as Kentucky’s Tax Modernization Plan, was signed into law in March2005.  This bill contains a number ofchanges in Kentucky’s tax system, including the reduction of the Corporateincome tax rate from 8.25% to 7% effective January 1, 2005, and a furtherreduction to 6% effective January 1, 2007. The impact of these reduced rates is expected to decrease KU’s incometax expense in future periods. Furthermore, these reduced rates will result in the reversal ofaccumulated temporary differences at lower rates than originally provided.  KU is presently evaluating the impact of thisand other changes to the Kentucky tax system, however, no material adverseimpacts on cash flows or results of operations are expected.

 

KU is subject to periodicchanges in state tax law, regulation or interpretation, as well as enforcementproceedings.  KU is currently undergoinga routine Kentucky sales tax audit for the period January 1996 to July2000.  The possible assessment or amountat issue is not known at this time, but is not expected to have a materialadverse effect on cashflows or results of operations.  

 

See Note 1 and Note 7 ofKU’s Notes to Financial Statements under Item 8.

 

Deferred Income Taxes -KU expects to have adequate levels of taxable income to realize its recordeddeferred tax assets.  See Note 7 of KU’sNotes to Financial Statements under Item 8 for a breakdown of deferred taxassets.    

 

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NEW ACCOUNTINGPRONOUNCEMENTS

 

The following recent accounting pronouncements affected KU in 2004 and2003:

 

SFAS No. 143

 

SFAS No. 143 was issued in 2001. SFAS No. 143 establishes accounting and reporting standards forobligations associated with the retirement of tangible long-lived assets andthe associated asset retirement costs.

 

The effective implementation date for SFAS No. 143 was January 1,2003.  Management has calculated theimpact of SFAS No. 143 and FERC Final Order No. 631 issued in Docket No.RM02-7.  As of January 1, 2003, KUrecorded ARO assets in the amount of $8.6 million and liabilities in the amountof $18.5 million.  KU also recorded acumulative effect adjustment in the amount of $9.9 million to reflect theaccumulated depreciation and accretion of ARO assets at the transition dateless amounts previously accrued under regulatory depreciation.  KU recorded offsetting regulatory assets of$9.9 million, pursuant to regulatory treatment prescribed under SFAS No.71.  Also pursuant to SFAS No. 71, KUrecorded regulatory liabilities in the amount of $0.9 million offsetting removalcosts previously accrued under regulatory accounting in excess of amountsallowed under SFAS No. 143.

 

Had SFAS No. 143 been in effect for the 2002 reporting period, KU wouldhave established asset retirement obligations as described in the followingtable:

 
| **(in thousands)**                   | ** ** | ** ** | ** ** |
|--------------------------------------|------------|------------|------------|
| Provision at  January 1, 2002   |       | $          | 17,331     |   |
| Accretion  expense                   |       | 1,146      |       |
| Provision at  December 31, 2002 |       | $          | 18,477     |   |

 

As of December 31, 2004, KU recorded ARO assets, net ofaccumulated depreciation, of $6.7 million and liabilities of $21.0million.  As of December 31, 2003,KU had ARO assets, net of accumulated depreciation, of $6.9 million andliabilities of $19.7 million.  KUrecorded offsetting regulatory assets of $12.8 million and $11.3 million andregulatory liabilities of $1.4 million and $1.2 million as of December 31,2004 and 2003, respectively.

 

For the year ended December 31, 2004, KU recorded ARO accretionexpense of $1.3 million, ARO depreciation expense of $0.2 million and anoffsetting regulatory credit in the income statement of $1.5 million, pursuantto regulatory treatment prescribed under SFAS No. 71. For the year ended December 31,2003, KU recorded ARO accretion expense of $1.2 million, ARO depreciationexpense of $0.2 million and an offsetting regulatory credit in the incomestatement of $1.4 million.  SFAS No. 143has no impact on the results of operations of KU.

 

KU AROs are primarily related to final retirement of assets associatedwith generating units.  For assetsassociated with AROs, the removal cost accrued through depreciation underregulatory accounting is established as a regulatory asset or liabilitypursuant to regulatory treatment prescribed under SFAS No. 71.  For the years ended December 31, 2004and 2003, KU recorded $0.3 million for both periods in depreciation expenserelated to the cost of removal of ARO related assets.  An offsetting regulatory liability wasestablished pursuant to regulatory treatment prescribed under SFAS No. 71.

 

KU also continues to include a cost of removal component in depreciationfor assets that do not have a legal ARO. As of December 31, 2004 and 2003,KU has segregated this cost of removal, embedded in accumulated

 

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depreciation, of $266.8 million and $256.7 million, respectively, inaccordance with FERC Order No. 631*.*  For reporting purposes in its ConsolidatedBalance Sheets included in Item 8, KU has presented this cost of removal as aregulatory liability pursuant to SFAS No. 71.

 

KU transmission and distribution lines largely operate under perpetualproperty easement agreements which do not generally require restoration uponremoval of the property.  Therefore,under SFAS No. 143, no material asset retirement obligations are recorded fortransmission and distribution assets.

 

EITF No. 02-03

 

KU adopted EITF No. 98-10**effective January 1,1999.  This pronouncement required thatenergy trading contracts be marked to market on the balance sheet, with thegains and losses shown net in the income statement.  Effective January 1, 2003, KU adoptedEITF No. 02-03.  EITF No. 02-03established the following:

 

•                  RescindedEITF No. 98-10,

**•****                 **Contractsthat do not meet the definition of a derivative under SFAS No. 133 should notbe marked to fair market value, and

•                  Revenuesshould be shown in the income statement net of costs associated with tradingactivities, whether or not the trades are physically settled.

 

With the rescission of EITF No. 98-10, energy trading contracts that donot also meet the definition of a derivative under SFAS No. 133 must beaccounted for as executory contracts. Contracts previously recorded at fair value under EITF No. 98-10 thatare not also derivatives under SFAS No. 133 must be restated to historical costthrough a cumulative effect adjustment. The rescission of this standard had no impact on financial position orresults of operations of KU since all forward and option contracts marked tomarket under EITF No. 98-10 were 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 againstelectric operating revenue to reflect this accounting change.  KU applied this guidance to previouslyreported 2002 balances as shown below. The reclassifications had no impact onpreviously reported net income or common equity.

 
| **(in thousands)**                                        | ** ** | ** ** | ** ** |   |
|-----------------------------------------------------------|------------|------------|------------|--------|
| Gross  electric operating revenues as previously reported |       | $          | 888,219    |   |   |
| Less costs  reclassified from power purchased             |       | 26,555     |       |   |
| Net electric  operating revenues                          |       | $          | 861,664    |   |   |
|                                                      |       |       |       |   |
| Gross power  purchased as previously reported             |       | $          | 157,955    |   |   |
| Less costs  reclassified to revenues                      |       | 26,555     |       |   |
| Net power  purchased                                      |       | $          | 131,400    |   |
|                                                           |            |            |            |        |  |  |

 

SFAS No. 150

 

In May 2003,the Financial Accounting Standards Board issued SFAS No. 150, which waseffective immediately for financial instruments entered into or modified afterMay 31, 2003, and otherwise was effective for interim reporting periodsbeginning after June 15, 2003, except for certain instruments and certainentities which have been deferred by the FASB. Such deferrals do not affect KU.

 

KU has no financial instruments that fall within thescope of SFAS No. 150.

 

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FIN 46

 

In January 2003, the Financial Accounting Standards Board issuedFIN 46.  FIN 46 requires certain variableinterest entities to be consolidated by the primary beneficiary of the entityif the equity investors in the entity do not have the characteristics of acontrolling financial interest or do not have sufficient equity at risk for theentity to finance its activities without additional subordinated financialsupport from other parties.  FIN 46 waseffective immediately for all new variable interest entities created oracquired after January 31, 2003. For variable interest entities created or acquired prior to February 1,2003, the provisions of FIN 46 must have been applied for the first interim orannual period beginning after June 15, 2003.

 

In December 2003, FIN 46 was revised, delaying the effective datesfor certain entities created before February 1, 2003, and making otheramendments to clarify application of the guidance.  For potential variable interest entitiesother than special purpose entities, FIN 46R was required to be applied nolater than the end of the first fiscal year or interim reporting period endingafter March 15, 2004.  The originalguidance under FIN 46 was applicable, however, for all special purpose entitiescreated prior to February 1, 2003, at the end of the first interim orannual reporting period ending after December 15, 2003.  FIN 46R may be applied prospectively with acumulative-effect adjustment as of the date it is first applied, or byrestating previously issued financial statements with a cumulative-effectadjustment as of the beginning of the first year restated.  FIN 46R also requires certain disclosures of anentity’s relationship with variable interest entities. The adoption of FIN 46and FIN 46R had no impact on the financial position or results of operationsfor KU.

 

Although KU holds investment interests in OVEC and EEI, it is not theprimary beneficiary of OVEC or EEI, and, therefore, neither are consolidatedinto the financial statements of KU.  KUand 11 other electric utilities are participating owners of OVEC, located inPiketon, Ohio.  OVEC owns and operatestwo power plants that burn coal to generate electricity, Kyger Creek Station inOhio and Clifty Creek Station in Indiana. KU’s share is 2.5%, representing approximately 55 Mw of generationcapacity.

 

KU’s original investment in OVEC was made in 1952.  KU’s investment in OVEC is the equivalent of2.5% of OVEC’s common stock and is accounted for under the cost method ofaccounting.  As of December 31,2004, KU’s investment in OVEC totaled $0.3 million. KU’s maximum exposure toloss as a result of the involvement with OVEC is limited to the value of theinvestments.  In the event of theinability of OVEC to fulfill its power provision requirements, KU wouldsubstitute such power supply with either owned generation or market purchasesand would generally recover associated incremental costs through regulatoryrate mechanisms.  See Note 11 of KU’sNotes to Financial Statements under Item 8 for further discussion ofdevelopments regarding KU’s ownership interests and power purchase rights.

 

KU owns 20% of the common stock of EEI, which owns and operates a1,000-Mw generating station in southern Illinois.  KU is entitled to take 20% of the availablecapacity of the station.  Purchases fromEEI are made under a contractual formula which has resulted in costs which wereand are expected to be comparable to the cost of other power generated byKU.  This contract governing thepurchases from EEI will terminate on December 31, 2005.  Such power equated to approximately 10% of KU’snet generation system output in 2004.

 

KU’s original investment in EEI was made in 1953.  KU’s investment in EEI is accounted for underthe equity method of accounting and, as of December 31, 2004, totaled$13.4 million.  KU’s direct exposure toloss as a result of its involvement with EEI is generally limited to the valueof its investment.  In the event of theinability of EEI to fulfill its power provision requirements, KU wouldsubstitute such power supply with either owned generation or market purchasesand would generally recover associated incremental costs through regulatory

 

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rate mechanisms.

 

FSP 106-2

 

In May 2004,the FASB finalized FSP 106-2 with guidance on accounting for subsidies providedunder the Medicare Act which became law in December 2003.  FSP 106-2 is effective for the first interimor annual period beginning after June 15, 2004.  FSP 106-2 does not have a material impact onKU.

 

FSP 109-1

 

In December 2004,the FASB finalized FSP 109-1*,*which**requires the tax deduction on qualifiedproduction activities to be treated as a special deduction in accordance withFAS 109.  FSP 109-1 became effective December 21,2004, and does not have a material impact on KU.

 

LIQUIDITY AND CAPITAL RESOURCES

 

KU uses net cash generated from its operations and external financing(including financing from affiliates) to fund construction of plant andequipment and the payment of dividends. KU believes that such sources of funds will be sufficient to meet theneeds of its business in the foreseeable future.

 

As of December 31, 2004, KU is in a negative working capitalposition in part because of the classification of certain variable-ratepollution control bonds that are subject to tender for purchase at the optionof the holder as current portion of long-term debt. KU expects to cover any workingcapital deficiencies with cash flow from operations, money pool borrowings, andborrowings from Fidelia.

 

Operating Activities

 

Cash provided by operations was $185.9 million, $233.4 million and$175.8 million 2004, 2003, and 2002, respectively.  The 2004 decrease compared to 2003 of $47.5million was primarily due to an increase in accounts receivable of $63.0million, including the termination of the accounts receivable securitizationprogram, additional pension funding of $33.2 million and lower environmentalcost recovery of $14.2 million. These decreases were partially offset by higherearnings of $42.1 million, higher accounts payable of $13.5 million and receiptof a litigation settlement of $11.4 million. The 2003 increase compared to 2002of $57.6 million was primarily the result of an increase in accrued incometaxes of $19.4 million, an increase in deferred income taxes of $17.3 million,a decrease in pension funding of $6.5 million and the change in accountsreceivable balances of $4.6 million, including the sale of accounts receivablethrough the accounts receivable securitization program.  See Note 4 of KU’s Notes to FinancialStatements under Item 8 for a discussion of accounts receivable securitization.

 

Investing Activities

 

KU’s primary use of funds for investing activities continues to be forcapital expenditures.  Capitalexpenditures were $157.6 million, $341.9 million and $237.9 million in 2004,2003 and 2002, respectively.  KU expectsits capital expenditures for 2005 and 2006 to total approximately $448 million,which consists primarily of construction estimates associated with installationof FGDs on Ghent units, totaling $195.9 million, as described in the section titled“Environmental Matters,” the construction of Trimble County Unit 2, totaling$37.4 million, and on-going construction on generation and distribution assets.

 

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Net cash used for investing activities decreased $185.2 million in 2004compared to 2003 primarily due to the level of construction expenditures.  NOx expenditures were approximately $45.0million in 2004 and $110.0 million in 2003, while CT expenditures wereapproximately $13.7 million in 2004 and $117.2 million in 2003. Net cash usedfor investment activities increased $107.5 million in 2003 compared to 2002 dueto increased CT and NOx expenditures.

 

Financing Activities

 

Net cash inflows (outflows) from financing activities were $(30.6)million, $107.8 million and $64.2 million in 2004, 2003 and 2002, respectively.

 

In January 2004, KU entered into an unsecured long-term loan fromFidelia totaling $50 million with an interest rate of 4.39% that matures in January 2012.  The proceeds were used to fund a pensioncontribution and to repay other debt obligations.

 

In May 2004, KU redeemed $4.8 million of its Series 14 PollutionControl Bonds which were initially issued in the amount of $7.2 million.

 

In October 2004, KU completed a refinancing transaction regarding$50 million in existing pollution control indebtedness.  The original indebtedness, 5.75% PollutionControl Bonds, Series 9, due December 1, 2023, was discharged in November 2004,with the proceeds from the replacement indebtedness, KU Pollution ControlBonds, Series 17, due October 1, 2034, which carries a variable, auctionrate of interest.  The call premium andunamortized debt expense of the Series 9 bonds are deferred assets beingamortized over the life of the Series 17 bonds.

 

In June 2003, KU’sfirst mortgage bond, 6.32% Series Q of $62 million matured.

 

In November 2003, KUcalled its first mortgage bond, Series P 8.55% of $33 million, due in 2027, andreplaced it with a loan from Fidelia.

 

During 2003, KU enteredinto four long-term loans from Fidelia totaling $283 million.  $100 million of this total is unsecured andthe remaining $183 million is collateralized by a pledge of substantially allassets of KU that is subordinated to the first mortgage bond lien.

 

In May 2002, KU issued $37.9 million variable-rate pollution controlSeries 12, 13, 14 and 15 due February 1, 2032, and exercised its calloption on $37.9 million, 6.25% pollution control Series 1B, 2B, 3B, and 4B due February 1,2018.

 

In September 2002, KU issued $96 million variable-rate pollutioncontrol 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 CapitalRequirements

 

Future capital requirements may be affected in varying degrees byfactors such as electric energy demand load growth, changes in constructionexpenditure levels, rate actions by regulatory agencies, new legislation,market entry of competing electric power generators, changes in environmentalregulations and other regulatory requirements. KU anticipates funding future capital requirements through operatingcash flow, debt, and/or infusion of capital from its parent.

 

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KU has a variety of intercompany funding alternatives available to meetits capital requirements.  KU participatesin an intercompany money pool agreement wherein LG&E Energy and/or LG&Emake funds available to KU at market-based rates up to $400 million.  Fidelia also provides long-term intercompanyfunding to KU.

 

Certain regulatoryapprovals are required for the Company to incur additional debt.  The Virginia Commission and the SEC authorizethe issuance of short-term debt while the Kentucky Commission, the VirginiaCommission, and the Tennessee Regulatory Authority authorize issuance oflong-term debt.  As of December 31,2004 the Company has received approvals from the Virginia Commission and theSEC to borrow up to $400 million in short-term funds.

 

KU’s debt ratings as of December 31, 2004, were:

 
| ** **            | ** ** | **Moody’s** | ** ** | **S&P** | ** ** |
|-----------------------|------------|------------------|------------|-------------|------------|
|                  |       |             |       |        |       |
| First  mortgage bonds |       | A1               |       | A           |       |
| Preferred  stock      |       | Baa1             |       | BBB-        |       |
| Commercial  paper     |       | P-1              |       | A-2         |       |

 

These ratings reflect the views of Moody’s and S&P.  A security rating is not a recommendation tobuy, sell or hold securities and is subject to revision or withdrawal at anytime by the rating agency.

 

Contractual Obligations

 

The following is providedto summarize KU’s contractual cash obligations for periods after December 31,2004.  KU anticipates cash fromoperations and external financing will be sufficient to fund futureobligations.

 
| **(in thousands)**

**Contractual Cash Obligations** | ** ** | **Payments Due by Period** | ** **   |
|------------------------------------------------------|------------|----------------------------|--------------|
| ** **                                           | **2005**   | ** **                 | **2006**     | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** | **Thereafter** | ** ** | **Total** | ** ** |
| Short-term debt (a)                                  |       | $                          |  34,820 |   | $ |  — |   | $ | — |   | $ | — |   | $ |  — |   | $ | — |   | $ | 34,820 |   |
| Long-term debt                                       |       | 162,130                    |         | 36,000 |   | 58,088 |   | — |   | — |   | 469,993 | (b) | 726,211 |   |
| Unconditional power purchase obligations (c)         |       | 40,098                     |         | 41,141 |   | 42,625 |   | 43,690 |   | 45,138 |   | 655,720 |   | 868,412 |   |
| Coal purchase obligations (d)                        |       | 263,418                    |         | 156,613 |   | 64,886 |   | 35,808 |   | — |   | — |   | 520,725 |   |
| Retirement obligations (e)                           |       | 6,564                      |         | 6,915 |   | 7,236 |   | 7,479 |   | 7,757 |   | — |   | 35,951 |   |
| Other long-term obligations (f)                      |       | 14,771                     |         | — |   | — |   | — |   | — |   | — |   | 14,771 |   |
| Total contractual cash obligations                   |       | $                          | 521,801      |   | $ | 240,669 |   | $ | 172,835 |   | $ | 86,977 |   | $ | 52,895 |   | $ | 1,125,713 |   | $ | 2,200,890 |   |

 

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(a)          Represents borrowings from affiliated companydue within one year.

(b)         Includes long-term debt of $87.1 millionclassified as current liabilities because these bonds are subject to tender forpurchase at the option of the holder and to mandatory tender for purchase uponthe occurrence of certain events. Maturity dates for these bonds range from 2024 to 2032.  KU does not expect to pay these amounts in2005.

(c)          Represents future minimum payments under OVEC,OMU and EEI purchased power agreements through 2024.

(d)         Represents contracts to purchase coal.

(e)          Represents currently projected cash flows forpension plans and other post-employment benefits as calculated by the actuary.

(f)            Represents construction commitments.

 

Sale and Leaseback Transaction

 

KU is aparticipant in a sale and leaseback transaction involving its 62% interest intwo jointly-owned CTs at KU’s E.W. Brown generating station (Units 6 and7).  Commencing in December 1999,LG&E and KU entered into a tax-efficient, 18-year lease of the CTs.  KU and LG&E have provided funds to fullydefease the lease,

 

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and haveexecuted an irrevocable notice to exercise an early purchase option containedin the lease after 15.5 years. The financial statement treatment of thistransaction is no different than if KU had retained its ownership. The leasingtransaction was entered into following receipt of required state and federalregulatory approvals.

 

In case ofdefault under the lease, KU is obligated to pay to the lessor its share ofcertain fees or amounts. Primary events of default include loss or destructionof the CTs, failure to insure or maintain the CTs and unwinding of thetransaction due to governmental actions. No events of default currently exist with respect to the lease.  Upon any termination of the lease, whether bydefault or expiration of its term, title to the CTs reverts jointly to KU andLG&E.

 

At December 31,2004, the maximum aggregate amount of default fees or amounts, which decreaseover the term of the lease, was $9.5 million, of which KU would be responsiblefor $5.9 million (62%).  KU has madearrangements with LG&E Energy, via guarantee and regulatory commitment, forLG&E Energy to pay its full portion of any default fees or amounts.

 

MARKET RISKS

 

KU is exposed to market risks from changes in interest rates andcommodity prices.  To mitigate changes incash flows attributable to these exposures, KU uses various financialinstruments including derivatives. Derivative positions are monitored using techniques that include marketvalue and sensitivity analysis. See Notes 1 and 4 of KU’s Notes to FinancialStatements under Item 8.

 

Interest Rate Sensitivity

 

KU has short-term and long-term variable-rate debt obligationsoutstanding.  At December 31, 2004,the potential change in interest expense associated with a 1% change in baseinterest rates of KU’s variable-rate debt is estimated at $3.8 million afterthe impact of interest rate swaps.

 

Interest rate swaps are used to hedge KU’s underlying debtobligations.  These swaps hedge specificdebt issuances and, consistent with management’s designation, are accordedhedge accounting treatment.  See Note 4of KU’s Notes to Financial Statements under Item 8.

 

As of December 31, 2004, KU has swaps with a combined notionalvalue of $103 million.  The swapsexchange fixed-rate interest payments for floating rate interest payments on KU’sSeries P and R first mortgage bonds.  Thepotential loss in fair value resulting from a hypothetical 1% adverse movementin base interest rates is estimated at $1.5 million as of December 31,2004.  This estimate is derived fromthird-party valuations. Changes in the market value of these swaps, if held tomaturity, will have no effect on KU’s net income or cash flow.  See Note 4 of KU’s Notes to FinancialStatements under Item 8.

 

In February 2004, KU terminated the swaps it had in place at December 31,2003 related to the Series 9 pollution control bonds.  The notional amount of the terminated swapwas $50 million and KU received a payment of $2.0 million as part of thetermination.  The swap was terminatedbecause it was no longer an effective hedge of the underlying bond.

 

Commodity PriceSensitivity

 

KU has limited exposure to market price volatility in prices of fueland electricity, since its retail tariffs include the FAC commodity pricepass-through mechanism.  KU is exposed tomarket price volatility of fuel and

 

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electricity in its wholesale activities.

 

# **Energy Trading & Risk Management Activities**

# ** **

KU conducts energy trading and risk management activities to maximizethe value of power sales from physical assets it owns, in addition to thewholesale sale of excess asset capacity. Certain energy trading activities are accounted for on a mark-to-marketbasis in accordance with SFAS No. 133, SFAS No. 138 and SFAS No. 149. Wholesalesales of excess asset capacity are treated as normal sales under these pronouncementsand are not marked to market.  To beeligible for the normal sales exclusion under SFAS No. 133, sales are limitedto the forecasted excess capacity of KU’s generation assets over what is neededto serve native load.  To be eligible forthe normal purchases exclusion under SFAS No. 133 purchases must be used to serveKU’s native load. Without the normal sales and purchases exclusion thesetransactions would be considered derivatives and marked to market under SFAS No.133.

 

The rescission ofEITF No. 98-10 for fiscal periods ending after December 15, 2002, had noimpact on KU’s energy trading and risk management reporting as all forward andoption contracts marked to market under EITF No. 98-10 are also within thescope of SFAS No. 133.

 

The table belowsummarizes KU’s energy trading and risk management activities for 2004 and2003:

 
| **(in thousands)**                                                     | ** ** | **2004** | ** ** | **2003** | ** ** |
|------------------------------------------------------------------------|------------|----------|------------|----------|------------|
| Fair value  of contracts at beginning of period, net asset (liability) |       | $        | 572        |     | $          | (156 | ) |
| Fair value  of contracts when entered into during the period           |       | (75      | )          | 2,654    |       |
| Contracts  realized or otherwise settled during the period             |       | (858     | )          | (569     | )          |
| Changes in  fair values due to changes in assumptions                  |       | 164      |       | (1,357   | )          |
| Fair value  of contracts at end of period, net (liability) asset       |       | $        | (197       | )   | $          | 572 |   |

 

No changes to valuationtechniques for energy trading and risk management activities occurred during2004.  Changes in market pricing,interest rate and volatility assumptions were made during both years. Theoutstanding mark-to-market value is sensitive to changes in prices, price volatilities,and interest rates.  The Companyestimates that a movement in prices of $1 and a change in interest andvolatilities of 1% would not result in a change of a material amount.  All contracts outstanding at December 31,2004 have a maturity of less than one year and are valued using prices activelyquoted for proposed or executed transactions or quoted by brokers.

 

KU maintains policies intended to minimize credit risk and revaluescredit exposures daily to monitor compliance with those policies.  At December 31, 2004, 100% of the tradingand risk management commitments were with counterparties rated BBB-/Baa3equivalent or better.

 

Accounts Receivable Securitization

 

On February 6, 2001, KU implemented an accounts receivablesecuritization program.  KU terminatedthe accounts receivable securitization program in January 2004, and in May2004, dissolved its inactive accounts receivable securitization-relatedsubsidiary, KU R. The purpose of this program was to enable KU to acceleratethe receipt of cash from the collection of retail accounts receivable, therebyreducing dependence upon more costly sources of working capital. Thesecuritization program allowed for a percentage of eligible receivables to besold.  Eligible receivables weregenerally all receivables associated with retail sales that had standard termsand were not past due.  KU was able toterminate this program at any time without penalty.

 

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As part of the program, KU sold retail accounts receivable to KUR.  Simultaneously, KU R entered into twoseparate three-year accounts receivable securitization facilities with twofinancial institutions and their affiliates whereby KU R could sell, on arevolving basis, an undivided interest in certain of its receivables andreceive up to $50 million from unrelated third-party purchasers.  The effective cost of the receivable programwas comparable to KU’s lowest cost source of capital, and was based on primerated commercial paper.  KU retainedservicing rights of the sold receivables through two separate servicingagreements with the third-party purchasers. KU obtained an opinion from independent legal counsel indicating thesetransactions qualified as a true sale of receivables.

 

To determine KU’s retained interest, the proceeds on the sale ofreceivables to the financial institutions was netted against the amount ofeligible receivables sold by KU to KU R. Interest expense, program fees, and facility fees paid to the financialinstitutions and an allowance for doubtful accounts were deducted to arrive atthe future value of retained interest. The future value was discounted using the prime rate plus 25 basispoints, assuming a 45-day receivable life. No material pre-tax gains or losses from the sale of the receivablesoccurred during 2004, 2003 and 2002.  KU’snet cash flows from KU R were $(50.1) million, $(0.1) million and $3.3 millionfor 2004, 2003 and 2002, respectively.

 

The allowance for doubtful accounts associated with the eligiblesecuritized receivables at December 31 was $0.5 million in 2003 and2002.  This allowance was based onhistorical experience of KU. Each securitization facility contained a fullyfunded reserve for uncollectible receivables.

 

RATES AND REGULATION

 

KU is subject to the jurisdiction of the Kentucky Commission, theVirginia Commission, the Tennessee Regulatory Authority, and FERC in virtuallyall matters related to electric utility regulation, and as such, its accountingis subject to SFAS No. 71.  Given KU’scompetitive position in the marketplace and the status of regulation in thestates of Kentucky and Virginia, KU has no plans or intentions to discontinueits application of SFAS No. 71.  See Note3 of KU’s Notes to Financial Statements under Item 8.

 

**Electric Rate Case.**InDecember 2003, KU filed an application with the Kentucky Commissionrequesting an adjustment in KU’s electric rates.  KU asked for a general adjustment in electricrates based on the twelve month test year ended September 30, 2003.  The revenue increase requested was $58.3million.

 

On June 30, 2004, theKentucky Commission issued an order approving an increase in the base electricrates of KU.  The Kentucky Commission’sorder largely accepted proposed settlement agreements filed in May 2004 by KUand a majority of the parties to the rate case proceedings.   The rate increases took effect on July 1,2004.

 

In the Kentucky Commission’s order, KU was granted anincrease in annual base electric rates of approximately $46.1 million(6.8%).  Other provisions of the orderinclude decisions on certain depreciation, ECR and VDT amounts or mechanismsand a termination of the ESM with respect to all periods after 2003.  The order also provided for a recovery beforeMarch 31, 2005, by KU of previously requested amounts relating to the ESMduring 2003.

 

DuringJuly 2004, the AG served subpoenas on KU, as well as on the KentuckyCommission and its staff, requesting information regarding allegedly impropercommunications between KU and the Kentucky Commission, particularly during theperiod covered by the rate case. The Kentucky Commission has procedurallyreopened the rate cases for the limited purpose of taking evidence, if any, asto the communication

 

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issues.Subsequently, the AG filed pleadings with the Kentucky Commission requestingrehearing of the rate case on certain computational components of the increasedrates, including income tax, cost of removal and depreciation amounts. In August 2004,the Kentucky Commission denied the AG’s rehearing request on the cost ofremoval and depreciation issues, with the effect that the rate increase orderis final as to these matters, subject to the parties’ rights to judicialappeals. The Kentucky Commission further agreed to hold in abeyance furtherproceedings in the rate case, including the AG’s concerns about allegedimproper communications, until the AG could file with the KentuckyCommission an investigative report regarding the latter issue. In addition, theKentucky Commission granted a rehearing on the income tax component once theabeyance discussed above is lifted.

 

In September andOctober 2004, various proceedings were held in circuit courts in Franklinand Jefferson Counties, Kentucky regarding the scope and timing of documentproduction or other information required or agreed to be produced under the AG’ssubpoenas and matters were consolidated into the Franklin County court.  In October 2004, the AG filed a motionwith the Kentucky Commission requesting that the previously granted rate increasebe set aside, that KU resubmit any applications for rate increases and thatrelevant Kentucky Commission personnel be recused from participation in ratecase proceedings.  In November 2004,the Franklin County, Kentucky court denied an AG request for sanctions on KUrelating to production matters and narrowed the AG’s permitted scope ofdiscovery.   In January 2005, the AGconducted interviews of certain Company individuals.

 

In January 2005,the AG submitted its report to the Franklin County, Kentucky Circuit Court inconfidence.  Concurrently the AG filed amotion summarizing the report as containing evidence of improper communicationsand record-keeping errors by KU in its conduct of activities before the KentuckyCommission or other state governmental entities and requesting release of thereport to such agencies.  During February 2005the court ruled that the report be forwarded to the Kentucky Commission undercontinued confidential treatment to allow it to consider the report, includingits impact, if any, on completing its investigation and any remaining steps inthe rate case, including ending the current abeyance.  To date, KU has neither seen nor requestedcopies of the report or its contents.

 

KU believes no improprieties have occurred in its communications withthe Kentucky Commission and is cooperating with the proceedings before the AGand the Kentucky Commission.

 

KU is currently unable to determine the ultimate impact, if any, of, orany possible future actions of the AG or the Kentucky Commission arising outof, the AG’s report and investigation, including whether there will be furtheractions to appeal, review or otherwise challenge the granted increase in baserates.

 

**VDT Costs - Kentucky CommissionSettlement Order. **Duringthe first quarter 2001, KU recorded a $64 million charge for a workforcereduction program.  Primary components ofthe charge were separation benefits, enhanced early retirement benefits, andhealthcare benefits. The result of this workforce reduction was the eliminationof approximately 300 positions, accomplished primarily through a voluntaryenhanced severance program.

 

In June 2001, KU filed an application (VDT case) with the KentuckyCommission to create a regulatory asset relating to these first quarter 2001charges.  The application requestedpermission to amortize these costs over a four-year period.  The Kentucky Commission also opened a case toreview a new depreciation study and resulting depreciation rates implemented in2001.

 

In December 2001, the Kentucky Commission approved a settlement inthe VDT case as well as other cases

 

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involving the depreciation rates and ESM.  The order approving the settlement allowed KUto set up a regulatory asset of $54 million for the workforce reduction costsand 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 hadaccepted a voluntary enhanced severance program.  Some employees rescinded their participationin the voluntary enhanced severance program which, along with the non-recurringcharge of $6.9 million for FERC and Virginia jurisdictions, decreased theoriginal charge to the regulatory asset from $64 million to $54 million. Thesettlement reduces revenues approximately $11 million through a surcredit onbills to ratepayers over the same five-year period.  The surcredit represents net savingsstipulated  by KU.

 

As mentioned, the current five-year VDT amortization period isscheduled to expire in March 2006. As part of the settlement agreements in the electric and gas rate cases,KU shall file with the Kentucky Commission a plan for the future ratemakingtreatment of the VDT surcredits and costs six months prior to the March 2006expiration.  The surcredit shall remainin effect following the expiration of the fifth year until the Commissionenters an order on the future disposition of VDT-related issues.

 

**Merger Surcredit. **As part of theLG&E Energy merger with KU Energy in 1998, LG&E Energy estimatednon-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 whichwas deferred and amortized over a five-year period pursuant to regulatoryorders.  Primary components of the mergercosts were separation benefits, relocation costs, and transaction fees, themajority of which were paid by December 31, 1998.  KU expensed the remaining costs associatedwith the merger ($21.8 million) in the second quarter of 1998.

 

In approving the merger, the Kentucky Commission adopted KU’s proposalto reduce its retail customers’ bills based on one-half of the estimatedmerger-related savings, net of deferred and amortized amounts, over a five-yearperiod.  The surcredit mechanism providesthat 50% of the net non-fuel cost savings estimated to be achieved from themerger be provided to ratepayers through a monthly bill credit, and 50% beretained by LG&E and KU over a five-year period.  The surcredit was allocated 53% to KU and 47%to LG&E.  In that same order, theKentucky Commission required LG&E and KU, after the end of the five-yearperiod, to present a plan for sharing with customers the then-projectednon-fuel savings associated with the merger. The Companies submitted this filing in January 2003, proposing tocontinue to share with ratepayers, on a 50%/50% basis, the estimated fifth-yeargross level of non-fuel savings associated with the merger.  In October 2003, the Kentucky Commissionissued an order approving a settlement agreement reached with the parties inthe case. KU’s merger surcredit will remain in place for another five-year termbeginning July 1, 2003 and the merger savings will continue to be shared50% with ratepayers and 50% with shareholders.

 

**ESM**.  Prior to 2004, KU’s Kentucky retail electricrates were subject to an ESM.  The ESM,initially in place for three years beginning in 2000, set an upper and lowerpoint for rate of return on equity, whereby if KU’s rate of return for thecalendar year fell within the range of 10.5% to 12.5%, no action wasnecessary.  If earnings were above theupper limit, the excess earnings were shared 40% with ratepayers and 60% withshareholders; if earnings were below the lower limit, the earnings deficiencywas recovered 40% from ratepayers and 60% from shareholders.  By order of the Kentucky Commission, ratechanges prompted by the ESM filing went into effect in April of each yearsubject to a balancing adjustment in successive periods.  There is no ESM for Virginia retail electricrates.

 

In November 2002, KU filed a revised ESM tariff which proposedcontinuance of the existing ESM through December 2005.  In addition, the Kentucky Commission initiated a focused management audit to review the ESMplan and reassess its reasonableness.  KUand interested parties had the opportunity to provide recommendations formodification and continuance of the ESM or other forms of alternative orincentive regulation.

 

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KU filed itsfinal 2003 ESM calculations with the Kentucky Commission on March 1, 2004,and applied for recovery of $16.2 million. Based upon estimates, KU previouslyaccrued $9.3 million for the 2003 ESM as of December 31, 2003.

 

On June 30,2004, the Kentucky Commission issued an order largely accepting proposedsettlement agreements by KU and all intervenors regarding the ESM.  Under the ESM settlements, KU will continueto collect approximately $16.2 million of previously requested 2003 ESM revenueamounts through March 2005.  As partof the settlement, the parties agreed to a termination of the ESM mechanismrelating to all periods after 2003.

 

As a result of the settlement, KU accrued an additional $6.9 million inJune 2004, related to 2003 ESM revenue.

 

**FAC. **KU’s Kentucky retailelectric rates contain a FAC, whereby increases or decreases in the cost offuel for electric generation are reflected in the rates charged to retailelectric customers.  In January 2003, the Kentucky Commissionreviewed KU’s FAC for the six month period ended October 31, 2001. TheKentucky Commission ordered KU to reduce its fuel costs for purposes ofcalculating its FAC by $0.7 million. At issue was the purchase of approximately102,000 tons of coal from Western Kentucky Energy Corporation, a non-regulatedaffiliate, for use at KU’s Ghent facility. The Kentucky Commission furtherordered that an independent audit be conducted to examine operational andmanagement aspects of both KU’s and LG&E’s fuel procurement functions. Thefinal report was issued in February 2004. The report’srecommendations related to documentation and process improvements.  Management Audit Action Plans were agreedupon by KU and the Kentucky Commission Staff in the second quarter of2004.  KU filed its first Audit ProgressReport with the Kentucky Commission Staff in November 2004.  A second Audit Progress Report is due in May2005.

 

The Kentucky Commission requires public hearings at six-month intervalsto examine past fuel adjustments, and at two-year intervals to review pastoperations of the fuel clause and transfer of the then current fuel adjustmentcharge or credit to the base charges.  KUalso employs a FAC mechanism for Virginia customers that uses an average fuelcost factor based primarily on projected fuel costs.  The fuel cost factor may be adjusted annuallyfor over or under collections of fuel costs from the previous year.  No other significant issues have beenidentified as a result of these reviews.

 

In December 2004, the Kentucky Commission initiated a two-yearreview of KU’s past operations of the fuel clause and transfer of fuel costsfrom the fuel adjustment clause to base rates.  A public hearing on the matter was held on March 17, 2005.  An order by the Kentucky Commission isexpected in April 2005.  KU isseeking to increase the fuel component of base rates.  KU does not anticipate any issues will ariseduring the regulatory proceeding.

 

In February 2005, KU filed with the Virginia Commission anapplication seeking approval of an increase in its fuel cost factor to reflecthigher fuel costs incurred.   KUanticipates implementing the increased fuel cost factor with April 2005billings.

 

**DSM.**  In May 2001, the Kentucky Commission approveda plan that would expand LG&E’s DSM programs into the service territoryserved by KU.  The plan included a ratemechanism that provided for concurrent recovery of DSM costs, provided anincentive for implementing DSM programs, and recovered revenues from lost salesassociated with the DSM programs based on program plan engineering estimatesand post-implementation evaluations.

 

**ECR**.  In August 2002, KU filed an applicationwith the Kentucky Commission to amend its compliance plan to

 

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allow recovery of the cost of a new and additional environmentalcompliance facilities.  The estimatedcapital cost of the additional facilities is $17.3 million.  A final order was issued in February 2003.The final order approved recovery of the new environmental compliance facilitytotaling $17.3 million.  Cost recoverythrough the environmental surcharge of the approved project commenced withbills rendered in April 2003.

 

In March 2003, the Kentucky Commissioninitiated a series of six-month and two-year reviews of the operation of KU’sEnvironmental Surcharge.  A final orderwas issued in October 2003, resolving all outstanding issues related toover-recovery from customers and under-recovery of allowed O&Mexpense.  The Commission found that KUhad over-collected a net $6.0 million from customers and ordered the refund tooccur through adjustments to the calculation of the monthly surcharge billingfactor over the subsequent 12 month period. The Kentucky Commission further ordered KU to roll $17.9 million ofenvironmental assets into base rates and make corresponding adjustments to themonthly environmental surcharge filings to reflect that portion of environmentalrate base now included in base rates going forward.  The rates of return for KU’s 1994 andpost-1994 plans were reset to 1.24% and 12.60%, respectively.

 

In June 2004, the Kentucky Commissionissued an order approving a settlement agreement that, among other things,revised the rate of return for KU’s post-1994 plan to 11.19%, with an 11%return on common equity.  The order alsoapproved the elimination of KU’s 1994 Plan for its ECR billing mechanism, withall remaining costs associated with that plan to be included in their entiretyin base rates.

 

In December 2004, KU filed an applicationwith the Kentucky Commission for approval of a CCN to construct new SO2control technology (FGDs) at the Ghent and Brown stations, and to amend itscompliance plan to allow recovery of costs associated with new and additionalenvironmental compliance facilities.  Theestimated capital cost of the additional facilities is $702.5 million, of which$658.9 million is for the FGDs.  A finalorder in the case is expected in June 2005.

 

**MISO. **KUis a founding member of the MISO.  Membershipwas obtained in 1998 in response to and consistent with federal policyinitiatives.  In February 2002, KUturned over operational control of its high voltage transmission facilities(100kV and above) to the MISO.  The MISOcurrently controls over 100,000 miles of transmission over 1.1 million squaremiles located in the northern Midwest between Manitoba, Canada andKentucky.  In September 2002, FERCgranted a 12.88% ROE on transmission facilities for KU and the rest of the MISOowners.  On February 18, 2005, theUnited States Court of Appeals for the District of Columbia Circuit ruled thatFERC did not provide proper notice that it would consider an incentive adder of50 basis points, but affirmed the September 2002 FERC order in all otherrespects.  Effective ROE, retroactive to February 1,2002, is 12.38% for KU and the original MISO owners.

 

In October 2001, the FERC issued an order requiring that thebundled retail load and grandfathered wholesale load of each membertransmission owner be included in the current calculation of the MISO’s “cost-adder,”the Schedule 10 charges designed to recover the MISO’s costs of operation,including start-up capital (debt) costs. KU, along with several other transmission owners, opposed the FERC’sruling on this matter. The opposition was rejected by the FERC in 2002.   Later that year, the MISO’s transmissionowners, appealed the FERC’s decision to the United States Court of Appeals forthe District of Columbia Circuit.  Inresponse, in November 2002, the FERC requested that the Court issue apartial remand of its challenged orders to allow the FERC to revisit certainissues, and requested that the case be held in abeyance pending the agency’sresolution of such issues.  The Courtgranted the FERC’s petition in December 2002.   In February 2003, FERC issued an orderreaffirming its position concerning the calculation of the Schedule 10charges and in July 2003 denied a rehearing. KU, along with several othertransmission owners, again petitioned the District Court of Columbia Circuitfor review. In July 2004, the court affirmed the FERC ruling.

 

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In August 2004, the MISO filedits FERC-required proposed TEMT.  InSeptember and October 2004, many MISO-related parties (including KU) filedproposals with the FERC regarding pending MISO-filed changes to transmissionpricing principles, including the TEMT and elimination of RTORs. Additionalfilings of the companies before FERC in September 2004 sought to address issuesrelating to the treatment of certain GFA's should TEMT become effective. Theutility proposals generally seek to appropriately delay the RTORs and TEMTeffective dates based upon errors in administrative or procedural processesused by FERC or to appropriately limit potential reductions in transmissionrevenues received by the utilities should the RTORs, TEMT or GFA structures beimplemented.  At present, existing FERCorders conditionally approve elimination of RTORs and implementation of generalTEMT rates in the MISO by spring 2005. At this time, KU cannot predict the outcome or effects of the variousFERC proceedings described above, including whether such will have a materialimpact on the financial condition or results of operations of the companies.Financial consequences (changes in transmission revenues and costs) associatedwith the upcoming transmission market tariff changes are subject to varyingassumptions and calculations and are therefore difficult to estimate. Changesin revenues and costs related to broader shifts in energy market practices andeconomics are not currently estimable. Should KU be ordered to exit MISO, current MISO rules may also impose anexit fee.  KU is not able to predict theestimated outcome or economic impact of any of the MISO-related matters.  While KU believes legal and regulatoryprecedent should permit most or many of the MISO-related costs to be recoveredin their rates charged to customers, they can give no assurance that state orfederal regulators will ultimately agree with such position with respect to allcosts, components or timing of recovery.

 

The MISO plans to implement a Day-ahead and Real-time market, includinga congestion management system in April 2005. This system will be similarto the LMP system currently used by the PJM RTO and contemplated in FERC’s SMDNOPR, currently being discussed.  TheMISO filed with FERC a mechanism for recovery of costs for the congestion managementsystem.  They proposed the addition oftwo new Schedules, 16 and 17.  Schedule 16is the MISO’s cost recovery mechanism for the Financial Transmission RightsAdministrative Service it will provide.  Schedule 17is the MISO’s mechanism for recovering costs it will incur for providing EnergyMarketing Support Administrative Service. The MISO transmission owners, including KU, have objected to theallocation of costs among market participants and retail native load. FERCruled in 2004 in favor of the MISO.

 

The Kentucky Commission opened an investigation into KU’s membership inthe MISO in July 2003. The Kentucky Commission directed KU to filetestimony addressing the costs and benefits of the MISO membership bothcurrently and over the next five years and other legal issues surroundingcontinued membership.  KU engaged anindependent third-party to conduct a cost benefit analysis on this issue.  The information was filed with the KentuckyCommission in September 2003.  Theanalysis and testimony supported the exit from the MISO, under certainconditions.  The MISO filed its owntestimony and cost benefit analysis in December 2003.  A final Kentucky Commission order wasexpected in the second quarter of 2004; that ruling has since been delayeduntil summer 2005 due to the Kentucky Commission’s request for additionaltestimony on the MISO’s Market Tariff filing at FERC.

 

**Kentucky CommissionAdministrative Case for System Adequacy.**   In June 2001, Kentucky’s  Governor issued Executive Order 2001-771,which directed the Kentucky Commission to review and study issues relating tothe need for and development of new electric generating capacity inKentucky.  In response to that ExecutiveOrder, in July 2001 the Kentucky Commission opened Administrative Case No.387 to review the adequacy of Kentucky’s generation capacity and transmissionsystem.  Specifically, the items reviewedwere the appropriate level of reliance on purchased power, the appropriatereserve margins to meet existing and future electric demand, the impact ofspikes in natural gas prices on electric utility planning strategies, and theadequacy of Kentucky’s electric transmission facilities.  In December 2001, the Kentucky Commissionissued an order in which it noted that KU is responsibly addressing thelong-term supply needs of native load customers and that current reservemargins are appropriate.  However, due tothe rapid pace of change in the industry, the order also requires KU to providean annual assessment of supply resources, future demand, reserve margin, andthe need for new resources.

 

Regarding the transmission system, the Kentucky Commission concludedthat the transmission system within Kentucky can reliably serve native load anda significant portion of the proposed new unregulated power plants. However, itwill not be able to handle the volume of transactions envisioned by FERC withoutfuture upgrades, the costs of which should be borne by those for whom theupgrades are required.

 

The Kentucky Commission pledged to continue to monitor all relevantissues and advocate Kentucky’s interests at all opportunities.

 

**KentuckyCommission Strategic Blueprint.**  In February 2005, Kentucky’s Governorsigned an executive order directing the Kentucky Commission, in conjunctionwith the Commerce Cabinet and the Environmental and Public Protection Cabinet,to ‘develop a Strategic Blueprint for the continued use and development ofelectric energy.’ This Strategic Blueprint will be designed to promote futureinvestment in electric infrastructure for the Commonwealth of Kentucky, toprotect Kentucky’s low-cost electric advantage, to maintain affordable ratesfor all Kentuckians, and to preserve Kentucky’s commitment to environmentalprotection.  In March 2005, theKentucky Commission established Administrative Case No. 2005-00090 to collectinformation from

 

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alljurisdictional utilities in Kentucky, including KU, pertaining to Kentuckyelectric generation, transmission and distribution systems.  The Kentucky Commission must provide itsStrategic Blueprint to the Governor in early August 2005.  KU must respond to the Kentucky Commission’sfirst set of data requests by the end of March 2005.

 

**FERC SMD NOPR. **In July 2002,the FERC issued a NOPR in Docket No. RM01-12-000 which would substantiallyalter the regulations governing the nation’s wholesale electricity markets byestablishing a common set of rules, defined as SMD. The SMD NOPR would requireeach public utility that owns, operates, or controls interstate transmissionfacilities to become an ITP, belong to an RTO that is an ITP, or contract withan ITP for operation of its transmission assets. It would also establish astandardized congestion management system, real-time and day-ahead energymarkets, and a single transmission service for network and point-to-pointtransmission customers. Review of the proposed rulemaking is underway and notime frame has been established by the FERC for adoption of a final rule.  While it is expected that the SMD final rulewill affect KU’s revenues and expenses, the specific impact of the rulemakingis not known at this time.

 

**Kentucky CommissionAdministrative Case for Affiliate Transactions. **In December 1997, theKentucky Commission opened Administrative Case No. 369 to consider KentuckyCommission policy regarding cost allocations, affiliate transactions and codesof conduct governing the relationship between utilities and their non-utilityoperations and affiliates.  The KentuckyCommission intended to address two major areas in the proceedings: the toolsand conditions needed to prevent cost shifting and cross-subsidization betweenregulated and non-utility operations; and whether a code of conduct should beestablished to assure that non-utility segments of the holding company are notengaged in practices that could result in unfair competition caused by cost shiftingfrom the non-utility affiliate to the utility. In early 2000, the Kentucky General Assembly enacted legislation, HouseBill 897, which authorized the Kentucky Commission to require utilities thatprovide nonregulated activities to keep separate accounts and allocate costs inaccordance with procedures established by the Kentucky Commission. In the samebill, the General Assembly set forth provisions to govern a utility’sactivities related to the sharing of information, databases, and resourcesbetween its employees or an affiliate involved in the marketing or theprovision of nonregulated activities and its employees or an affiliate involvedin the provision of regulated services. The legislation became law in July 2000and KU has been operating pursuant thereto since that time.  In February 2001, the Kentucky Commissionpublished notice of their intent to promulgate new administrative regulationunder the auspices of the new law.  Thiseffort is still on going.

 

**Environmental Matters. **KU is subject to SO2and NOx emission limits on its electric generating units pursuant to the CleanAir Act.  KU met its Phase I SO2requirements primarily through installation of FGD equipment on Ghent Unit 1and through the consumption of emission allowances granted under the Clean AirAct.  KU’s strategy for Phase II SO2reductions, which commenced January 1, 2000, has been to use accumulatedemissions allowances to delay additional capital expenditures and will includefuel switching and the installation of additional FGDs as necessary. KU decidedin December 2004 that additional FGDs will be necessary to maintaincompliance with Phase II SO2 reductions.  Those installations are currently scheduledfor completion in 2007-2009.   KU met theNOx emission requirements of the Act through installation of low-NOx burnersystems. KU’s compliance plans are subject to many factors includingdevelopments in the emission allowance and fuel markets, future regulatory andlegislative initiatives, and advances in clean air control technology.  KU will continue to monitor thesedevelopments to ensure that its environmental obligations are met in the mostefficient and cost-effective manner.

 

In September 1998, the EPA announced its final “NOx SIP Call” rulerequiring states to impose significant additional reductions in NOx emissionsby May 2003, in order to mitigate alleged ozone transport impacts on theNortheast region.  The Commonwealth ofKentucky SIP, which was approved by the EPA on June 24, 2003,

 

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requires reductions in NOx emissions from coal-fired generating unitsto the 0.15 lb./MMBtu level on a system-wide basis.  In related proceedings in response topetitions filed by various Northeast states, in December 1999, the EPA issueda final rule pursuant to Section 126 of the Clean Air Act directingsimilar NOx reductions from a number of specifically targeted generating unitsincluding all KU units in the eastern half of Kentucky.  Additional petitions currently pending beforethe EPA may potentially result in rules encompassing KU’s remaining generatingunits.  As a result of appeals to bothrules, the compliance date was extended to May 31, 2004.  All KU generating units are in compliancewith these NOx emissions reduction rules.

 

KU has added significant NOx controls to its generating units throughthe installation of SCR systems, advanced low-NOx burners and neuralnetworks.  The NOx controls projectcommenced in late 2000 with the controls being placed into operation prior tothe 2004 Summer Ozone Season. As of December 31, 2004, KU incurred totalcapital costs of approximately $219 million to reduce its NOx emissions belowthe 0.15 lb./MMBtu level on a company-wide basis.  In addition, KU will incur additionaloperating and maintenance costs in operating new NOx controls.  KU believes its costs in this regard to becomparable to those of similarly situated utilities with like generationassets. KU anticipated that such capital and operating costs are the type ofcosts that are eligible for recovery from customers under its environmentalsurcharge mechanism and believed that a significant portion of such costs couldbe recovered.  In April 2001, theKentucky Commission granted recovery of these costs for KU.

 

KU is also monitoring several other air quality issues which maypotentially impact coal-fired power plants, including EPA’s revised air qualitystandards for ozone and particulate matter, measures to implement EPA’sregional haze rule, and EPA’s Clean Air Mercury Rule which regulates mercuryemissions from steam electric generating units and reductions in emissions ofSO2 and NOx required under the Clean Air Interstate Rule.  KU has implemented a plan for addingsignificant additional SO2 controls to its generating units.  Installation of additional SO2controls will proceed on a phased basis, with construction of controls (i.e.FGD’s) commencing in mid 2005 and continuing through the final installation andoperation in 2009.  KU estimates that itwill incur $678 million in capital costs related to the reduction of its SO2emissions to achieve compliance with current emission limits on a company-widebasis.  In addition, KU will incuradditional operating and maintenance costs in operating new SO2controls.  KU believes its costs in thisregard to be comparable to those of similarly situated utilities with likegeneration assets.  KU anticipates thatsuch capital and operating costs are the type of costs that are eligible forrecovery from customers under its environmental surcharge mechanism andbelieves that a significant portion of such costs could be recovered.  In December 2004, KU filed anapplication seeking recovery of its costs. KU expects the Kentucky Commissionto issue an Order granting recovery of these costs in June 2005.

 

KU owns or formerly owned several properties that were used for companyor company-predecessor operations, including MGP’s, power production facilitiesand substations.  While KU has completeda cleanup of one such site in 1995, evaluations of these types of propertiesgenerally have not identified issues of significance.  With regard to these properties, KU isunaware of any imminent exposure or liability.

 

In October 1999, approximately 38,000 gallons of diesel fuelleaked from a cracked valve in an underground pipeline at KU’s E.W. BrownStation.  KU commenced immediate spillcontainment and recovery measures which continued under the oversight of EPAand state officials and prevented the spill from reaching the Kentucky River.  KU ultimately recovered approximately 34,000gallons of diesel fuel.  In November 1999,the Kentucky Division of Water issued a notice of violation for theincident.  KU has settled all outstandingissues for this incident with the Commonwealth of Kentucky.  KU incurred costs of approximately $1.8million and received insurance reimbursement of $1.2 million.  In December 2002, the Department ofJustice (DOJ) sent correspondence to KU regarding a potential per-day fine forfailure to timely submit a facility response plan and

 

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a per-gallon fine for the amount of oil discharged.  During August 2004, KU, the EPA, and theDepartment of Justice agreed in principle to settle outstanding matters concerningthe 1999 oil discharge at KU’s E.W. Brown plant for approximately $0.6 million.The settlement is subject to completion of final definitive documents but isanticipated to be resolved by the construction of a separate environmentalcapital project and a cash payment of approximately $0.2 million. At December 31,2004, KU has recorded an accrual and expense to operations of $0.2 million.

 

In April 2002, the EPA sent correspondence to KU regardingpotential exposure in connection with $1.5 million in completed remediationcosts associated with a transformer scrap-yard. KU believes it is one of the more remote parties, among a number ofpotentially responsible parties, and has entered into settlement discussionswith the EPA and the Kentucky Division of Waste Management on this matter.

 

In January 2005, approximately 1,000 gallons of fuel oil leakedfrom a cracked weld in a storage tank at KU’s Green River GeneratingStation.  KU commenced immediate spillcontainment, recovery and remediation actions and has received satisfactoryinspections from state regulators to date. The cost related to the cleanup of the oil spill is expected to beimmaterial.

 

See Note 11 of KU’s Notes to FinancialStatements under Item 8 for an additional discussion of environmental issues.

 

**Lock 7License Matter.** KU's 1.8 Mw hydroelectric facility located at Lock No. 7 on the KentuckyRiver has been inactive since 1999.  Inconnection with a possible transfer of Lock No.7 and the dam at the site fromthe U.S. Army Corps of Engineers to the Kentucky River Authority, KU is seekingto surrender or transfer its FERC license governing the hydroelectricfacility.  KU has entered intonegotiations with a prospective third party acquirer for the license.  If KU is unable to successfully transfer thelicense, it may become or remain obligated for certain construction ordemolition expenditures or other financial liabilities in the approximateamount of $4 million.

 

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FUTURE OUTLOOK

 

Competition and Customer Choice

 

In the last several years, KU has taken many steps to keep its rateslow while maintaining high levels of customer satisfaction, including areduction in the number of employees; aggressive cost cutting; an increase infocus on commercial, industrial and residential customers; an increase inemployee involvement and training; and continuous modifications of its organizationalstructure.  KU will take additional stepsto better position itself should retail competition come to Kentucky.

 

At this time, neither the Kentucky General Assembly nor the KentuckyCommission has adopted or approved a plan or timetable for retail electricindustry competition in Kentucky.  Thenature or timing of the ultimate legislative or regulatory actions regardingindustry restructuring and their impact on KU, which may be significant, cannotcurrently be predicted.  Some states thathave already deregulated have begun discussions that could lead tore-regulation.

 

In February 2005,Kentucky’s Governor signed an executive order directing the Kentucky Commission,in conjunction with the Commerce Cabinet and the Environmental and PublicProtection Cabinet, to ‘develop a Strategic Blueprint for the continued use anddevelopment of electric energy.’ This Strategic Blueprint will be designed topromote future investment in electric infrastructure for the Commonwealth ofKentucky, to protect Kentucky’s low-cost electric advantage, to maintainaffordable rates for all Kentuckians, and to preserve Kentucky’s commitment toenvironmental protection.”  In March 2005,the Kentucky Commission established Administrative Case No. 2005-00090 tocollect information from all jurisdictional utilities in Kentucky, includingKU, pertaining to Kentucky electric generation, transmission and distributionsystems.  The Kentucky Commission mustprovide its Strategic Blueprint to the Governor in early August 2005.  KU must respond to the Kentucky Commission’sfirst set of data requests by the end of March 2005.

 

Virginia has enacted a phase-in of customer choice through the VirginiaElectric Restructuring Act.  The VirginiaCommission is promulgating regulations to govern the various activitiesrequired by the Act.  Effective July 1, 2003, the General Assemblyof Virginia amended and reenacted Section 56-580 of the Code of Virginiawith language that effectively exempts all KU Virginia service territory fromretail choice until such time as retail choice is offered to customers in KU’sother service territories.

 

# **ITEM7A.  Quantitative and QualitativeDisclosures About Market Risk.**

# ** **

See LG&E’s and KU’s Management’s Discussion and Analysis ofFinancial Condition and Results of Operations, Market Risks, under Item 7.

 

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# **ITEM8. Financial Statements and Supplementary Data.**

 

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INDEX OF ABBREVIATIONS

 
| AFUDC               |   | Allowance for Funds Used During  Construction                |
|---------------------|--------|--------------------------------------------------------------|
| ARO                 |   | Asset Retirement Obligation                                  |
| Capital Corp.       |   | LG&E Capital Corp.                                       |
| Clean Air Act       |   | The Clean Air Act, as amended  in 1990                       |
| CCN                 |   | Certificate of Public  Convenience and Necessity             |
| CO2                 |   | Carbon Dioxide                                               |
| CT                  |   | Combustion Turbines                                          |
| CWIP                |   | Construction Work in Progress                                |
| DSM                 |   | Demand Side Management                                       |
| ECAR                |   | East Central Area Reliability  Region                        |
| 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                        |
| FGD                 |   | Flue Gas Desulfurization                                     |
| 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 LLC (as  successor to LG&E Energy Corp.) |
| LG&E R          |   | LG&E Receivables LLC                                     |
| LG&E Services   |   | LG&E Energy Services Inc.                                |
| LNG                 |   | Liquefied Natural Gas                                        |
| Mcf                 |   | Thousand Cubic Feet                                          |
| MGP                 |   | Manufactured Gas Plant                                       |
| MISO                |   | Midwest Independent  Transmission 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                   |

 

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| ROE                 |   | Return on Equity                             |
|---------------------|--------|----------------------------------------------|
| RTO                 |   | Regional Transmission  Organization          |
| S&P             |   | Standard & Poor’s Rating  Services  |
| SCR                 |   | Selective Catalytic Reduction                |
| SEC                 |   | Securities and Exchange Commission           |
| SERP                |   | Supplemental Executive  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 LLC                   |
| 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  |
| WNA                 |   | Weather Normalization Adjustment             |

 

83

----

 

Louisville Gas and Electric Company andSubsidiary

ConsolidatedStatements of Income

(Thousands of $)

 
| ** **                                          | ** ** | **Years Ended December 31** | ** ** |
|-----------------------------------------------------|------------|----------------------------------|------------|
| ** **                                          | ** ** | **2004**                         | ** ** | **2003** | ** ** | **2002** | ** ** |
| OPERATING  REVENUES:                                |       |                             |       |   |   |   |   |
| Electric  (Note 14)                                 |       | $                                | 815,697    |   | $ | 768,188 |   | $ | 736,042 |   |
| Gas                                                 |       | 357,071                          |       | 325,333 |   | 267,693 |   |
| Total  operating revenues (Note 1)                  |       | 1,172,768                        |       | 1,093,521 |   | 1,003,735 |   |
|                                                |       |                             |       |   |   |   |   |
| OPERATING  EXPENSES:                                |       |                             |       |   |   |   |   |
| Fuel for  electric generation                       |       | 207,092                          |       | 196,965 |   | 194,900 |   |
| Power  purchased (Note 14)                          |       | 92,047                           |       | 79,621 |   | 61,881 |   |
| Gas supply  expenses                                |       | 266,013                          |       | 233,601 |   | 182,108 |   |
| Other  operation and maintenance expenses           |       | 306,008                          |       | 291,295 |   | 285,991 |   |
| Depreciation  and amortization (Note 1)             |       | 116,577                          |       | 113,287 |   | 105,906 |   |
| Total  operating expenses                           |       | 987,737                          |       | 914,769 |   | 830,786 |   |
|                                                |       |                             |       |   |   |   |   |
| Net  operating income                               |       | 185,031                          |       | 178,752 |   | 172,949 |   |
|                                                |       |                             |       |   |   |   |   |
| Other income  (expense) - net (Note 8 and Note 14)  |       | (3,332                           | )          | (7,193 | ) | (1,536 | ) |
| Interest  expense (Notes 9 and 10)                  |       | 20,545                           |       | 23,863 |   | 27,630 |   |
| Interest  expense to affiliated companies (Note 14) |       | 12,242                           |       | 6,784 |   | 2,175 |   |
|                                                |       |                             |       |   |   |   |   |
| Income  before income taxes                         |       | 148,912                          |       | 140,912 |   | 141,608 |   |
|                                                |       |                             |       |   |   |   |   |
| Federal and  state income taxes (Note 7)            |       | 53,294                           |       | 50,073 |   | 52,679 |   |
|                                                |       |                             |       |   |   |   |   |
| Net income                                          |       | $                                | 95,618     |   | $ | 90,839 |   | $ | 88,929 |   |
|                                                     |            |                                  |            |  |  |  |  |  |  |  |  |  |

 

Consolidated Statements of Retained Earnings

(Thousands of $)

 
| ** **                         | ** **                         | **Years Ended December 31** | ** ** |
|------------------------------------|------------------------------------|----------------------------------|------------|
| ** **                         | ** **                         | **2004**                         | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                         | ** **                         | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| Balance January 1             |                               | $                                | 497,441    |   | $ | 409,319 |   | $ | 393,636 |   |
| Add net  income                    |                               | 95,618                           |       | 90,839 |   | 88,929 |   |
|                               |                               | 593,059                          |       | 500,158 |   | 482,565 |   |
|                               |                               |                             |       |   |   |   |   |
| Deduct:                            | Cash  dividends declared on stock: |                             |       |   |   |   |   |   |
| 5%  cumulative preferred           |                               | 1,075                            |       | 1,075 |   | 1,075 |   |
| Auction rate  cumulative preferred |                               | 962                              |       | 908 |   | 1,702 |   |
| $5.875  cumulative preferred       |                               | —                           |       | 734 |   | 1,469 |   |
| Common                             |                               | 57,000                           |       | — |   | 69,000 |   |
|                               |                               | 59,037                           |       | 2,717 |   | 73,246 |   |
|                               |                               |                             |       |   |   |   |   |
| Balance December 31           |                               | $                                | 534,022    |   | $ | 497,441 |   | $ | 409,319 |   |
|                                    |                                    |                                  |            |  |  |  |  |  |  |  |  |  |

 

The accompanying notes are an integral part of these consolidatedfinancial statements.

 

84

----

 

Louisville Gas and ElectricCompany and Subsidiary

Consolidated Statements of Comprehensive Income

(Thousands of $)

 
| ** **                                                                                                                                                                       | ** ** | **Years Ended December 31** | ** ** |
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                                                                                                                                       | ** ** | **2004**                         | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                                                                                                                                                       | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| Net income                                                                                                                                                                       |       | $                                | 95,618     |   | $ | 90,839 |   | $ | 88,929 |   |
|                                                                                                                                                                             |       |                             |       |   |   |   |   |
| Gain/(losses)  on derivative instruments and hedging activities, net of tax  benefit/(expense) of $947, $(368) and $3,457 for 2004, 2003 and 2002,  respectively (Notes 1 and 4) |       | (1,399                           | )          | 544 |   | (5,107 | ) |
|                                                                                                                                                                             |       |                             |       |   |   |   |   |
| Additional  minimum pension liability adjustment, net of tax benefit/(expense) of $4,128,  $(1,257) and $10,493 for 2004, 2003 and 2002, respectively (Note 6)                   |       | (6,100                           | )          | 1,857 |   | (15,505 | ) |
|                                                                                                                                                                             |       |                             |       |   |   |   |   |
| Other  comprehensive (loss) income, net of tax (Note 15)                                                                                                                         |       | (7,499                           | )          | 2,401 |   | (20,612 | ) |
|                                                                                                                                                                             |       |                             |       |   |   |   |   |
| Comprehensive  income                                                                                                                                                            |       | $                                | 88,119     |   | $ | 93,240 |   | $ | 68,317 |   |

 

The accompanying notes are an integral part of these consolidatedfinancial statements.

 

85

----

 

Louisville Gas and ElectricCompany and Subsidiary

ConsolidatedBalance Sheets

(Thousands of $)

 
| ** **                                                                           | ** ** | **December 31** | ** ** |
|--------------------------------------------------------------------------------------|------------|----------------------|------------|
| ** **                                                                           | ** ** | **2004**             | ** ** | **2003** | ** ** |
| ASSETS:                                                                              |       |                 |       |   |   |
| Current  assets:                                                                     |       |                 |       |   |   |
| Cash and  cash equivalents (Note 1)                                                  |       | $                    | 6,809      |   | $ | 1,706 |   |
| Accounts  receivable - less reserve of $785 in 2004 and $3,515 in 2003 (Note 4)      |       | 166,990              |       | 84,585 |   |
| Materials  and supplies - at average cost:                                           |       |                 |       |   |   |
| Fuel  (predominantly coal) (Note 1)                                                  |       | 21,771               |       | 25,260 |   |
| Gas stored  underground (Note 1)                                                     |       | 77,503               |       | 69,884 |   |
| Other (Note  1)                                                                      |       | 26,159               |       | 24,971 |   |
| Prepayments  and other                                                               |       | 3,921                |       | 5,281 |   |
|                                                                                 |       | 303,153              |       | 211,687 |   |
|                                                                                 |       |                 |       |   |   |
| Other  property and investments – less reserve of $63 in 2004 and 2003 (Note 1) |       | 507                  |       | 611 |   |
|                                                                                 |       |                 |       |   |   |
| Utility  plant, at original cost (Note 1):                                           |       |                 |       |   |   |
| Electric                                                                             |       | 3,113,653            |       | 2,809,957 |   |
| Gas                                                                                  |       | 487,771              |       | 468,504 |   |
| Common                                                                               |       | 177,538              |       | 186,556 |   |
|                                                                                 |       | 3,778,962            |       | 3,465,017 |   |
|                                                                                 |       |                 |       |   |   |
| Less:  reserve for depreciation                                                      |       | 1,396,341            |       | 1,326,899 |   |
|                                                                                 |       | 2,382,621            |       | 2,138,118 |   |
|                                                                                 |       |                 |       |   |   |
| Construction  work in progress                                                       |       | 136,842              |       | 339,166 |   |
|                                                                                 |       | 2,519,463            |       | 2,477,284 |   |
|                                                                                 |       |                 |       |   |   |
| Deferred  debits and other assets:                                                   |       |                 |       |   |   |
| Restricted  cash (Note 1)                                                            |       | 10,943               |       | — |   |
| Unamortized  debt expense (Note 1)                                                   |       | 8,453                |       | 8,753 |   |
| Regulatory  assets (Note 3)                                                          |       | 91,866               |       | 143,626 |   |
| Other                                                                                |       | 32,167               |       | 40,121 |   |
|                                                                                 |       | 143,429              |       | 192,500 |   |
|                                                                                 |       |                 |       |   |   |
|                                                                                 |       | $                    | 2,966,552  |   | $ | 2,882,082 |   |
|                                                                                      |            |                      |            |  |  |  |  |  |  |

 

Theaccompanying notes are an integral part of these consolidated financialstatements.

 

86

----

 

Louisville Gas and Electric Companyand Subsidiary

ConsolidatedBalance Sheets (continued)

(Thousands of $)

 
| ** **                                                        | ** ** | **December 31** | ** ** |
|-------------------------------------------------------------------|------------|----------------------|------------|
| ** **                                                        | ** ** | **2004**             | ** ** | **2003** | ** ** |
| CAPITAL AND  LIABILITIES:                                         |       |                 |       |   |   |
| Current  liabilities:                                             |       |                 |       |   |   |
| Current  portion of long-term debt:                               |       |                 |       |   |   |
| Long-term  bonds (Note 9)                                         |       | $                    | 246,200    |   | $ | 246,200 |   |
| Long-term  notes to affiliated company (Note 9)                   |       | 50,000               |       | — |   |
| Mandatorily  redeemable preferred stock (Note 9)                  |       | 1,250                |       | 1,250 |   |
|                                                              |       | 297,450              |       | 247,450 |   |
|                                                              |       |                 |       |   |   |
| Notes  payable to affiliated company (Notes 10 and 14)            |       | 58,220               |       | 80,332 |   |
| Accounts payable                                                  |       | 106,090              |       | 93,118 |   |
| Accounts  payable to affiliated companies (Note 14)               |       | 31,709               |       | 38,343 |   |
| Accrued  income taxes                                             |       | 6,208                |       | 11,472 |   |
| Customer  deposits                                                |       | 14,016               |       | 10,493 |   |
| Other                                                             |       | 18,624               |       | 16,533 |   |
|                                                              |       | 234,867              |       | 250,291 |   |
|                                                              |       |                 |       |   |   |
|                                                              |       | 532,317              |       | 497,741 |   |
| Long-term  debt (see statements of capitalization):               |       |                 |       |   |   |
| Long-term  bonds (Note 9)                                         |       | 328,104              |       | 328,104 |   |
| Long-term  notes to affiliated company (Note 9)                   |       | 225,000              |       | 200,000 |   |
| Mandatorily  redeemable preferred stock (Note 9)                  |       | 21,250               |       | 22,500 |   |
|                                                              |       | 574,354              |       | 550,604 |   |
| Deferred  credits and other liabilities:                          |       |                 |       |   |   |
| Accumulated  deferred income taxes (Notes 1 and 7)                |       | 347,233              |       | 337,704 |   |
| Investment  tax credit, in process of amortization                |       | 46,176               |       | 50,329 |   |
| Accumulated  provision for pensions and related benefits (Note 6) |       | 120,566              |       | 140,598 |   |
| Asset  retirement obligations                                     |       | 10,266               |       | 9,747 |   |
| Regulatory  liabilities (Note 3):                                 |       |                 |       |   |   |
| Accumulated  cost of removal of utility plant                     |       | 220,214              |       | 216,491 |   |
| Other                                                             |       | 52,150               |       | 51,822 |   |
| Other                                                             |       | 40,105               |       | 32,957 |   |
|                                                              |       | 836,710              |       | 839,648 |   |
| Commitments  and contingencies (Note 11)                          |       |                 |       |   |   |
|                                                              |       |                 |       |   |   |
| Cumulative  preferred stock (see statements of capitalization)    |       | 70,425               |       | 70,425 |   |
|                                                              |       |                 |       |   |   |
| Common  equity (see statements of capitalization)                 |       | 952,746              |       | 923,664 |   |
|                                                              |       |                 |       |   |   |
|                                                              |       | $                    | 2,966,552  |   | $ | 2,882,082 |   |

 

Theaccompanying notes are an integral part of these consolidated financialstatements.

 

87

----

 

Louisville Gas and ElectricCompany and Subsidiary

Consolidated Statements of Cash Flows

(Thousands of $)

 
| ** **                                                  | ** ** | **Years Ended December 31** | ** ** |
|-------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                  | ** ** | **2004**                         | ** ** | **2003** | ** ** | **2002** | ** ** |
| CASH FLOWS  FROM OPERATING ACTIVITIES:                      |       |                             |       |   |   |   |   |
| Net income                                                  |       | $                                | 95,618     |   | $ | 90,839 |   | $ | 88,929 |   |
| Items not  requiring cash currently:                        |       |                             |       |   |   |   |   |
| Depreciation  and amortization                              |       | 116,577                          |       | 113,287 |   | 105,906 |   |
| Deferred  income taxes - net                                |       | 5,533                            |       | 20,123 |   | 11,915 |   |
| Investment  tax credit - net                                |       | (4,153                           | )          | (4,207 | ) | (4,153 | ) |
| VDT  amortization                                           |       | 30,135                           |       | 30,400 |   | 30,000 |   |
| Mark-to-market  financial instruments                       |       | 2,576                            |       | (1,149 | ) | 8,512 |   |
| Other                                                       |       | (2,023                           | )          | 10,812 |   | 11,226 |   |
| Change in  certain net current assets:                      |       |                             |       |   |   |   |   |
| Accounts  receivable                                        |       | (24,405                          | )          | (10,945 | ) | (3,973 | ) |
| Materials  and supplies                                     |       | (5,318                           | )          | (7,598 | ) | (15,048 | ) |
| Accounts  payable                                           |       | 6,338                            |       | 8,690 |   | (26,299 | ) |
| Accrued  income taxes                                       |       | (5,264                           | )          | 17,165 |   | (18,807 | ) |
| Prepayments and  other                                      |       | 6,827                            |       | 906 |   | 321 |   |
| Sale of  accounts receivable (Note 4)                       |       | (58,000                          | )          | (5,200 | ) | 21,200 |   |
| Pension  funding                                            |       | (34,492                          | )          | (89,125 | ) | 336 |   |
| Gas supply  clause receivable, net                          |       | 10,296                           |       | (4,712 | ) | 3,873 |   |
| Litigation  settlement                                      |       | 6,972                            |       | — |   | — |   |
| Earnings sharing  mechanism receivable                      |       | 10,241                           |       | 142 |   | — |   |
| Other                                                       |       | 14,178                           |       | (6,178 | ) | (1,557 | ) |
| Net cash  provided by operating activities                  |       | 171,636                          |       | 163,250 |   | 212,381 |   |
|                                                        |       |                             |       |   |   |   |   |
| CASH FLOWS  FROM INVESTING ACTIVITIES:                      |       |                             |       |   |   |   |   |
| Proceeds  from sales of securities                          |       | 103                              |       | 153 |   | 412 |   |
| Construction  expenditures                                  |       | (148,306                         | )          | (212,957 | ) | (220,416 | ) |
| Net cash  used for investing activities                     |       | (148,203                         | )          | (212,804 | ) | (220,004 | ) |
|                                                        |       |                             |       |   |   |   |   |
| CASH FLOWS  FROM FINANCING ACTIVITIES:                      |       |                             |       |   |   |   |   |
| Increase in  restricted cash                                |       | (10,943                          | )          | — |   | — |   |
| Long-term  borrowings from affiliated company               |       | 125,000                          |       | 200,000 |   | — |   |
| Repayment of  long-term borrowings from affiliated company  |       | (50,000                          | )          | — |   | — |   |
| Repayment of  short-term borrowings                         |       | —                           |       | — |   | (29,944 | ) |
| Short-term  borrowings from affiliated company              |       | 552,800                          |       | 602,700 |   | 652,300 |   |
| Repayment of  short-term borrowings from affiliated company |       | (574,912                         | )          | (715,421 | ) | (523,500 | ) |
| Retirement  of first mortgage bonds                         |       | —                           |       | (42,600 | ) | — |   |
| Issuance of  pollution control bonds                        |       | —                           |       | 128,000 |   | 161,665 |   |
| Issuance  expense on pollution control bonds                |       | (135                             | )          | (5,843 | ) | (3,030 | ) |
| Retirement  of pollution control bonds                      |       | —                           |       | (128,000 | ) | (161,665 | ) |
| Retirement  of mandatorily redeemable preferred stock       |       | (1,250                           | )          | (1,250 | ) | — |   |
| Payment of  dividends                                       |       | (58,890                          | )          | (3,341 | ) | (73,300 | ) |
| Net cash  (used for) provided by financing activities       |       | (18,330                          | )          | 34,245 |   | 22,526 |   |
|                                                        |       |                             |       |   |   |   |   |
| Change in  cash and cash equivalents                        |       | 5,103                            |       | (15,309 | ) | 14,903 |   |
|                                                        |       |                             |       |   |   |   |   |
| Cash and  cash equivalents at beginning of year             |       | 1,706                            |       | 17,015 |   | 2,112 |   |
|                                                        |       |                             |       |   |   |   |   |
| Cash and  cash equivalents at end of year                   |       | $                                | 6,809      |   | $ | 1,706 |   | $ | 17,015 |   |
|                                                        |       |                             |       |   |   |   |   |
| Supplemental  disclosures of cash flow information:         |       |                             |       |   |   |   |   |
|                                                        |       |                             |       |   |   |   |   |
| Cash paid  during the year for:                             |       |                             |       |   |   |   |   |
| Income taxes                                                |       | $                                | 52,121     |   | $ | 24,868 |   | $ | 51,540 |   |
| Interest on  borrowed money                                 |       | 18,144                           |       | 23,829 |   | 25,673 |   |
| Interest to  affiliated companies on borrowed money         |       | 11,323                           |       | 4,162 |   | 1,850 |   |

 

The accompanying notes are an integral part of these consolidatedfinancial statements.

 

88

----

 

Louisville Gas and ElectricCompany and Subsidiary

Consolidated Statements of Capitalization

(Thousands of $)

 
| ** **                                                                      | ** ** | ** **              | ** ** | ** **                    | ** ** | **December 31** | ** ** |
|---------------------------------------------------------------------------------|------------|-------------------------|------------|-------------------------------|------------|----------------------|------------|
| ** **                                                                      | ** ** | ** **              | ** ** | ** **                    | ** ** | **2004**             | ** ** | **2003** | ** ** |
| LONG-TERM  DEBT (Note 9):                                                       |       |                    |       |                          |       |                 |       |   |   |
| Pollution  control series:                                                      |       |                    |       |                          |       |                 |       |   |   |
| S due September 1,  2017, variable %                                       |       |                    |       |                          |       | $                    | 31,000     |   | $ | 31,000 |   |
| T due September 1,  2017, variable %                                       |       |                    |       |                          |       | 60,000               |       | 60,000 |   |
| U due August 15,  2013, variable %                                         |       |                    |       |                          |       | 35,200               |       | 35,200 |   |
| X due April 15,  2023, 5.90%                                               |       |                    |       |                          |       | 40,000               |       | 40,000 |   |
| Y due May 1,  2027, variable %                                                  |       |                    |       |                          |       | 25,000               |       | 25,000 |   |
| Z due August 1,  2030, variable %                                          |       |                    |       |                          |       | 83,335               |       | 83,335 |   |
| AA due September 1,  2027, variable %                                      |       |                    |       |                          |       | 10,104               |       | 10,104 |   |
| BB due September 1,  2026, variable %                                      |       |                    |       |                          |       | 22,500               |       | 22,500 |   |
| CC due September 1,  2026, variable %                                      |       |                    |       |                          |       | 27,500               |       | 27,500 |   |
| DD due November 1,  2027, variable %                                       |       |                    |       |                          |       | 35,000               |       | 35,000 |   |
| EE due November 1,  2027, variable %                                       |       |                    |       |                          |       | 35,000               |       | 35,000 |   |
| FF due October 1,  2032, variable %                                        |       |                    |       |                          |       | 41,665               |       | 41,665 |   |
| GG due October 1,  2033, variable %                                        |       |                    |       |                          |       | 128,000              |       | 128,000 |   |
| Notes payable  to Fidelia:                                                      |       |                    |       |                          |       |                 |       |   |   |
| Due April 30,  2013, 4.55%, unsecured                                      |       |                    |       |                          |       | 100,000              |       | 100,000 |   |
| Due August 15,  2013, 5.31%, secured                                       |       |                    |       |                          |       | 100,000              |       | 100,000 |   |
| Due January 6,  2005, 1.53%, secured                                       |       |                    |       |                          |       | 50,000               |       | — |   |
| Due January 16,  2012, 4.33%, secured                                      |       |                    |       |                          |       | 25,000               |       | — |   |
| Mandatorily  redeemable preferred stock:                                        |       |                    |       |                          |       |                 |       |   |   |
| $ 5.875  series, outstanding shares of 225,000 in 2004 and 237,500 in 2003 |       |                    |       |                          |       | 22,500               |       | 23,750 |   |
|                                                                            |       |                    |       |                          |       |                 |       |   |   |
| Total  long-term debt outstanding                                               |       |                    |       |                          |       | 871,804              |       | 798,054 |   |
|                                                                            |       |                    |       |                          |       |                 |       |   |   |
| Less current  portion of long-term debt                                         |       |                    |       |                          |       | 297,450              |       | 247,450 |   |
|                                                                            |       |                    |       |                          |       |                 |       |   |   |
| Long-term  debt                                                                 |       |                    |       |                          |       | 574,354              |       | 550,604 |   |
|                                                                            |       |                    |       |                          |       |                 |       |   |   |
| CUMULATIVE  PREFERRED STOCK:                                                    |       |                    |       |                          |       |                 |       |   |   |
|                                                                            |       |                    |       |                          |       |                 |       |   |   |
| ** **                                                                      | ** ** | **Shares  Outstanding** | ** ** | **Current  Redemption Price** | ** ** | ** **           | ** ** | ** ** | ** ** |
| $25 par  value, 1,720,000 shares authorized - 5% series                         |       | 860,287                 |       | $                             | 28.00      |                 | 21,507     |   | 21,507 |   |
| Without par  value, 6,750,000 shares authorized - Auction rate                  |       | 500,000                 |       | $                             | 100.00     |                 | 50,000     |   | 50,000 |   |
| Preferred  stock expense, net                                                   |       |                    |       |                          |       | (1,082               | )          | (1,082 | ) |
|                                                                            |       |                    |       |                          |       |                 |       |   |   |
|                                                                            |       |                    |       |                          |       | 70,425               |       | 70,425 |   |
|                                                                            |       |                    |       |                          |       |                 |       |   |   |
| COMMON  EQUITY:                                                                 |       |                    |       |                          |       |                 |       |   |   |
| Common  stock, without par value -                                              |       |                    |       |                          |       |                 |       |   |   |
| Authorized  75,000,000 shares, outstanding 21,294,223 shares                    |       |                    |       |                          |       | 425,170              |       | 425,170 |   |
| Common stock  expense                                                           |       |                    |       |                          |       | (836                 | )          | (836 | )  |
| Additional paid-in  capital                                                     |       |                    |       |                          |       | 40,000               |       | 40,000 |   |
| Accumulated  other comprehensive income (Note 15)                               |       |                    |       |                          |       | (45,610              | )          | (38,111 | )  |
| Retained  earnings                                                              |       |                    |       |                          |       | 534,022              |       | 497,441 |   |
|                                                                            |       |                    |       |                          |       |                 |       |   |   |
|                                                                            |       |                    |       |                          |       | 952,746              |       | 923,664 |   |
|                                                                            |       |                    |       |                          |       |                 |       |   |   |
| Total  capitalization                                                           |       |                    |       |                          |       | $                    | 1,597,525  |   | $ | 1,544,693 |   |

 

The accompanying notes are an integral part of these consolidatedfinancial statements.

 

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Louisville Gasand Electric Company and SubsidiaryNotes to ConsolidatedFinancial Statements

 

**Note 1 - Summary of Significant AccountingPolicies**

 

LG&E, a subsidiary of LG&E Energy and an indirect subsidiary ofE.ON, is a regulated public utility engaged in the generation, transmission,distribution, and sale of electric energy and the storage, distribution, andsale of natural gas in Louisville and adjacent areas in Kentucky.  LG&E Energy is an exempt public utilityholding company with wholly owned subsidiaries including LG&E, KU, CapitalCorp., LEM, and LG&E Services.  Allof LG&E’s common stock is held by LG&E Energy.  In May 2004, LG&E dissolved its accountsreceivable securitization-related subsidiary, LG&E R.  Prior to May 2004, the consolidated financialstatements include the accounts of LG&E and LG&E R with the eliminationof intercompany accounts and transactions.

 

On December 11, 2000, LG&E Energy was acquired byPowergen.   On July 1, 2002, E.ON, aGerman company, completed its acquisition of Powergen plc (now PowergenLimited).  E.ON is a registered public utility holding company underPUHCA.

 

No costs associated with the E.ON purchase of Powergen or the Powergenpurchase of LG&E Energy nor any effects of purchase accounting have beenreflected in the financial statements of LG&E.

 

Effective December 30, 2003, LG&E Energy LLC became thesuccessor, by assignment and subsequent merger, to all assets and liabilitiesof LG&E Energy Corp.

 

Certain reclassification entries have been made to the previous years’financial statements to conform to the 2004 presentation with no impact on thebalance sheet net assets or previously reported income.  Effective December 31, 2004, operatingand non-operating income taxes are presented as “Federal and State Income Taxes”on LG&E’s Consolidated Statements of Income.  Prior to December 31, 2004, thecomponent of income taxes associated with operating income was included in netoperating income and the component of income taxes associated withnon-operating income taxes was included in other income (expense) – net.  LG&E has applied this change inpresentation to all prior periods.

 

**Regulatory Accounting. **Accounting for theregulated utility business conforms with generally accepted accountingprinciples as applied to regulated public utilities and as prescribed by FERCand the Kentucky Commission.  LG&E issubject to SFAS No. 71 under which certain costs that would otherwise becharged to expense are deferred as regulatory assets based on expected recoveryfrom customers in future rates. Likewise, certain credits that would otherwise be reflected as incomeare deferred as regulatory liabilities based on expected return to customers infuture rates.  LG&E’s current orexpected recovery of deferred costs and expected return of deferred credits isbased on specific ratemaking decisions or precedent for each item.  See Note 3 for additional detail regardingregulatory assets and liabilities.

 

**Utility Plant.**  LG&E’s utility plant is stated atoriginal cost, which includes payroll-related costs such as taxes, fringebenefits, and administrative and general costs. Construction work in progress has been included in the rate base fordetermining retail customer rates. LG&E has not recorded any allowance for funds used duringconstruction.

 

The cost of plant retired or disposed of in the normal course ofbusiness is deducted from plant accounts and such cost, plus removal expenseless salvage value, is charged to the reserve for depreciation.  When complete operating units are disposedof, appropriate adjustments are made to the reserve for depreciation and gainsand losses, if any, are recognized.

 

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**Depreciation and Amortization.**  Depreciation is provided on the straight-linemethod over the estimated service lives of depreciable plant.  The amounts provided were approximately 3.1%in 2004 (2.9% electric, 2.8% gas, and 7.6% common); 3.3% in 2003 (2.9%electric, 2.8% gas and 9.4% common); and 3.1% for 2002 (2.9% electric, 2.8% gasand 6.6% common), of average depreciable plant. Of the amount provided for depreciation, at December 31, 2004,approximately 0.4% electric, 0.9% gas and 0.04% common were related to theretirement, removal and disposal costs of long lived assets.   Of theamount provided for depreciation, at December 31, 2003, approximately 0.4%electric, 0.8% gas and 0.1% common were related to the retirement, removal anddisposal costs of long lived assets.

 

**Cash and Cash Equivalents. **LG&E considersall debt instruments purchased with a maturity of three months or less to becash equivalents.

 

**Restricted Cash. **A deposit in theamount of $10.9 million, used as collateral for a $83.3 million interest rateswap, is classified as restricted cash on LG&E’s balance sheet.

 

**Fuel Inventory.**  Fuel inventories of $21.8 million and $25.3million at December 31, 2004, and 2003, respectively, are included in Fuelin the balance sheet.  The inventory isaccounted for using the average-cost method.

 

**Gas Stored Underground.**  Gas inventories of $77.5 million and $69.9million at December 31, 2004, and 2003, respectively, are included in gasstored underground in the balance sheet. The inventory is accounted for using the average-cost method.

 

**Other Materials and Supplies. **Non-fuel materialsand supplies of $26.2 million and $25.0 million at December 31, 2004 and2003, respectively, are accounted for using the average-cost method.

 

**Financial Instruments.**  LG&E uses over-the-counter interest-rateswap agreements to hedge its exposure to fluctuations in the interest rates itpays on variable-rate debt.  Gains andlosses on interest-rate swaps used to hedge interest rate risk are reflected inother comprehensive income.  LG&Euses sales of market-traded electric forward contracts for periods less thanone year to hedge the price volatility of its forecasted peak electricoff-system sales.  Gains and lossesresulting from ineffectiveness are shown in other income (expense) and to theextent that the hedging relationship has been effective, gains and losses arereflected in other comprehensive income. Wholesale sales of excess asset capacity and wholesale purchases to beused to serve native load are treated as normal sales and purchases under SFAS No.133, SFAS No. 138 and SFAS No. 149 and are not marked-to-market.  See Note 4, Financial Instruments and Note15, Accumulated Other Comprehensive Income.

 

**Unamortized Debt Expense.**  Debt expense is capitalized in deferreddebits and amortized over the lives of the related bond issues, consistent withregulatory practices.

 

**Deferred Income Taxes.** Deferred income taxes are recognized atcurrently enacted tax rates for all material temporary differences between thefinancial reporting and income tax basis of assets and liabilities.

 

**Investment Tax Credits.**  Investment tax credits resulted fromprovisions of the tax law that permitted a reduction of LG&E’s taxliability based on credits for certain construction expenditures.  Deferred investment tax credits are beingamortized to income over the estimated lives of the related property that gaverise to the credits.

 

**Income Taxes.**Incometaxes are accounted for under SFAS No.109.  In accordance with thisstatement, deferred tax assets and liabilities are recognized for the futuretax consequences attributable to differences between the financialstatement carrying amounts of existing assets and liabilities and theirrespective tax bases, as measured by enacted tax rates that are expected to bein effect in the periods when the deferred tax assets and liabilities areexpected to be settled or realized. Significant judgment is required indetermining the provision

 

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for income taxes, and there are many transactions for which theultimate tax outcome is uncertain.  To provide for these uncertaintiesor exposures, an allowance is maintained for tax contingencies, thebalance of which management believes is adequate.  Tax contingencies areanalyzed periodically and adjustments are made when events occur to warrant achange.  The company is currently in the examination phase of IRSaudits for the years 1999 to 2003 and expects some or all of these auditsto be completed within the next 12 months.  The results of auditassessments by taxing authorities are not anticipated to have a materialadverse effect on cash flows or results of operations.

 

**RevenueRecognition.**  Revenuesare recorded based on service rendered to customers through month-end.  LG&E accrues an estimate for unbilledrevenues from each meter reading date to the end of the accounting period basedon allocating the daily system net deliveries between billed volumes andunbilled volumes. The allocation is based on a daily ratio of the number ofmeter reading cycles remaining in the month to the total number of meterreading cycles in each month.  Each day’sratio is then multiplied by each day’s system net deliveries to determine anestimated billed and unbilled volume for each day of the accountingperiod.  The unbilled revenue estimatesincluded in accounts receivable were approximately $63.0 million and $50.8million at December 31, 2004 and 2003, respectively.

 

**Allowancefor Doubtful Accounts.** At December 31, 2004 and 2003,the LG&E allowance for doubtful accounts was $0.8 million and $3.5 million,respectively. The allowance is based on the ratio of the amounts charged-offduring the last twelve months to the retail revenues billed over the sameperiod multiplied by the retail revenues billed over the last four months.  Accounts with no payment activity arecharged-off after four months.

 

**Fuel and Gas Costs.**  The cost of fuel for electric generation ischarged to expense as used, and the cost of gas supply is charged to expense asdelivered to the distribution system. LG&E implemented a Kentucky Commission-approved performance-basedratemaking mechanism related to gas procurement and off-system gas salesactivity.  See Note 3, Rates andRegulatory Matters.

 

**Other Property and Investments. **Other property andinvestments on the Balance Sheet consists of LG&E’s investment in OVEC andnon-utility plant.  As of December 31,2004 and 2003, LG&E’s investment in OVEC totaled $0.5 million.  In March 2005, LG&E purchased fromAEP an additional 0.73% interest in OVEC for a purchase price of approximately$0.1 million, which resulted in an increase in LG&E ownership in OVEC from4.9% to 5.63%.  LG&E is not theprimary beneficiary of OVEC, and, therefore, it is not consolidated into thefinancial statements of LG&E and is accounted for under the cost method of accounting.

 

**Management’s Use of Estimates.**  The preparation of financial statements inconformity with generally accepted accounting principles requires management tomake estimates and assumptions that affect the reported assets and liabilitiesand disclosure of contingent items at the date of the financial statements andthe reported amounts of revenues and expenses during the reporting period.  Accrued liabilities, including legal andenvironmental, are recorded when they are probable and estimable.  Actual results could differ from thoseestimates. See Note 11, Commitments and Contingencies, for a furtherdiscussion.

 

**New Accounting Pronouncements.**The following accounting pronouncements were issued that affected LG&E in2004 and 2003:

 

SFAS No. 143

 

SFAS No. 143 was issued in 2001. SFAS No. 143 establishes accounting and reporting standards forobligations associated with the retirement of tangible long-lived assets andthe associated asset retirement costs.

 

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The effective implementation date for SFAS No. 143 was January 1,2003.  Management has calculated theimpact of SFAS No. 143 and FERC Final Order No. 631 issued in Docket No.RM02-7.  As of January 1, 2003,LG&E recorded ARO assets in the amount of $4.6 million and liabilities inthe amount of $9.3 million.  LG&Ealso recorded a cumulative effect adjustment in the amount of $5.3 million toreflect the accumulated depreciation and accretion of ARO assets at thetransition date less amounts previously accrued under regulatory depreciation.  LG&E recorded offsetting regulatoryassets of $5.3 million, pursuant to regulatory treatment prescribed under SFASNo. 71.  Also pursuant to SFAS No. 71,LG&E recorded regulatory liabilities in the amount of $0.1 millionoffsetting removal costs previously accrued under regulatory accounting inexcess of amounts allowed under SFAS No. 143.

 

Had SFAS No. 143 been in effect for the 2002 reporting period, LG&Ewould have established asset retirement obligations as described in thefollowing table:

 
| **(in thousands)**                   | ** ** | ** ** | ** ** |
|--------------------------------------|------------|------------|------------|
| Provision at  January 1, 2002   |       | $          | 8,752      |   |
| Accretion  expense                   |       | 578        |       |
| Provision at  December 31, 2002 |       | $          | 9,330      |   |

 

As of December 31, 2004, LG&E had ARO assets, net ofaccumulated depreciation, of $3.3 million and liabilities of $10.3million.  As of December 31, 2003,LG&E had ARO assets, net of accumulated depreciation, of $3.5 million andliabilities of $9.7 million.  LG&Erecorded regulatory assets of $6.9 million and $6.0 million and regulatoryliabilities of $0.1 million as of both December 31, 2004 and 2003,respectively.

 

For the year ended December 31, 2004, LG&E recorded AROaccretion expense of approximately $0.7 million, ARO depreciation expense of$0.2 million and an offsetting regulatory credit in the income statement of$0.9 million, pursuant to regulatory treatment prescribed under SFAS No.71.  For the year ended December 31,2003, LG&E recorded ARO accretion expense of approximately $0.6 million,ARO depreciation expense of $0.1 million and an offsetting regulatory credit inthe income statement of $0.7 million. Removal costs incurred and charged against the ARO liability during 2004and 2003, were $0.1 million and $0.2 million, respectively.  SFAS No. 143 has no impact on the results ofoperations of LG&E.

 

LG&E AROs are primarily related to final retirement of assetsassociated with generating units.  Forassets associated with AROs, the removal cost accrued through depreciationunder regulatory accounting is established as a regulatory asset or liabilitypursuant to regulatory treatment prescribed under SFAS No. 71.  For the years ended December 31, 2004and 2003, LG&E recorded immaterial amounts (less than $0.1 million) ofdepreciation expense related to the cost of removal of ARO related assets.  An offsetting regulatory liability wasestablished pursuant to regulatory treatment prescribed under SFAS No. 71.

 

LG&E also continues to include a cost of removal component indepreciation for assets that do not have a legal ARO.  As of December 31, 2004 and 2003,LG&E has segregated this cost of removal, embedded in accumulateddepreciation, of $220.2 million and $216.5 million, respectively, in accordancewith FERC Order No. 631*.* Forreporting purposes in its Consolidated Balance Sheets, LG&E has presentedthis cost of removal as a regulatory liability pursuant to SFAS No. 71.

 

LG&E transmission and distribution lines largely operate underperpetual property easement agreements which do not generally requirerestoration upon removal of the property.  Therefore, under SFAS No. 143, no materialasset retirement obligations are recorded for transmission and distributionassets.

 

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EITF No. 02-03

 

LG&E adopted EITF No. 98-10**effective January 1,1999.  This pronouncement required thatenergy trading contracts be marked to market on the balance sheet, with thegains and losses shown net in the income statement.  Effective January 1, 2003, LG&Eadopted EITF No. 02-03.  EITF No. 02-03established the following:

 

•                  RescindedEITF No. 98-10,

•                  Contractsthat do not meet the definition of a derivative under SFAS No. 133 should notbe marked to fair market value, and

•                  Revenuesshould be shown in the income statement net of costs associated with tradingactivities, whether or not the trades are physically settled.

 

With the rescission of EITF No. 98-10, energy trading contracts that donot also meet the definition of a derivative under SFAS No. 133 must beaccounted for as executory contracts. Contracts previously recorded at fair value under EITF No. 98-10 thatare not also derivatives under SFAS No. 133 must be restated to historical costthrough a cumulative effect adjustment. The rescission of this standard had no impact on financial position orresults of operations of LG&E since all forward and option contracts markedto market under EITF No. 98-10 were 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 activitiesagainst electric operating revenue to reflect this accounting change.  LG&E applied this guidance to previouslyreported 2002 balances as shown below. The reclassifications had no impact on previously reported net income orcommon equity.

 
| **(in thousands)**                                        | ** ** | ** ** | ** ** |
|-----------------------------------------------------------|------------|------------|------------|
| Gross  electric operating revenues as previously reported |       | $          | 1,026,184  |   |
| Less costs  reclassified from power purchased             |       | 22,449     |       |
| Net electric  operating revenues                          |       | $          | 1,003,735  |   |
|                                                      |       |       |       |
| Gross power  purchased as previously reported             |       | $          | 84,330     |   |
| Less costs  reclassified to revenues                      |       | 22,449     |       |
| Net power  purchased                                      |       | $          | 61,881     |   |

 

SFAS No. 150

 

In May 2003,the Financial Accounting Standards Board issued SFAS No. 150, which waseffective immediately for financial instruments entered into or modified afterMay 31, 2003, and otherwise was effective for interim reporting periodsbeginning after June 15, 2003, except for certain instruments and certainentities which have been deferred by the FASB. Such deferrals do not affect LG&E.

 

LG&E has$5.875 series mandatorily redeemable preferred stock outstanding having acurrent redemption price of $100 per share. The preferred stock has a sinkingfund requirement sufficient to retire a minimum of 12,500 shares on July 15of each year commencing with July 15, 2003, and the remaining 187,500 shareson July 15, 2008 at $100 per share. LG&E redeemed 12,500 shares in accordance with these provisions on July 15,2004 and 2003, leaving 225,000 shares currently outstanding.  Beginning with the three months ended September 30,2003, LG&E reclassified its $5.875 series preferred stock as long-term debtwith the minimum shares mandatorily redeemable within one year classified ascurrent.  Dividends accrued beginning July 1,2003 are charged as interest expense.

 

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FIN 46

 

In January 2003, the Financial Accounting Standards Board issuedFIN 46.  FIN 46 requires certain variableinterest entities to be consolidated by the primary beneficiary of the entityif the equity investors in the entity do not have the characteristics of acontrolling financial interest or do not have sufficient equity at risk for theentity to finance its activities without additional subordinated financialsupport from other parties.  FIN 46 was effectiveimmediately for all new variable interest entities created or acquired after January 31,2003.  For variable interest entitiescreated or acquired prior to February 1, 2003, the provisions of FIN 46must have been applied for the first interim or annual period beginning after June 15,2003.

 

In December 2003, FIN 46 was revised, delaying the effective datesfor certain entities created before February 1, 2003, and making otheramendments to clarify application of the guidance.  For potential variable interest entitiesother than special purpose entities, FIN 46R was required to be applied nolater than the end of the first fiscal year or interim reporting period endingafter March 15, 2004.  The originalguidance under FIN 46 was applicable, however, for all special purpose entitiescreated prior to February 1, 2003, at the end of the first interim orannual reporting period ending after December 15, 2003.  FIN 46R may be applied prospectively with acumulative-effect adjustment as of the date it is first applied, or byrestating previously issued financial statements with a cumulative-effectadjustment as of the beginning of the first year restated.  FIN 46R also requires certain disclosures ofan entity’s relationship with variable interest entities. The adoption of FIN46 and FIN 46R has no impact on the financial position or results of operationsof LG&E.

 

Although LG&E holds an investment interest in OVEC, it is not theprimary beneficiary of OVEC and, therefore, OVEC is not consolidated into thefinancial statements of LG&E.

 

LG&E and 11 other electric utilities are participating owners ofOVEC, located in Piketon, Ohio. OVEC owns and operates two power plants thatburn coal to generate electricity, Kyger Creek Station in Ohio and Clifty CreekStation in Indiana.  Through March 2006,LG&E’s share is 7%, representing approximately 155 Mw of generationcapacity, and 5.63% thereafter.

 

LG&E’s original investment in OVEC was made in 1952.  As of December 31, 2004, LG&E’sinvestment in OVEC totaled $0.5 million. In March 2005, LG&E purchased from AEP an additional 0.73%interest in OVEC for a purchase price of approximately $0.1 million, whichresulted in an increase in LG&E ownership in OVEC from 4.9% to 5.63%.  LG&E’s investment in OVEC is accountedfor under the cost method of accounting.

 

LG&E’s maximum exposure to loss as a result of its involvement withOVEC is limited to the value of the investment. In the event of the inability of OVEC to fulfill its power provisionrequirements, LG&E would substitute such power supply with either ownedgeneration or market purchases and would generally recover associatedincremental costs through regulatory rate mechanisms.  See Note 11 for further discussion ofdevelopments regarding LG&E’s ownership interest and power purchase rights.

 

FSP 106-2

 

In May 2004, the FASB finalized FSP 106-2 with guidance on accountingfor subsidies provided under the Medicare Act which became law in December 2003.  FSP 106-2 is effective for the first interimor annual period beginning after June 15, 2004.  FSP 106-2 does not have a material impact onLG&E.

 

FSP 109-1

 

In December 2004, the FASB finalized FSP 109-1*,*which**requires the tax deduction on qualified production activities to betreated as a special deduction in accordance with FAS 109.  FSP 109-1 became effective

 

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December 21, 2004, and does not have a material impact onLG&E.

 

**Note 2 – Mergers and Acquisitions**

 

On July 1,2002, E.ON completed its acquisition of Powergen, including LG&E Energy,for approximately £5.1 billion ($7.3 billion). As a result of the acquisition, LG&E Energy became a wholly ownedsubsidiary of E.ON and, as a result, LG&E also became an indirectsubsidiary of E.ON.  LG&E hascontinued its separate identity and serves customers in Kentucky under itsexisting name.  The preferred stock anddebt securities of LG&E were not affected by this transaction and theutilities continue to file SEC reports. Following the acquisition, E.ON became a registered holding companyunder PUHCA. LG&E, as a subsidiary of a registered holding company, issubject to additional regulations under PUHCA. In March 2003, E.ON, Powergen and LG&E Energy completed anadministrative reorganization to move the LG&E Energy group from anindirect Powergen subsidiary to an indirect E.ON subsidiary.  In early 2004, LG&E Energy commenceddirect reporting arrangements to E.ON.

 

LG&EEnergy and KU Energy merged on May 4, 1998, with LG&E Energy as thesurviving corporation.  Managementaccounted for the merger as a pooling of interests and as a tax-freereorganization under the Internal Revenue Code. Following the acquisition, LG&E has continued to maintain itsseparate corporate identity and serve customers under its present name.

 

**Note 3 -Rates and Regulatory Matters**

 

Electric andGas Rate Cases

 

In December 2003,LG&E filed applications with the Kentucky Commission requesting adjustmentsin LG&E’s electric and gas rates. LG&E asked for general adjustments in electric and gas rates basedon the twelve month test year ended September 30, 2003.  The revenue increases requested were $63.8million for electric and $19.1 million for gas.

 

On June 30, 2004, theKentucky Commission issued an order approving increases in the base electricand gas rates of LG&E.  The KentuckyCommission’s order largely accepted proposed settlement agreements filed in May2004 by LG&E and a majority of the parties to the rate caseproceedings.   The rate increases tookeffect on July 1, 2004.

 

In the KentuckyCommission’s order, LG&E was granted increases in annual base electricrates of approximately $43.4 million (7.7%) and in annual base gas rates ofapproximately $11.9 million (3.4%). Other provisions of the order include decisions on certain depreciation,gas supply clause, ECR and VDT amounts or mechanisms and a termination of theESM with respect to all periods after 2003. The order also provided for a recovery before March 31, 2005, byLG&E of previously requested amounts relating to the ESM during 2003.

 

During July 2004, the AGserved subpoenas on LG&E, as well as on the Kentucky Commission and itsstaff, requesting information regarding allegedly improper communicationsbetween LG&E and the Kentucky Commission, particularly during the periodcovered by the rate cases. The Kentucky Commission has procedurally reopenedthe rate cases for the limited purpose of taking evidence, if any, as to thecommunication issues. Subsequently, the AG filed pleadings with the KentuckyCommission requesting rehearing of the rate cases on certain computational componentsof the increased rates, including income tax, cost of removal and depreciationamounts. In August 2004, the Kentucky Commission denied the AG’s rehearingrequest on the cost of removal and depreciation issues, with the effect thatthe rate increase order is final as to these matters, subject to the parties’rights to judicial appeals. The Kentucky Commission further agreed to hold inabeyance further proceedings in the rate cases, including the AG’s concernsabout alleged improper communications,

 

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until the AG could file withthe Kentucky Commission an investigative report regarding the latter issue. Inaddition, the Kentucky Commission granted a rehearing on the income taxcomponent once the abeyance discussed above is lifted.

 

In September andOctober 2004, various proceedings were held in circuit courts in Franklinand Jefferson Counties, Kentucky regarding the scope and timing of documentproduction or other information required or agreed to be produced under the AG’ssubpoenas and matters were consolidated into the Franklin County court.  In October 2004, the AG filed a motionwith the Kentucky Commission requesting that the previously granted rateincreases be set aside, that LG&E resubmit any applications for rateincreases and that relevant Kentucky Commission personnel be recused fromparticipation in rate case proceedings. In November 2004, the Franklin County, Kentucky court denied an AGrequest for sanctions on LG&E relating to production matters and narrowedthe AG’s permitted scope of discovery.  In January 2005, the AG conducted interviews of certain Companyindividuals.

 

In January 2005,the AG submitted its report to the Franklin County, Kentucky Circuit Court inconfidence.  Concurrently the AG filed amotion summarizing the report as containing evidence of improper communicationsand record-keeping errors by LG&E in its conduct of activities before theKentucky Commission or other state governmental entities and requesting releaseof the report to such agencies.  During February 2005the court ruled that the report be forwarded to the Kentucky Commission undercontinued confidential treatment to allow it to consider the report, includingits impact, if any, on completing its investigation and any remaining steps inthe rate cases, including ending the current abeyance.  To date, LG&E has neither seen norrequested copies of the report or its contents.

 

LG&Ebelieves no improprieties have occurred in its communications with the KentuckyCommission and is cooperating with the proceedings before the AG and theKentucky Commission.

 

LG&E iscurrently unable to determine the ultimate impact, if any, of, or any possiblefuture actions of the AG or the Kentucky Commission arising out of, the AG’sreport and investigation, including whether there will be further actions to appeal,review or otherwise challenge the granted increases in base rates.

 

RegulatoryAssets and Liabilities

 

The followingregulatory assets and liabilities were included in LG&E’s balance sheets asof December 31:

 
| **(in thousands)**                            | ** ** | **2004** | ** ** | **2003** | ** ** |
|-----------------------------------------------|------------|----------|------------|----------|------------|
|                                          |       |     |       |     |       |
| VDT Costs                                     |       | $        | 37,676     |     | $          | 67,810 |   |
| Unamortized  loss on bonds                    |       | 20,272   |       | 21,333   |       |
| ARO                                           |       | 6,870    |       | 6,015    |       |
| Merger  surcredit                             |       | 4,838    |       | 6,220    |       |
| ESM                                           |       | 2,118    |       | 12,359   |       |
| Rate case  expenses                           |       | 1,111    |       | 854      |       |
| FAC                                           |       | 842      |       | —   |       |
| DSM                                           |       | —   |       | 24       |       |
| Gas supply  adjustments due from customers    |       | 13,320   |       | 22,077   |       |
| Gas  performance base ratemaking              |       | 3,673    |       | 5,480    |       |
| Manufactured  gas sites                       |       | 1,146    |       | 1,454    |       |
| Total  regulatory assets                      |       | $        | 91,866     |     | $          | 143,626 |   |
|                                          |       |     |       |     |       |
| Accumulated  cost of removal of utility plant |       | $        | 220,214    |     | $          | 216,491 |   |
| Deferred  income taxes - net                  |       | 37,184   |       | 41,180   |       |
| ECR                                           |       | 4,039    |       | 17       |       |
| DSM                                           |       | 2,439    |       | 1,706    |       |
| ARO                                           |       | 136      |       | 85       |       |
| FAC                                           |       | 8        |       | 1,950    |       |
| ESM                                           |       | —   |       | 79       |       |
| Gas supply  adjustments due to customers      |       | 8,344    |       | 6,805    |       |
| Total  regulatory liabilities                 |       | $        | 272,364    |     | $          | 268,313 |   |

 

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LG&E currently earns a return on all regulatory assets except forgas supply adjustments, ESM, FAC, gas performance based ratemaking and DSM, allof which are separate rate mechanisms with recovery within twelve months.  Additionally, no current return is earned onthe ARO regulatory asset.  This regulatoryasset will be offset against the associated regulatory liability, ARO asset,and ARO liability at the time the underlying asset is retired.  See Note 1, Summary of Significant AccountingPolicies.

 

**VDT Costs - Kentucky Commission SettlementOrder. **Duringthe first quarter of 2001, LG&E recorded a $144 million charge for aworkforce reduction program.  Primarycomponents of the charge were separation benefits, enhanced early retirementbenefits, and healthcare benefits.  Theresult of this workforce reduction was the elimination of approximately 700positions, accomplished primarily through a voluntary enhanced severanceprogram.

 

In June 2001, LG&E filed an application (VDT case) with theKentucky Commission to create a regulatory asset relating to these firstquarter 2001 charges.  The applicationrequested permission to amortize these costs over a four-year period.  The Kentucky Commission also opened a case toreview a new depreciation study and resulting depreciation rates implemented in2001.

 

In December 2001, the Kentucky Commission approved a settlement inthe VDT case as well as other cases involving the depreciation rates and ESM.The order approving the settlement allowed LG&E to set up a regulatoryasset of $141 million for the workforce reduction costs and begin amortizingthese costs over a five-year period starting in April 2001. The firstquarter 2001 charge of $144 million represented all employees who had accepteda voluntary enhanced severance program. Some employees rescinded their participation in the voluntary enhancedseverance program, thereby decreasing the original charge to the regulatoryasset from $144 million to $141 million. The settlement reduces revenues approximately$26 million through a surcredit on bills to ratepayers over the same five-yearperiod.  The surcredit represents netsavings stipulated by LG&E.

 

As mentioned, the current five-year VDT amortization period isscheduled to expire in March 2006. As part of the settlement agreements in the electric and gas rate cases,LG&E shall file with the Kentucky Commission a plan for the future ratemakingtreatment of the VDT surcredits and costs six months prior to the March 2006expiration.  The surcredit shall remainin effect following the expiration of the fifth year until the Commissionenters an order on the future disposition of VDT-related issues.

 

**ARO.**  At December 31, 2004 and 2003, LG&Ehad recorded $6.9 million and $6.0 million in regulatory assets and $0.1million and $0.1 million in regulatory liabilities, respectively, related toSFAS No. 143.

 

**Merger Surcredit.**  As part of the LG&E Energy merger with KUEnergy in 1998, LG&E Energy estimated non-fuel savings over a ten-yearperiod following the merger.  Costs toachieve these savings for LG&E of $50.2 million were recorded in the secondquarter of 1998, $18.1 million of which was deferred and amortized over afive-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 remainingcosts associated with the merger ($32.1 million) in the second quarter of 1998.

 

In approving the merger, the Kentucky Commission adopted LG&E’sproposal to reduce its retail customers’ bills based on one-half of theestimated merger-related savings, net of deferred and amortized amounts, over afive-year period.  The surcreditmechanism provides that 50% of the net non-fuel cost savings estimated to be

 

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achieved from the merger be provided to ratepayers through a monthlybill credit, and 50% be retained by LG&E and KU, over a five-yearperiod.  The surcredit was allocated 53%to KU and 47% to LG&E.  In that sameorder, the Commission required LG&E and KU, after the end of the five-yearperiod, to present a plan for sharing with ratepayers the then-projectednon-fuel savings associated with the merger. The Companies submitted this filing in January 2003, proposing tocontinue to share with ratepayers, on a 50%/50% basis, the estimated fifth-yeargross level of non-fuel savings associated with the merger.  In October 2003, the Kentucky Commissionissued an order approving a settlement agreement reached with the parties inthe case.  LG&E’s merger surcreditwill remain in place for another five-year term beginning July 1, 2003 andthe merger savings will continue to be shared 50% with ratepayers and 50% withshareholders.

 

**ESM.**  Prior to 2004, LG&E’s retail electricrates were subject to an ESM.  The ESM,initially in place for three years beginning in 2000, set an upper and lowerpoint for rate of return on equity, whereby if LG&E’s rate of return forthe calendar year fell within the range of 10.5% to 12.5%, no action wasnecessary.  If earnings were above theupper limit, the excess earnings were shared 40% with ratepayers and 60% withshareholders; if earnings were below the lower limit, the earnings deficiencywas recovered 40% from ratepayers and 60% from shareholders.  By order of the Kentucky Commission, ratechanges prompted by the ESM filing went into effect in April of each yearsubject to a balancing adjustment in successive periods.

 

In November 2002, LG&E filed a revised ESM tariff whichproposed continuance of the existing ESM through December 2005.  In addition, the Kentucky Commission initiated a focused management audit to review the ESMplan and reassess its reasonableness.  LG&Eand interested parties had the opportunity to provide recommendations formodification and continuance of the ESM or other forms of alternative orincentive regulation.

 

LG&E filed its final 2003 ESM calculations with the Kentucky Commissionon March 1, 2004, and applied for recovery of $13.0 million. Based uponestimates, LG&E previously accrued $8.9 million for the 2003 ESM as of December 31,2003.

 

On June 30, 2004, the Kentucky Commission issued an order largelyaccepting proposed settlement agreements by LG&E and all intervenorsregarding the ESM.  Under the ESMsettlements, LG&E will continue to collect approximately $13.0 million ofpreviously requested 2003 ESM revenue amounts through March 2005.  As part of the settlement, the parties agreedto a termination of the ESM mechanism relating to all periods after 2003.

 

As a result of the settlement, LG&E accrued an additional $4.1million in June 2004, related to 2003 ESM revenue.

 

**FAC. **LG&E’sretail electric rates contain a FAC, whereby increases and decreases in thecost of fuel for electric generation are reflected in the rates charged toretail customers.  In January 2003,the Kentucky Commission reviewed KU’s FAC and, as part of the order in thatcase, required that an independent audit be conducted to examine operationaland management aspects of both LG&E’s and KU’s fuel procurementfunctions.  The final report was issuedin February 2004.  The report’srecommendations related to documentation and process improvements.  Management Audit Action Plans were agreedupon by LG&E and the Kentucky Commission Staff in the second quarter of2004.  LG&E filed its first AuditProgress Report with the Kentucky Commission Staff in November 2004.  A second Audit Progress Report is due in May2005.

 

The Kentucky Commission requires public hearings at six-month intervalsto examine past fuel adjustments, and at two-year intervals to review pastoperations of the fuel clause and transfer of the then current fuel adjustmentcharge or credit to the base charges.  Nosignificant issues have been identified as a result of these reviews.

 

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In December 2004, the KentuckyCommission initiated a two-year review of LG&E’s past operations of thefuel clause and transfer of fuel costs from the fuel adjustment clause to baserates.  A public hearing on the matterwas held on March 17, 2005.  Anorder by the Kentucky Commission is expected in April 2005.  LG&E is seeking to increase the fuelcomponent of base rates.  LG&E doesnot anticipate any issues will arise during the regulatory proceeding.

 

**DSM.**  LG&E’s rates contain a DSMprovision.  The provision includes a ratemechanism that provides concurrent recovery of DSM costs and provides anincentive for implementing DSM programs. This provision allowed LG&E to recover revenues from lost salesassociated with the DSM programs.  In May2001, the Kentucky Commission approved LG&E’s plan to continue DSMprograms.  This plan called for theexpansion of the LG&E DSM programs into the service territory served by KUand proposed a mechanism to recover revenues from lost sales associated withDSM programs based on program plan engineering estimates andpost-implementation evaluations.

 

**Gas Supply Cost PBR Mechanism.  **Since November 1,1997, LG&E has operated under a PBR mechanism related to its gas procurementactivities.   LG&E’s rates areadjusted annually to recover its portion of the savings (or expenses) incurredduring each PBR year (12 months ending October 31). Since itsimplementation on November 1, 1997, through October 31, 2004,LG&E has achieved $60.7 million in savings. Of that total savings amount,LG&E’s portion has been $22.7 million and the ratepayers’ portion has been$38.0 million.  Pursuant to the extensionof LG&E’s gas supply cost PBR mechanism effective November 1, 2001,the sharing mechanism under PBR requires savings (and expenses) to be shared25% with shareholders and 75% with ratepayers up to 4.5% of the benchmarked gascosts.  Savings (and expenses) in excessof 4.5% of the benchmarked gas costs are shared 50% with shareholders and 50%with ratepayers.  LG&E filed a reportand assessment with the Kentucky Commission on December 30, 2004, seekingmodification and extension of the mechanism.

 

**Accumulated Cost of Removal. **As of December 31,2004 and 2003, LG&E has segregated the cost of removal, embedded inaccumulated depreciation, of $220.2 million and $216.5 million, respectively,in accordance with FERC Order No. 631. For reporting purposes in the Consolidated Balance Sheets, LG&E haspresented this cost of removal as a regulatory liability pursuant to SFAS No.71.

 

**ECR. **InMay 2002, the Kentucky Commission initiated a periodic two-year review ofLG&E’s environmental surcharge.  Thereview included the operation of the surcharge mechanism, determination of theappropriateness of costs included in the surcharge mechanism, recalculation ofthe cost of debt to reflect actual costs for the period under review, finaldetermination of the amount of environmental revenues over-collected fromcustomers, and a final determination of the amount of environmental costs andrevenues to be “rolled-in” to base rates. A final order was issued in October 2002, in which LG&E wasordered to refund $0.3 million to customers over the four month periodbeginning 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 monthlyenvironmental surcharge filings to reflect that portion of environmental ratebase now included in base rates.

 

In August 2002, LG&E filed an application with the KentuckyCommission to amend its compliance plan to allow recovery of the cost of newand additional environmental compliance facilities.  The estimated capital cost of the additionalfacilities is $71.1 million.  A finalorder was issued in February 2003, approving recovery of four newenvironmental compliance facilities totaling $43.1 million.  A fifth project, expansion of the landfillfacility at the Mill Creek Station, was denied without prejudice with aninvitation to reapply for recovery when required construction permits are approved.  Cost recovery through the environmentalsurcharge of the four approved projects commenced with bills rendered in April 2003.

 

In January 2003, the Kentucky Commission initiated a six-monthreview of LG&E’s environmental surcharge.

 

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A final order was issued in April 2003, in which LG&E wasordered to refund $2.9 million it had previously over-collected fromcustomers.  In July 2003, theKentucky Commission initiated a two-year review of LG&E’s environmentalsurcharge.  A final order was issued in December 2003in which LG&E was ordered to roll $15.2 million of environmental assetsinto base rates and make corresponding adjustments to the monthly environmentalsurcharge filings to reflect that portion of environmental rate base nowincluded in base rates on a going-forward basis.  Additionally, LG&E was ordered to collect$0.2 million to correct for amounts under-collected from customers.  The rates of return for LG&E’s 1995 andpost-1995 plans were reset to 3.32% and 10.92%, respectively.

 

In June 2004, the Kentucky Commission issued an order approving asettlement agreement that, among other things, revised the rate of return forLG&E’s post-1995 plan to 10.72%, with an 11% return on common equity. Theorder also approved the elimination of LG&E’s 1995 plan from its ECRbilling mechanism, with all remaining costs associated with that plan to beincluded in their entirety in base rates.

 

In December 2004, LG&E filed an application with the KentuckyCommission to amend its compliance plan to allow recovery of the cost of newand additional environmental compliance facilities, including the expansion ofthe landfill facility at the Mill Creek station.  The estimated capital cost of the additionalfacilities is $40.2 million.  LG&Erequested an overall rate of return of 10.72%, including an 11% return oncommon equity.  A final order in the caseis anticipated in June 2005.

 

Other Regulatory Matters

 

**MISO. **LG&Eis a founding member of the MISO.  Membershipwas obtained in 1998 in response to and consistent with federal policyinitiatives.  In February 2002,LG&E turned over operational control of their high voltage transmissionfacilities (100kV and above) to the MISO. The MISO currently controls over 100,000 miles of transmission linesover 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 and the restof the MISO owners.  On February 18,2005, the United States Court of Appeals for the District of Columbia Circuitruled that FERC did not provide proper notice that it would consider anincentive adder of 50 basis points, but affirmed the September 2002 FERCorder in all other respects.  EffectiveROE, retroactive to February 1, 2002, is 12.38% for LG&E and theoriginal MISO owners.

 

In October 2001, the FERC issued an order requiring that thebundled retail load and grandfathered wholesale load of each membertransmission owner be included in the current calculation of the MISO’s “cost-adder,”the Schedule 10 charges designed to recover the MISO’s costs of operation,including start-up capital (debt) costs. LG&E, along with several other transmission owners, opposed the FERC’sruling on this matter. The opposition was rejected by the FERC in 2002.   Later that year, the MISO’s transmissionowners, appealed the FERC’s decision to the United States Court of Appeals forthe District of Columbia Circuit.  Inresponse, in November 2002, the FERC requested that the Court issue a partialremand of its challenged orders to allow the FERC to revisit certain issues,and requested that the case be held in abeyance pending the agency’s resolutionof such issues.  The Court granted theFERC’s petition in December 2002.  In February 2003, FERC issued an order reaffirming its positionconcerning the calculation of the Schedule 10 charges and in July 2003denied a rehearing.  LG&E, along withseveral other transmission owners, again petitioned the District Court ofColumbia Circuit for review. In July 2004 the court affirmed the FERCruling.

 

In August 2004, the MISO filed its FERC-required proposed TEMT.  In September and October 2004, manyMISO-related parties (including LG&E) filed proposals with the FERCregarding pending MISO-filed changes to transmission pricing principles,including the TEMT and elimination of RTORs. Additional filings of thecompanies before FERC in September 2004 sought to address issues relating tothe treatment of certain GFA's should TEMT become effective. The utilityproposals generally seek to appropriately delay the RTOR and TEMT effectivedates based upon errors in administrative or procedural processes used by FERCor to appropriately limit potential reductions in transmission revenuesreceived by the utilities should the RTOR, TEMT or GFA structures beimplemented.  At present, existing FERCorders conditionally approve elimination of RTORs and implementation of generalTEMT rates in the MISO by spring 2005. At this time, LG&E cannot predict the outcome or effects of thevarious FERC proceedings described above, including whether such will have amaterial impact on the financial condition or results of operations of thecompanies. Financial consequences (changes in transmission revenues and costs)associated with the upcoming transmission market tariff changes are subject tovarying assumptions and calculations and are therefore difficult to estimate.Changes in revenues and costs related to broader shifts in energy marketpractices and economics are not currently estimable.  Should LG&E be ordered to exit MISO,current MISO rules may also impose an exit fee. LG&E is not able to predict the estimated outcome or economic impactof any of the MISO-related matters. While LG&E believes legal and regulatory precedent should permitmost or many of the MISO-related costs to be recovered in their rates chargedto customers, they can give no assurance that state or federal regulators willultimately agree with such position with respect to all costs, components ortiming of recovery.

 

The MISO plans to implement a Day-ahead and Real-time market, includinga congestion management system in April 2005. This system will be similarto the LMP system currently used by the PJM RTO and contemplated in FERC’s SMDNOPR, currently being discussed.  TheMISO filed with FERC a mechanism for recovery of costs for the congestion managementsystem.  They proposed the addition oftwo new Schedules, 16 and 17.  Schedule 16is the MISO’s cost recovery mechanism for the Financial Transmission RightsAdministrative Service it will provide.  Schedule 17

 

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is the MISO’s mechanism for recovering costs it will incur forproviding Energy Marketing Support Administrative Service.  The MISO transmission owners, includingLG&E, have objected to the allocation of costs among market participantsand retail native load. FERC ruled in 2004 in favor of the MISO.

 

The Kentucky Commission opened an investigation into LG&E’smembership in the MISO in July 2003. The Kentucky Commission directedLG&E to file testimony addressing the costs and benefits of the MISOmembership both currently and over the next five years and other legal issuessurrounding continued membership. LG&E engaged an independent third-party to conduct a cost benefitanalysis on this issue.  The informationwas filed with the Kentucky Commission in September 2003.  The analysis and testimony supported the exitfrom the MISO, under certain conditions. The MISO filed its own testimony and cost benefit analysis in December 2003.  A final Kentucky Commission order wasexpected in the second quarter of 2004; that ruling has since been delayeduntil summer 2005 due to the Kentucky Commission’s request for additionaltestimony on the MISO’s Market Tariff filing at FERC.

 

**Kentucky CommissionAdministrative Case for System Adequacy. **In June 2001,Kentucky’s Governor issued Executive Order 2001-771, which directed theKentucky Commission to review and study issues relating to the need for anddevelopment of new electric generating capacity in Kentucky.  In response to that Executive Order, in July 2001the Kentucky Commission opened Administrative Case No. 387 to review theadequacy of Kentucky’s generation capacity and transmission system.  Specifically, the items reviewed were theappropriate level of reliance on purchased power, the appropriate reservemargins to meet existing and future electric demand, the impact of spikes innatural gas prices on electric utility planning strategies, and the adequacy ofKentucky’s electric transmission facilities. In December 2001, the Kentucky Commission issued an order in whichit noted that LG&E is responsibly addressing the long-term supply needs ofnative load customers and that current reserve margins are appropriate.  However, due to the rapid pace of change inthe industry, the order also requires LG&E to provide an annual assessmentof supply resources, future demand, reserve margin, and the need for newresources.

 

Regarding the transmission system, the Kentucky Commission concludedthat the transmission system within Kentucky can reliably serve native load anda significant portion of the proposed new unregulated power plants.  However, it will not be able to handle thevolume of transactions envisioned by FERC without future upgrades, the costs ofwhich should be borne by those for whom the upgrades are required.

 

The Kentucky Commission pledged to continue to monitor all relevantissues and advocate Kentucky’s interests at all opportunities.

 

**Kentucky Commission Strategic Blueprint. **In February 2005,Kentucky’s Governor signed an executive order directing the Kentucky Commission,in conjunction with the Commerce Cabinet and the Environmental and PublicProtection Cabinet, to ‘develop a Strategic Blueprint for the continued use anddevelopment of electric energy.’ This Strategic Blueprint will be designed topromote future investment in electric infrastructure for the Commonwealth ofKentucky, to protect Kentucky’s low-cost electric advantage, to maintain affordablerates for all Kentuckians, and to preserve Kentucky’s commitment toenvironmental protection.  In March 2005,the Kentucky Commission established Administrative Case No. 2005-00090 tocollect information from all jurisdictional utilities in Kentucky, includingLG&E, pertaining to Kentucky electric generation, transmission anddistribution systems.  The KentuckyCommission must provide its Strategic Blueprint to the Governor in early August 2005.  LG&E must respond to the KentuckyCommission’s first set of data requests by the end of March 2005.

 

**FERC SMD NOPR. **In July 2002,the FERC issued a NOPR in Docket No. RM01-12-000 which would substantiallyalter the regulations governing the nation’s wholesale electricity markets byestablishing a common set of rules, defined as SMD. The SMD NOPR would requireeach public utility that owns, operates,

 

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or controls interstate transmission facilities to become an ITP, belongto an RTO that is an ITP, or contract with an ITP for operation of itstransmission assets. It would also establish a standardized congestionmanagement system, real-time and day-ahead energy markets, and a single transmissionservice for network and point-to-point transmission customers. Review of theproposed rulemaking is underway and no timeframe has been established by theFERC for adoption of a final rule.  Whileit is expected that the SMD final rule will affect LG&E revenues andexpenses, the specific impact of the rulemaking is not known at this time.

 

**Kentucky Commission Administrative Case forAffiliate Transactions. **InDecember 1997, the Kentucky Commission opened Administrative Case No. 369to consider Kentucky Commission policy regarding cost allocations, affiliatetransactions and codes of conduct governing the relationship between utilitiesand their non-utility operations and affiliates.  The Kentucky Commission intended to addresstwo major areas in the proceedings: the tools and conditions needed to preventcost shifting and cross-subsidization between regulated and non-utilityoperations; and whether a code of conduct should be established to assure thatnon-utility segments of the holding company are not engaged in practices thatcould result in unfair competition caused by cost shifting from the non-utilityaffiliate to the utility.  In early 2000,the Kentucky General Assemblyenacted legislation, House Bill 897, which authorized the Kentucky Commissionto require utilities that provide nonregulated activities to keep separateaccounts and allocate costs in accordance with procedures established by theKentucky Commission.  In the same bill,the General Assembly set forth provisions to govern a utility’s activitiesrelated to the sharing of information, databases, and resources between itsemployees or an affiliate involved in the marketing or the provision ofnonregulated activities and its employees or an affiliate involved in theprovision of regulated services. The legislation became law in July 2000and LG&E has been operating pursuant thereto since that time.  In February 2001, the KentuckyCommission published notice of its intent to promulgate new administrativeregulations under the auspices of this new law. This effort is still on-going.

 

**Wholesale Natural Gas Prices.**  On September 12, 2000, the KentuckyCommission issued an order establishing Administrative Case No. 384 – “AnInvestigation of Increasing Wholesale Natural Gas Prices and the Impacts ofsuch Increase on the Retail Customers Served by Kentucky’s JurisdictionalNatural Gas Distribution Companies”.

 

Subsequent to thisinvestigation, the Kentucky Commission issued an order on July 17, 2001,encouraging the natural gas distribution companies in Kentucky to take variousactions, among them to propose a natural gas hedge plan, considerperformance-based ratemaking mechanisms, and to increase the use of storage.

 

In May 2004, in Case No. 2004-148, LG&E proposed a hedge plan forthe 2004/2005 winter heating season relying upon LG&E’s storage to mitigate customer exposure to pricevolatility. In August 2004, the Kentucky Commission approved LG&E’sproposed hedge plan, validating the effectiveness of storage to mitigatepotential volatility associated with high winter gas prices by approving thisnatural gas hedge plan.  The KentuckyCommission also ordered that LG&E need not file hedge plans in the futureunless it intended to utilize financial hedging instruments.

 

**Note 4 - Financial Instruments**

 

The cost and estimated fair values of LG&E’s non-trading financialinstruments as of December 31, 2004, and 2003 follow:

 
| **(in thousands)**                               | ** ** | **2004**   | ** **      | **2003**   | ** ** |
|--------------------------------------------------|------------|------------|-----------------|------------|------------|
| ** **                                       | **Cost**   | ** ** | **Fair  Value** | ** ** | **Cost**   | ** ** | **Fair  Value** | ** ** |
| ** **                                       | ** ** | ** ** | ** **      | ** ** |
|                                             |       |       |            |       |       |   |   |   |   |
| Preferred  stock subject to mandatory redemption |       | $          | 22,500          |       | $          | 22,781 |   | $ | 23,750 |   | $ | 23,893 |   |
| Long-term  debt (including current portion)      |       | $          | 574,304         |       | $          | 575,419 |   | $ | 574,304 |   | $ | 576,174 |   |
| Long-term  debt from affiliate                   |       | $          | 275,000         |       | $          | 280,684 |   | $ | 200,000 |   | $ | 206,333 |   |
| Interest-rate  swaps - liability                 |       | —     |            | $          | (18,542    | ) | — |   | $ | (15,966 | ) |

 

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All of the above valuations reflect prices quoted by exchanges exceptfor the swaps and intercompany loans. The fair values of the swaps andintercompany loans reflect price quotes from dealers or amounts calculatedusing accepted pricing models.

 

**Interest Rate Swaps.** LG&E uses interest rate swaps tohedge exposure to market fluctuations in certain of its debt instruments.  Pursuant to policy, use of these financialinstruments is intended to mitigate risk, earnings and cash flow volatility andis not speculative in nature.  Managementhas designated all of the interest rate swaps as hedge instruments.  Financial instruments designated as cash flowhedges have resulting gains and losses recorded within other comprehensiveincome and stockholders’ equity.  To theextent a financial instrument designated as a cash flow hedge or the underlyingitem being hedged is prematurely terminated or the hedge becomes ineffective,the resulting gains or losses are reclassified from other comprehensive incometo net income. See Note 15, Accumulated Other Comprehensive Income.  Financial instruments designated as fairvalue hedges and the underlying hedged items are periodically marked to marketwith the resulting net gains and losses recorded directly into net income.  Upon termination of any fair value hedge, theresulting gain or loss is recorded into net income.

 

LG&E was party to various interest rate swap agreements with aggregatenotional amounts of $228.3 million as of December 31, 2004 and 2003.  Under these swap agreements, LG&E paidfixed rates averaging 4.38%  and receivedvariable rates based on LIBOR or the Bond Market Association’s municipal swapindex averaging 1.74% and 1.11% at December 31, 2004 and 2003,respectively. The swap agreements in effect at December 31, 2004 have beendesignated as cash flow hedges and mature on dates ranging from 2005 to2033.  The cash flow designation wasassigned because the underlying variable rate debt has variable future cashflows. The hedges have been deemed to be fully effective resulting in a pretaxgain of $2.3 million for 2004, recorded in other comprehensive income.  Upon expiration of these hedges, the amountrecorded in other comprehensive income will be reclassified into earnings.  The amounts expected to be reclassified fromother comprehensive income to earnings in the next twelve months is immaterial(less than $0.1 million). A deposit in the amount of $10.9 million, used ascollateral for the $83.3 million interest rate swap, is classified asrestricted cash on LG&E’s balance sheet. The amount of the deposit requiredis tied to the market value of the swap.

 

# **Energy Trading & RiskManagement Activities. **LG&E conducts energy trading and risk managementactivities 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 areaccounted for on a mark-to-market basis in accordance with SFAS No. 133, SFASNo. 138**and SFAS No. 149.  Wholesale sales of excess asset capacity aretreated as normal sales under  these pronouncementsand are not marked to market.  To beeligible for the normal sales exclusion under SFAS No. 133, sales are limitedto the forecasted excess capacity of LG&E’s generation assets over what isneeded to serve native load.  To beeligible for the normal purchases exclusion under SFAS No. 133 purchases mustbe used to serve LG&E’s native load. Without the normal sales and purchases exclusion these transactionswould be considered derivatives and marked to market under SFAS No. 133.

# ** **

The rescission ofEITF No. 98-10 for fiscal periods ending after December 15, 2002, had noimpact on LG&E’s energy trading and risk management reporting as allforward and option contracts marked to market under EITF No. 98-10 are alsowithin the scope of SFAS No. 133.

 

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No changes to valuationtechniques for energy trading and risk management activities occurred during2004.  Changes in market pricing,interest rate and volatility assumptions were made during both years.  All contracts outstanding at December 31,2004, have a maturity of less than one year and are valued using pricesactively quoted for proposed or executed transactions or quoted by brokers.

 

LG&E maintains policies intended to minimize credit risk andrevalues credit exposures daily to monitor compliance with those policies.  At December 31, 2004, 100% of thetrading and risk management commitments were with counterparties rated BBB-/Baa3equivalent or better.

 

LG&E hedges the price volatility of its forecasted peak electricoff-system sales with the sales of market-traded electric forward contracts forperiods less than one year.  Theseelectric forward sales have been designated as cash flow hedges and are notspeculative in nature.  Gains or losseson these instruments, to the extent that the hedging relationship has beeneffective, are deferred in other comprehensive income.  Gains and losses resulting fromineffectiveness are shown in LG&E’s Consolidated Statements of Income inother income (expense) – net.  Uponexpiration of these instruments, the amount recorded in other comprehensiveincome is recorded in earnings.  Nomaterial pre-tax gains and losses resulted from these cash flow hedges in 2004,2003 and 2002.   See Note 15, AccumulatedOther Comprehensive Income.

 

**Accounts Receivable Securitization. **On February 6,2001, LG&E implemented an accounts receivable securitization program.LG&E terminated the accounts receivable securitization program in January 2004,and in May 2004, LG&E dissolved its inactive accounts receivablesecuritization-related subsidiary, LG&E R. The purpose of this program was to enable LG&E to accelerate thereceipt of cash from the collection of retail accounts receivable, therebyreducing dependence upon more costly sources of working capital.  The securitization program allowed for apercentage of eligible receivables to be sold. Eligible receivables were generally all receivables associated with retailsales that had standard terms and were not past due.  LG&E was able to terminate the program atany time without penalty.

 

As part of the program, LG&E sold retail accounts receivable toLG&E R.  Simultaneously, LG&E Rentered into two separate three-year accounts receivable securitizationfacilities with two financial institutions and their affiliates wherebyLG&E R could sell, on a revolving basis, an undivided interest in certainof its receivables and receive up to $75 million from unrelated third-partypurchasers.  The effective cost of thereceivables program was comparable to LG&E’s lowest cost source of capital,and was based on prime rated commercial paper. LG&E retained servicingrights of the sold receivables through two separate servicing agreements withthe third-party purchasers.  LG&Eobtained an opinion from independent legal counsel indicating thesetransactions qualified as a true sale of receivables.

 

To determine LG&E’s retained interest, the proceeds on the sale ofreceivables to the financial institutions were netted against the amount ofeligible receivables sold by LG&E to LG&E R.  Interest expense, program fees, and facilityfees paid to the financial institutions and an allowance for doubtful accountswere deducted to arrive at the future value of retained interest.  The future value was discounted using theprime rate plus 25 basis points, assuming a 45-day receivable life.  No material pre-tax gains and losses from thesale of the receivables occurred in 2004, 2003 and 2002.  LG&E’s net cash flows from LG&E Rwere $(58.1) million, $(6.2) million and $20.2 million for 2004, 2003 and 2002,respectively.

 

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The allowance for doubtful accounts associated with the eligiblesecuritized receivables at December 31 was $1.4 million and $1.9 million in 2003 and 2002, respectively.  This allowance was based on historicalexperience of LG&E. Each securitization facility contained a fully fundedreserve for uncollectible receivables.

 

**Note 5 - Concentrations of Credit and OtherRisk**

 

Credit risk represents the accounting loss that would be recognized atthe reporting date if counterparties failed to perform as contracted.  Concentrations of credit risk (whether on- oroff-balance sheet) relate to groups of customers or counterparties that havesimilar economic or industry characteristics that would cause their ability tomeet contractual obligations to be similarly affected by changes in economic orother conditions.

 

LG&E’s customer receivables and gas and electric revenues arisefrom deliveries of natural gas to approximately 318,000 customers andelectricity to approximately 390,000 customers in Louisville and adjacent areasin Kentucky.  For the year ended December 31,2004, 70% of total revenue was derived from electric operations and 30% fromgas operations.

 

In November 2001, LG&E and IBEW Local 2100 employees, thatrepresent approximately 72% of LG&E’s workforce, entered into a four-yearcollective bargaining agreement and completed wage and benefit re-openernegotiations in October 2003.

 

**Note 6 - Pension and Other Post RetirementBenefit Plans**

 

LG&E has both funded and unfunded non-contributory defined benefitpension plans and other post-retirement benefit plans that together cover substantiallyall of its employees. The healthcare plans are contributory with participants’contributions adjusted annually.

 

LG&E uses December 31 as the measurement date for its plans.

 

**Obligations and Funded Status. **The following tablesprovide a reconciliation of the changes in the plan’s benefit obligations andfair value of assets over the three-year period ending December 31, 2004,and a statement of the funded status as of December 31, 2004, for LG&E’ssponsored defined benefit plan:

 
| **(in thousands)**                              | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|-------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Pension  Plans:                                 |       |     |       |     |       |     |       |
| Change in  benefit obligation                   |       |     |       |     |       |     |       |
| Benefit  obligation at beginning of year        |       | $        | 378,691    |     | $          | 364,794  |       | $ | 356,293 |   |
| Service cost                                    |       | 2,777    |       | 1,757    |       | 1,484    |       |
| Interest  cost                                  |       | 22,742   |       | 23,190   |       | 24,512   |       |
| Plan amendments                                 |       | 3,301    |       | 3,978    |       | 576      |       |
| Change due  to transfers                        |       | (1,144   | )          | (2,759   | )          | —   |       |
| Benefits  paid                                  |       | (30,520  | )          | (33,539  | )          | (34,823  | )          |
| Actuarial  (gain) or loss and other             |       | 26,529   |       | 21,270   |       | 16,752   |       |
| Benefit  obligation at end of year              |       | $        | 402,376    |     | $          | 378,691  |       | $ | 364,794 |   |
|                                            |       |     |       |     |       |     |       |
| Change in  plan assets                          |       |     |       |     |       |     |       |
| Fair value  of plan assets at beginning of year |       | $        | 297,778    |     | $          | 196,314  |       | $ | 233,944 |   |
| Actual  return on plan assets                   |       | 39,240   |       | 47,152   |       | (15,648  | )          |
| Employer  contributions                         |       | 34,492   |       | 89,125   |       | 336      |       |
| Change due  to transfers                        |       | (1,071   | )          | 238      |       | 13,814   |       |
| Benefits  paid                                  |       | (30,520  | )          | (33,539  | )          | (34,824  | )          |
| Administrative  expenses                        |       | (1,764   | )          | (1,512   | )          | (1,308   | )          |
| Fair value  of plan assets at end of year       |       | $        | 338,155    |     | $          | 297,778  |       | $ | 196,314 |   |
|                                            |       |     |       |     |       |     |       |
| Reconciliation  of funded status                |       |     |       |     |       |     |       |
| Funded  status                                  |       | $        | (64,221    | )        | $          | (80,913  | )          | $ | (168,480 | ) |
| Unrecognized  actuarial (gain) or loss          |       | 70,304   |       | 56,219   |       | 60,313   |       |
| Unrecognized  transition (asset) or obligation  |       | (1,455   | )          | (2,183   | )          | (3,199   | )          |
| Unrecognized  prior service cost                |       | 31,505   |       | 32,275   |       | 32,265   |       |
| Net amount  recognized at end of year           |       | $        | 36,133     |     | $          | 5,398    |       | $ | (79,101 | ) |
|                                            |       |     |       |     |       |     |       |
| Other  Benefits:                                |       |     |       |     |       |     |       |
| Change in  benefit obligation                   |       |     |       |     |       |     |       |
| Benefit  obligation at beginning of year        |       | $        | 108,030    |     | $          | 93,233   |       | $ | 89,946 |   |
| Service cost                                    |       | 895      |       | 604      |       | 444      |       |
| Interest  cost                                  |       | 6,524    |       | 6,872    |       | 5,956    |       |
| Plan  amendments                                |       | 355      |       | 7,380    |       | —   |       |
| Benefits  paid                                  |       | (7,119   | )          | (9,313   | )          | (4,988   | )          |
| Actuarial  (gain) or loss                       |       | 4,265    |       | 9,254    |       | 1,875    |       |
| Benefit  obligation at end of year              |       | $        | 112,950    |     | $          | 108,030  |       | $ | 93,233 |   |
|                                            |       |     |       |     |       |     |       |
| Change in  plan assets                          |       |     |       |     |       |     |       |
| Fair value  of plan assets at beginning of year |       | $        | 674        |     | $          | 1,478    |       | $ | 2,802 |   |
| Actual  return on plan assets                   |       | (2,007   | )          | 2,076    |       | (533     | )          |
| Employer  contributions                         |       | 9,339    |       | 6,401    |       | 4,213    |       |
| Change due  to transfers                        |       | (105     | )          | —   |       | —   |       |
| Benefits  paid                                  |       | (7,126   | )          | (9,281   | )          | (5,004   | )          |
| Fair value  of plan assets at end of year       |       | $        | 775        |     | $          | 674      |       | $ | 1,478 |   |
|                                            |       |     |       |     |       |     |       |
| Reconciliation  of funded status                |       |     |       |     |       |     |       |
| Funded  status                                  |       | $        | (112,175   | )        | $          | (107,356 | )          | $ | (91,755 | ) |
| Unrecognized  actuarial (gain) or loss          |       | 29,414   |       | 23,724   |       | 16,971   |       |
| Unrecognized  transition (asset) or obligation  |       | 5,357    |       | 6,027    |       | 6,697    |       |
| Unrecognized  prior service cost                |       | 10,036   |       | 11,482   |       | 5,995    |       |
| Net amount  recognized at end of year           |       | $        | (67,368    | )        | $          | (66,123  | )          | $ | (62,092 | ) |

 

106

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**Amounts Recognized in Statement of FinancialPosition.**The following tables provide the amountsrecognized in the balance sheet and information for plans with benefitobligations in excess of plan assets as of December 31, 2004, 2003 and2002:

 
| **(in thousands)**                                                                                         | ** ** | **2004**   | ** ** | **2003**   | ** ** | **2002**   | ** ** |
|------------------------------------------------------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| ** **                                                                                                 | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Pension  Plans:                                                                                            |       |       |       |       |       |       |       |
| Amounts  recognized in the balance sheet consisted of:                                                     |       |       |       |       |       |       |       |
| Accrued  benefit liability                                                                                 |       | $          | (53,197    | )          | $          | (74,474    | )          | $ | (162,611 | ) |
| Intangible  asset                                                                                          |       | 31,505     |       | 32,275     |       | 32,799     |       |
| Accumulated  other comprehensive income                                                                    |       | 57,825     |       | 47,597     |       | 50,711     |       |
| Net amount  recognized at year-end                                                                         |       | $          | 36,133     |       | $          | 5,398      |       | $ | (79,101 | ) |
|                                                                                                       |       |       |       |       |       |       |       |
| Increase  (decrease) in minimum liability included in other comprehensive income                           |       | $          | 10,228     |       | $          | (3,114     | )          | $ | 25,999 |   |
|                                                                                                       |       |       |       |       |       |       |       |
| Additional  year-end information for plans with accumulated benefit obligations in excess  of plan assets: |       |       |       |       |       |       |       |
| Projected  benefit obligation                                                                              |       | $          | 402,376    |       | $          | 378,691    |       | $ | 364,794 |   |
| Accumulated  benefit obligation                                                                            |       | 391,353    |       | 372,252    |       | 358,956    |       |
| Fair value  of plan assets                                                                                 |       | 338,155    |       | 297,778    |       | 196,314    |       |
|                                                                                                       |       |       |       |       |       |       |       |
| Other  Benefits:                                                                                           |       |       |       |       |       |       |       |
| Amounts  recognized in the balance sheet consisted of:                                                     |       |       |       |       |       |       |       |
| Accrued  benefit liability                                                                                 |       | $          | (67,368    | )          | $          | (66,123    | )          | $ | (62,092 | ) |
|                                                                                                       |       |       |       |       |       |       |       |   |   |   |
| Additional  year-end information for plans with benefit obligations in excess of plan  assets:             |       |       |       |       |       |       |       |
| Benefit  obligation                                                                                        |       | $          | 112,950    |       | $          | 108,030    |       | $ | 93,233 |   |
| Fair value  of plan assets                                                                                 |       | 775        |       | 674        |       | 1,478      |       |

 

107

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**Components of Net Periodic Benefit Cost. **The following tableprovides the components of net periodic benefit cost for the plans for 2004,2003 and 2002:

 
| **(in thousands)**                                | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|---------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Pension  Plans:                                   |       |     |       |     |       |     |       |
| Components  of net periodic benefit cost          |       |     |       |     |       |     |       |
| Service cost                                      |       | $        | 2,777      |     | $          | 1,756    |       | $ | 1,484 |   |
| Interest  cost                                    |       | 22,742   |       | 23,190   |       | 24,512   |       |
| Expected  return on plan assets                   |       | (26,975  | )          | (22,785  | )          | (21,639  | )          |
| Amortization  of prior service cost               |       | 4,071    |       | 3,792    |       | 3,777    |       |
| Amortization  of transition (asset) or obligation |       | (728     | )          | (1,016   | )          | (1,016   | )          |
| Amortization  of actuarial (gain) or loss         |       | 1,870    |       | 2,219    |       | 21       |       |
| Net periodic  benefit cost                        |       | $        | 3,757      |     | $          | 7,156    |       | $ | 7,139 |   |
|                                              |       |     |       |     |       |     |       |
| Other  Benefits:                                  |       |     |       |     |       |     |       |
| Components  of net periodic benefit cost          |       |     |       |     |       |     |       |
| Service cost                                      |       | $        | 895        |     | $          | 604      |       | $ | 444 |   |
| Interest  cost                                    |       | 6,524    |       | 6,872    |       | 5,956    |       |
| Expected  return on plan assets                   |       | —   |       | (51      | )          | (204     | )          |
| Amortization  of prior service cost               |       | 1,800    |       | 1,768    |       | 920      |       |
| Amortization  of transition (asset) or obligation |       | 670      |       | 670      |       | 650      |       |
| Amortization  of actuarial (gain) or loss         |       | 695      |       | 505      |       | 116      |       |
| Net periodic  benefit cost                        |       | $        | 10,584     |     | $          | 10,368   |       | $ | 7,882 |   |

 

The assumptions used inthe measurement of LG&E’spension benefit obligation are shown in the following table:

 
| ** **                                            | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|-------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
|                                                  |       |     |       |     |       |     |       |
| Weighted-average  assumptions as of December 31: |       |     |       |     |       |     |       |
| Discount  rate                                        |       | 5.75     | %          | 6.25     | %          | 6.75     | %          |
| Rate of  compensation increase                        |       | 4.50     | %          | 3.00     | %          | 3.75     | %          |

 

The assumptions used in the measurement of LG&E’s net periodicbenefit cost are shown in the following table:

 
| ** **                                | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|-------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
|                                      |       |     |       |     |       |     |       |
| Discount  rate                            |       | 6.25     | %          | 6.75     | %          | 7.25     | %          |
| Expected  long-term return on plan assets |       | 8.50     | %          | 9.00     | %          | 9.50     | %          |
| Rate of  compensation increase            |       | 3.50     | %          | 3.75     | %          | 4.25     | %          |

 

To develop the expected long-term rate of return on assets assumption,LG&E considered the current level of expected returns on risk freeinvestments (primarily government bonds), the historical level of the riskpremium associated with the other asset classes in which the portfolio isinvested and the expectations for future returns of each asset class.  The expected return for each asset class wasthen weighted based on the target asset allocation to develop the expectedlong-term rate of return on assets assumption for the portfolio.

 

108

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## **AssumedHealthcare Cost Trend Rates. **Formeasurement purposes, a 12.0% annual increase in the per capita cost of coveredhealthcare benefits was assumed for 2004. The rate was assumed to decrease gradually to 5.0% by 2015 and remain atthat level thereafter.

##  

Assumed healthcare cost trend rates have a significant effect on theamounts reported for the healthcare plans. A 1% change in assumed healthcarecost trend rates would have the following effects:

 
| **(in thousands)**                                                | ** ** | **1 % Decrease** | ** ** | **1 % Increase** | ** ** |
|-------------------------------------------------------------------|------------|------------------|------------|------------------|------------|
|                                                              |       |             |       |             |       |
| Effect on  total of service and interest cost components for 2004 |       | $                | (283       | )                | $          | 322 |   |
| Effect on  year-end 2004 postretirement benefit obligations       |       | $                | (3,603     | )                | $          | 4,016 |   |

 

## **ExpectedFuture Benefit Payments. **Thefollowing list provides the amount of expected future benefit payments, whichreflect expected future service, as appropriate:

##  

| **(in thousands)** | ** ** | **Pension  Plans** | ** ** | **Other  Benefits** | ** ** |
|--------------------|------------|--------------------|------------|---------------------|------------|
| ** **         | ** ** | ** **         |
| 2005               |       | $                  | 29,783     |                | $          | 8,207 |   |
| 2006               |       | $                  | 28,878     |                | $          | 8,095 |   |
| 2007               |       | $                  | 28,118     |                | $          | 8,367 |   |
| 2008               |       | $                  | 27,353     |                | $          | 8,520 |   |
| 2009               |       | $                  | 26,466     |                | $          | 8,716 |   |
| 2010-2014          |       | $                  | 122,939    |                | $          | 46,850 |   |

 

## **PlanAssets. **The followingtable shows LG&E’s weighted-averageasset allocation by asset category at December 31:

##  

| ** **         | ** ** | **Target Range** | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|--------------------|------------|------------------|------------|----------|------------|----------|------------|----------|------------|
|               |       |             |       |     |       |     |       |     |       |
| Pension  Plans:    |       |             |       |     |       |     |       |     |       |
| Equity  securities |       | 55% - 85         | %          | 66       | %          | 66       | %          | 64       | %          |
| Debt  securities   |       | 20% - 40         | %          | 33       | %          | 33       | %          | 34       | %          |
| Other              |       | 0% - 10          | %          | 1        | %          | 1        | %          | 2        | %          |
| Totals             |       |             |       | 100      | %          | 100      | %          | 100      | %          |
|               |       |             |       |     |       |     |       |     |       |
| Other  Benefits:   |       |             |       |     |       |     |       |     |       |
| Equity securities  |       | —           | %          | —   | %          | —   | %          | —   | %          |
| Debt  securities   |       | 100              | %          | 100      | %          | 100      | %          | 100      | %          |
|               |       | 100              | %          | 100      | %          | 100      | %          | 100      | %          |

 

The investment policy of the pension plans was developed in conjunctionwith financial consultants, investment advisors and legal counsel.  The goal of the investment policy is topreserve the capital of the fund and maximize investment earnings with atargeted real rate of return (adjusted for inflation) objective of 6.0 percent.

 

**Thefund focuses on a long-term investment time horizon of at least three to five yearsor a complete market cycle.  The assetsof the pension plans are broadly diversified within different asset classes(equities, fixed income securities and cash equivalents).**

** **

To minimize therisk of large losses in a single asset class, no more than 5% of the portfoliowill be invested in the securities of any one issuer with the exclusion of theU.S. government and its agencies.  Theequity portion of the Fund is diversified among the market’s varioussubsections to diversify risk, maximize returns and avoid undue exposure to anysingle economic sector, industry group or individual security.  The equity subsectors include, but are notlimited to growth, value, small capitalization and international.

 

109

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In addition, theoverall fixed income portfolio holdings have a maximum average weightedmaturity of no more than fifteen (15) years, with the weighted average durationof the portfolio being no more than eight (8) years.  All securities must be rated “investmentgrade” or better and foreign bonds in the aggregate shall not exceed 10% of thetotal fund.  The cash investments shouldbe in securities that either are of short maturities (not to exceed 180 days)or readily marketable with modest risk.

 

Derivative securities are permitted only to improve the portfolio’srisk/return profile or to reduce transaction costs and must be used inconjunction with underlying physical assets in the portfolio. Derivativesecurities that involve speculation, leverage, interest rate anticipation, orany undue risk whatsoever are not deemed appropriate investments.

 

The investment objective for the post retirement benefit plan is toprovide current income consistent with stability of principal and liquiditywhile maintaining a stable net asset value of $1.00 per share.  The post retirement funds are invested in aprime cash money market fund that invests primarily in a portfolio ofshort-term, high-quality fixed income securities issued by banks, corporationsand the U.S. government.

 

**Contributions. **LG&E madediscretionary contributions to the pension plan of $34.5 million in January 2004and $89.2 million during 2003.  Nodiscretionary contributions are planned for 2005.

 

**FSP 106-2. **In May 2004, the FASB finalized FSP 106-2 withthe guidance on accounting for subsidies provided under the Medicare Act whichbecame law in December 2003.  FSP106-2 was effective for the first interim or annual period beginning after June 15,2004.  The following table reflects theimpact of the subsidy:

 
| **(in thousands)**                                                                          | ** ** | ** ** | ** ** |
|---------------------------------------------------------------------------------------------|------------|------------|------------|
| Reduction in  accumulated postretirement benefit obligation (“APBO”)              |       | $          | 3,166      |   |
|                                                                                        |       |       |       |
| Effect of  the subsidy on the measurement of the net periodic postretirement benefit  cost: |       |       |       |
|                                                                                        |       |       |       |
| Amortization  of the actuarial experience gain/(loss)                                       |       | $          | 198        |   |
| Reduction in  service cost due to the subsidy                                               |       | 0          |       |
| Resulting  reduction in interest cost on the APBO                                           |       | 198        |       |
| Total                                                                                       |       | $          | 396        |   |

 

**Thrift Savings Plans.**  LG&E has a thrift savings plan under section 401(k)of the Internal Revenue Code.  Under theplan, eligible employees may defer and contribute to the plan a portion ofcurrent compensation in order to provide future retirement benefits. LG&Emakes contributions to the plan by matching a portion of the employeecontributions.  The costs of thismatching were approximately $1.4 million for 2004, $1.8 million for 2003, and$1.7 million for 2002.

 

**Note 7 - Income Taxes**

 

Components of income tax expense are shown in the table below:

 
| **(in thousands)**                     | ** **            | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|----------------------------------------|-----------------------|----------|------------|----------|------------|----------|------------|
|                                   |                  |     |       |     |       |     |       |
| Related to  operating income:          |                  |     |       |     |       |     |       |
| Current                                | - federal             |     | $          | 35,190   |       | $        | 30,598     |   | $ | 26,231 |   |
|                                   | - state               |     | 13,358     |     | 11,007     |     | 8,083      |   |
| Deferred                               | - federal –  net |     | 11,363     |     | 16,922     |     | 20,464     |   |
|                                   | - state –  net   |     | (800       | )        | 1,746      |     | 4,410      |   |
| Amortization  of investment tax credit |                  | (4,153   | )          | (4,207   | )          | (4,153   | )          |
| Total                                  |                  | 54,958   |       | 56,066   |       | 55,035   |       |
|                                   |                  |     |       |     |       |     |       |
| Related to  other income - net:        |                  |     |       |     |       |     |       |
| Current                                | - federal             |     | (1,340     | )        | (4,830     | )        | (1,667     | ) |
|                                   | - state               |     | (350       | )        | (1,004     | )        | (430       | ) |
| Deferred                               | - federal –  net |     | 21         |     | (129       | )        | (206       | ) |
|                                   | - state –  net   |     | 5          |     | (30        | )        | (53        | ) |
| Total                                  |                  | (1,664   | )          | (5,993   | )          | (2,356   | )          |
|                                   |                  |     |       |     |       |     |       |
| Total income  tax expense              |                  | $        | 53,294     |     | $          | 50,073   |       | $ | 52,679 |   |
|                                        |                       |          |            |          |            |          |            |  |  |  |  |  |

 

110

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Components of net deferred tax liabilities included in the balancesheet are shown below:

 
| **(in thousands)**                          | ** ** | **2004** | ** ** | **2003** | ** ** |
|---------------------------------------------|------------|----------|------------|----------|------------|
|                                        |       |     |       |     |       |
| Deferred tax  liabilities:                  |       |     |       |     |       |
| Depreciation  and other plant-related items |       | $        | 397,806    |     | $          | 365,460 |   |
| Regulatory  assets and other                |       | 33,335   |       | 52,976   |       |
|                                        |       | 431,141  |       | 418,436  |       |
|                                        |       |     |       |     |       |
| Deferred tax  assets:                       |       |     |       |     |       |
| Investment  tax credit                      |       | 18,638   |       | 20,314   |       |
| Income taxes  due to customers              |       | 15,008   |       | 16,620   |       |
| Pensions and  related benefits              |       | 32,219   |       | 29,508   |       |
| Liabilities  and other                      |       | 18,043   |       | 14,290   |       |
|                                        |       | 83,908   |       | 80,732   |       |
|                                        |       |     |       |     |       |
| Net deferred  income tax liability          |       | $        | 347,233    |     | $          | 337,704 |   |
|                                        |       |     |       |     |       |
| Thereof  non-current                        |       | $        | 342,609    |     | $          | 332,796 |   |
| Thereof  current                            |       | 4,624    |       | 4,908    |       |
|                                        |       | $        | 347,233    |     | $          | 337,704 |   |

 

A reconciliation of differences between the statutory U.S. federalincome tax rate and LG&E’s effective income tax rate follows:

 
| ** **                                  | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|---------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
|                                        |       |     |       |     |       |     |       |
| Statutory  federal income tax rate          |       | 35.0     | %          | 35.0     | %          | 35.0     | %          |
| State income  taxes, net of federal benefit |       | 5.3      |       | 5.4      |       | 5.6      |       |
| Amortization  of investment tax credit      |       | (3.6     | )          | (3.0     | )          | (2.9     | )          |
| Other  differences – net               |       | (0.9     | )          | (1.9     | )          | (0.5     | )          |
| Effective  income tax rate                  |       | 35.8     | %          | 35.5     | %          | 37.2     | %          |

 

H. R. 4520, known as the“American Jobs Creation Act of 2004” allows electric utilities to take adeduction of up to 3% of their generation taxable income in 2005. On astand-alone basis, LG&E expects to generate a deduction in 2005 which willreduce LG&E’s effective tax rate by less than 1%. 

 

Kentucky House Bill 272, alsoknown as Kentucky’s Tax Modernization Plan, was signed into law in March  2005. This bill contains a number of changes in Kentucky’s tax system,including the reduction of the Corporate income tax rate from 8.25% to 7%effective January 1, 2005, and a further reduction to 6% effective January 1,2007.  The impact of these reduced ratesis expected to decrease LG&E’s income tax expense in future periods.  Furthermore, these reduced rates will resultin the reversal of accumulated temporary differences at lower rates thanoriginally provided.  LG&E ispresently evaluating the impact of this and other changes to the Kentucky taxsystem, however, no material adverse impacts on cash flows or results ofoperations are expected.

 

LG&E is subject to periodicchanges in state tax law, regulation or interpretation, as well as enforcementproceedings.  LG&E is currentlyundergoing a routine Kentucky sales tax audit for the period October 1997through 2001.  The possible assessment oramount at issue is not known at this time, but is not expected to have amaterial adverse effect on cashflows or results of operations.  

 

# **Note 8 - Other Income (Expense)- Net**

# ** **

Other income (expense) - net consisted of thefollowing at December 31:

 
| **(in thousands)**                      | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|-----------------------------------------|------------|----------|------------|----------|------------|----------|------------|
|                                    |       |     |       |     |       |     |       |
| Interest and  dividend income (expense) |       | $        | 304        |     | $          | 100      |       | $ | 554 |   |
| IMEA/IMPA fees                          |       | 719      |       | 806      |       | 859      |       |
| Gain on  disposition of property        |       | 166      |       | 2        |       | 421      |       |
| Terminated  projects                    |       | 0        |       | (2,997   | )          | 0        |       |
| Benefits  expense                       |       | 0        |       | 0        |       | (1,655   | )          |
| Other                                   |       | (4,521   | )          | (5,104   | )          | (1,715   | )          |
|                                    |       | $        | (3,332     | )        | $          | (7,193   | )          | $ | (1,536 | ) |

 

111

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**Note 9 - Long-Term Debt**

 

Refer to the Consolidated Statements of Capitalization for detailedinformation for LG&E’s long-term debt.

 

As of December 31, 2004, long-term debt and the current portion oflong-term debt consists primarily of pollution control bonds and long-termloans from affiliated companies as summarized below.  Interest rates and maturities in the tablebelow reflect the impact of interest rate swaps.

 

| **(in thousands)**                      | ** ** | **Stated  Interest Rates** | ** ** | **Weighted  Average  Interest  Rate** | ** ** | **Maturities** | ** ** | **Principal  Amounts** | ** ** |
|-----------------------------------------|------------|----------------------------|------------|---------------------------------------|------------|----------------|------------|------------------------|------------|
| ** **                              | ** ** | ** **                 | ** ** | ** **                            |
| ** **                              | ** ** | ** **                 | ** ** | ** **                            |
| ** **                              | ** ** | ** **                 | ** ** | ** **                            |
|                                    |       |                       |       |                                  |       |           |       |                   |       |
| Outstanding  at December 31, 2004: |       |                       |       |                                  |       |           |       |                   |       |
| Noncurrent  portion                     |       | Variable - 5.90%           |       | 4.39%                                 |       | 2008-2033      |       | $                      | 574,354    |   |
| Current  portion                        |       | Variable                   |       | 1.96%                                 |       | 2005-2027      |       | 297,450                |       |
|                                    |       |                       |       |                                  |       |           |       |                   |       |
| Outstanding  at December 31, 2003: |       |                       |       |                                  |       |           |       |                   |       |
| Noncurrent portion                      |       | Variable - 5.90%           |       | 4.23%                                 |       | 2027-2033      |       | $                      | 550,604    |   |
| Current portion                         |       | Variable                   |       | 1.46%                                 |       | 2017-2027      |       | 247,450                |       |

 

Under the provisions for LG&E’s variable-rate pollution controlbonds, Series S, T, U, BB, CC, DD and EE, the bonds are subject to tender forpurchase at the option of the holder and to mandatory tender for purchase uponthe occurrence of certain events, causing the bonds to be classified as currentportion of long-term debt in the Consolidated Balance Sheets.  The average annualized interest rate for thesebonds during 2004 was 1.29%.

 

Pollution control series bonds are first mortgage bonds that have beenissued by LG&E in connection with tax-exempt pollution control revenuebonds issued by various governmental entities, principally counties inKentucky.  A loan agreement obligatesLG&E to make debt service payments to the county that equate to the debtservice due from the county on the related pollution control revenuebonds.  The county’s debt is also securedby an equal amount of LG&E’s first mortgage bonds (the pollution controlseries bonds) that are pledged to the trustee for the pollution control revenuebonds, and that match the terms and conditions of the county’s debt, butrequire no payment of principal and interest unless LG&E defaults on theloan agreement.

 

Substantially all of LG&E’s utility assets are pledged as securityfor its first mortgage bonds.  LG&E’sfirst mortgage bond indenture, as supplemented, provides that portions ofretained earnings will not be available for the payment of dividends on commonstock, under certain specified conditions. No portion of retained earnings wasrestricted by this provision as of December 31, 2004 or 2003.

 

Interest rate swaps are used to hedge LG&E’s underlyingvariable-rate debt obligations.  Theseswaps hedge specific debt issuances and, consistent with management’sdesignation, are accorded hedge accounting treatment.  The swaps exchange floating-rate interestpayments for fixed rate interest payments to reduce the impact of interest ratechanges on LG&E’s pollution control bonds.  As of December 31, 2004 and 2003, LG&E had swaps with acombined notional value of $228.3 million. See Note 4.

 

In January 2004, LG&E entered into one long-term loan fromFidelia totaling $25 million with an interest rate of 4.33% that matures in January 2012.  The loan is collateralized by a pledge ofsubstantially all assets of LG&E that is subordinated to the first mortgagebond lien. The proceeds were used to repay amounts due under the accountsreceivable securitization program.

 

In November 2003, LG&E issued $128 million variable-ratepollution control bonds due October 1, 2033, and exercised its call optionon the $102 million, 5.625% pollution control bonds due August 15, 2019and on the $26 million, 5.45% pollution control bonds due October 15,2020.

 

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LG&E’s first mortgage bond, 6% Series of $42.6 million, matured in August 2003and was retired.

 

During 2003, LG&E entered into two long-term loans from Fideliatotaling $200 million (see Note 14).  Ofthis total, $100 million is unsecured with an interest rate of 4.55% andmatures in April 2013.  Theremaining $100 million is collateralized by a pledge of substantially allassets of LG&E that is subordinated to the first mortgage bond lien, has aninterest rate of 5.31% and matures in August 2013.  The second lien applies to substantially allassets of LG&E.

 

LG&E has existing $5.875 series mandatorily redeemable preferredstock outstanding having a current redemption price of $100 per share. Thepreferred stock has a sinking fund requirement sufficient to retire a minimumof 12,500 shares on July 15 of each year commencing with July 15,2003, and the remaining 187,500 shares on July 15, 2008 at $100 pershare.  LG&E redeemed 12,500 sharesin accordance with these provisions on July 15, 2004 and 2003, leaving225,000 shares currently outstanding. Beginning with the three months ended September 30, 2003, LG&Ereclassified its $5.875 series preferred stock as long-term debt with theminimum shares mandatorily redeemable within one year classified as current.

 

# **See Note 11, Commitments and Contingencies for alllong-term debt maturities.**

# ** **

# **Note 10 - Notes Payableand Other Short-Term Obligations**

# ** **

LG&E participates in an intercompany money pool agreement whereinLG&E Energy and/or KU make funds available to LG&E at market-basedrates (based on an index of highly rated commercial paper issues as of theprior month end) up to $400 million.  Thebalance of the money pool loan from LG&E Energy (shown as “Notes payable toaffiliated company”) was $58.2 million at an average rate of 2.22% and $80.3million at an average rate of 1.00%, at December 31, 2004 and 2003,respectively.  The amount available toLG&E under the money pool agreement at December 31, 2004 was $341.8million.  LG&E Energy maintains arevolving credit facility totaling $150 million with an affiliate to ensurefunding availability for the money pool. The outstanding balance under LG&E Energy’s facility as of December 31,2004 was $65.4 million, and availability of $84.6 million remained.  LG&E Energy increased the size of itsrevolving credit facility to $200 million effective January 24, 2005.

 

During June 2004, LG&E renewed five revolving lines of creditwith banks totaling $185 million.  Thesecredit facilities expire in June 2005, and there was no outstandingbalance under any of these facilities at December 31, 2004.

 

The covenants under these revolving lines of credit include:

 

1.                                       Thedebt/total capitalization ratio must be less than 70%,

2.                                       E.ONAG must own at least 66.667% of voting stock of LG&E directly orindirectly,

3.                                       Thecorporate credit rating of the company must be at or above BBB- and Baa3, and

4.                                       Alimitation on disposing of assets aggregating more than 15% of total assets asof December 31, 2003.

 

In January 2004, LG&E entered into a one year loan totaling$100 million with Fidelia.  The interestrate on the loan is 1.53%, and the proceeds were used to repay notes payable toLG&E Energy under the money pool arrangement.  The loan is collateralized by a pledge ofsubstantially all assets of LG&E that is subordinated to the first mortgagebond lien.  A prepayment of $50 millionwas made in 2004 and the remaining $50 million was paid at maturity in January 2005.

 

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**Note 11 - Commitments and Contingencies**

 

The following is providedto summarize LG&E’s contractual cash obligations for periods after December 31,2004.  LG&E anticipates cash fromoperations and external financing will be sufficient to fund futureobligations.  Future interest obligationscannot be quantified because most of LG&E's debt is variable rate (seeLG&E's Consolidated Statements of Capitalization).

 
| **(****in thousands****)**                    | ** ** | **Payments Due by Period** | ** ** |
|-----------------------------------------------|------------|----------------------------|------------|
| **Contractual Cash Obligations**              | ** ** | **2005**                   | ** ** | **2006** | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** | **Thereafter** | ** ** | **Total** | ** ** |
| ** **                                    |       |                       |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Short-term  debt (a)                          |       | $                          | 58,220     |   | $ | — |   | $ | — |   | $ | — |   | $ | — |   | $ | — |   | $ | 58,220 |   |
| Long-term  debt                               |       | 297,450                    |       | 1,250 |   | 1,250 |   | 18,750 |   | — |   | 553,104 | (b) | 871,804 |   |
| Operating  lease (c)                          |       | 3,469                      |       | 3,538 |   | 3,609 |   | 3,681 |   | 3,754 |   | 22,375 |   | 40,426 |   |
| Unconditional  power purchase obligations (d) |       | 11,230                     |       | 10,098 |   | 9,726 |   | 9,932 |   | 10,145 |   | 181,089 |   | 232,220 |   |
| Coal and gas  purchase obligations (e)        |       | 202,450                    |       | 95,478 |   | 52,656 |   | 49,396 |   | 6,037 |   | 6,037 |   | 412,054 |   |
| Retirement  obligations (f)                   |       | 9,250                      |       | 10,106 |   | 13,305 |   | 10,992 |   | 15,839 |   | — |   | 59,492 |   |
| Other  long-term obligations (g)              |       | 14,767                     |       | — |   | — |   | — |   | — |   | — |   | 14,767 |   |
| Total contractual  cash obligations           |       | $                          | 596,836    |   | $ | 120,470 |   | $ | 80,546 |   | $ | 92,751 |   | $ | 35,775 |   | $ |  762,605 |   | $ | 1,688,983 |   |

 

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(a)          Represents borrowings from affiliated companydue within one year.

(b)         Includes long-term debt of $246.2 millionclassified as current liabilities because these bonds are subject to tender forpurchase at the option of the holder and to mandatory tender for purchase uponthe occurrence of certain events. Maturity dates for these bonds range from 2013 to 2027.  LG&E does not expect to pay these amountsin 2005.

(c)          Operating lease represents the lease ofLG&E’s administrative office building.

(d)         Represents future minimum payments under OVECpurchased power agreements through 2024.

(e)          Represents contracts to purchase coal andnatural gas.

(f)            Represents currently projected contributionsto pension plans and other post-employment benefit obligations as calculated bythe actuary.

(g)         Represents construction commitments.

 

**Operating Leases.**  LG&E leases office space, officeequipment and vehicles.  LG&Eaccounts for its leases as operating leases. Total lease expense for 2004, 2003 and 2002, less amounts contributed byaffiliated companies occupying a portion of the office space leased byLG&E, was $2.8 million, $2.2 million, and $2.2 million, respectively.  The future minimum annual lease paymentsunder LG&E’s office space lease agreement for years subsequent to December 31,2004, are in the Contractual Cash Obligations table above.

 

**Sale and Leaseback Transaction.** LG&E is a participant in a sale andleaseback transaction involving its 38% interest in two jointly-owned CTs at KU’sE.W. Brown generating station (Units 6 and 7). Commencing in December 1999, LG&E and KU entered into atax-efficient, 18-year lease of the CTs. LG&E and KU have provided funds tofully defease the lease, and have executed an irrevocable notice to exercise anearly purchase option contained in the lease after 15.5 years. The financialstatement treatment of this transaction is no different than if LG&E hadretained its ownership.  The leasingtransaction was entered into following receipt of required state and federalregulatory approvals.

 

In case of default under the lease, LG&E is obligated to pay to thelessor its share of certain fees or amounts. Primary events of default includeloss or destruction of the CTs, failure to insure or maintain the CTs andunwinding of the transaction due to governmental actions.  No events of default currently exist withrespect to the lease.  Upon anytermination of the lease, whether by default or expiration of its term, titleto the CTs reverts jointly to LG&E and KU.

 

At December 31, 2004, the maximum aggregate amount of default feesor amounts, which decrease over the term of the lease, was $9.5 million, ofwhich LG&E would be responsible for $3.6 million (38%).  LG&E has made arrangements with LG&EEnergy, via guarantee and regulatory commitment, for LG&E Energy to pay itsfull portion of any default fees or amounts.

 

**Letters of Credit.**  LG&E has provided letters of credittotaling $3.0 million to support certain obligations

 

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related to landfill reclamation.

 

**Purchased Power.**LG&Ehas a contract for purchased power with OVEC for various Mw capacities.  LG&E has an investment of 5.63% ownershipin OVEC’s common stock, which is accounted for on the cost method ofaccounting.  Through March 2006,LG&E’s entitlement is 7% of OVEC’s generation capacity or approximately 155Mw, and 5.63% thereafter.

 

In March 2005, LG&E purchased from AEP an additional 0.73%interest in OVEC for a purchase price of approximately $0.1 million, whichresulted in the increase in LG&E ownership in OVEC from 4.9% to 5.63%.

 

**Construction Program.**  LG&E had approximately $14.8 million ofcommitments in connection with its construction program at December 31,2004.  Construction expenditures for theyears 2005 and 2006 are estimated to total approximately $268 million, althoughall of this amount is not currently committed, including future expendituresrelated to the construction of Trimble County Unit 2.

 

**Environmental Matters. **LG&E is subjectto SO2 and NOx emission limits on its electric generating unitspursuant to the Clean Air Act.** **LG&E was exempt from Phase ISO2 requirements due to its low emission rates. LG&E opted intothe Phase I NOx program to take advantage of the less stringent requirementsand installed burner modifications as needed to meet these limitations.  LG&E’s strategy for Phase II SO2 reductions,which commenced January 1, 2000, is to increase FGD removal efficiency todelay additional capital expenditures and may also include fuel switching orupgrading FGDs.  LG&E met the NOxemission requirements of the Act through installation of low-NOx burner systems.  LG&E’s compliance plans are subject tomany factors including developments in the emission allowance and fuel markets,future regulatory and legislative initiatives, and advances in clean aircontrol technology.  LG&E willcontinue to monitor these developments to ensure that its environmentalobligations are met in the most efficient and cost-effective manner.

 

In September 1998, the EPA announced its final “NOx SIP Call” rulerequiring states to impose significant additional reductions in NOx emissionsby May 2003, in order to mitigate alleged ozone transport impacts on theNortheast region.  The Commonwealth ofKentucky SIP, which was approved by the EPA on June 24, 2003, requiresreductions in NOx emissions from coal-fired generating units to the 0.15lb./MMBtu level on a system-wide basis. In related proceedings in response to petitions filed by variousNortheast states, in December 1999, the EPA issued a final rule pursuantto Section 126 of the Clean Air Act directing similar NOx reductions froma number of specifically targeted generating units including all LG&Eunits.  As a result of appeals to bothrules, the compliance date was extended to May 31, 2004.  All LG&E generating units are incompliance with these NOx emissions reduction rules.

 

LG&E has added significant NOx controls to its generating unitsthrough the installation of SCR systems, advanced low-NOx burners and neuralnetworks.  The NOx controls projectcommenced in late 2000 with the controls being placed into operation prior tothe 2004 Summer Ozone Season. As of December 31, 2004, LG&E incurredtotal capital costs of approximately $186 million to reduce its NOx emissionsbelow the 0.15 lb./MMBtu level on a company-wide basis.  In addition, LG&E will incur additionaloperating and maintenance costs in operating new NOx controls.  LG&E believes its costs in this regard tobe comparable to those of similarly situated utilities with like generationassets. LG&E anticipated that such capital and operating costs are the typeof costs that are eligible for recovery from customers under its environmentalsurcharge mechanism and believed that a significant portion of such costs couldbe recovered.  In April 2001, theKentucky Commission granted recovery of these costs for LG&E.

 

LG&E is also monitoring several other air quality issues which maypotentially impact coal-fired power plants, including EPA’s revised air qualitystandards for ozone and particulate matter, measures to implement EPA’sregional haze rule, EPA’s Clean Air Mercury Rule which regulates mercuryemissions from steam electric

 

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generating units and reductions in emissions of SO2 and NOxrequired under the Clean Air Interstate Rule. In addition, LG&E has worked with local regulatory authorities toreview the effectiveness of remedial measures aimed at controlling particulatematter emissions from its Mill Creek Station. LG&E previously settled a number of property damage claims fromadjacent residents and completed significant remedial measures as part of itsongoing capital construction program. LG&E has converted the Mill CreekStation to a wet stack operation in an effort to resolve all outstanding issuesrelated to particulate matter emissions.

 

LG&E owns or formerly owned three properties which are the locationof past MGP operations.  Variouscontaminants are typically found at such former MGP sites and environmentalremediation measures are frequently required. With respect to the sites, LG&E has completed cleanups, obtainedregulatory approval of site management plans, or reached agreements for otherparties to assume responsibility for cleanup. Based on currently available information, management estimates that itcould incur additional costs of $0.4 million for additional cleanup.  Accordingly, an accrual for this amount hasbeen recorded in the accompanying financial statements at December 31,2004 and 2003.

 

**Note 12 - Jointly Owned Electric UtilityPlant**

 

LG&E owns a 75% undivided interest in Trimble County Unit 1 whichthe Kentucky Commission has allowed to be reflected in customer rates.

 

Of the remaining 25% of the Unit, IMEA owns a 12.12% undividedinterest, and IMPA owns a 12.88% undivided interest.  Each company is responsible for itsproportionate ownership share of fuel cost, operation and maintenance expenses,and incremental assets.

 

The following data represent shares of the jointly owned property:

 
| ** **                                      | ** ** | **Trimble County** | ** ** |
|-------------------------------------------------|------------|--------------------|------------|
| ** **                                      | ** ** | **LG&E**       | ** ** | **IMPA** | ** ** | **IMEA** | ** ** | **Total** | ** ** |
| Ownership  interest                             |       | 75                 | %          | 12.88 | % | 12.12 | % | 100 | % |
| Mw capacity                                     |       | 383                |       | 66 |   | 62 |   | 511 |   |
|                                            |       |               |       |   |   |   |   |   |   |
| LG&E’s  75% ownership: (in  thousands) |       |               |       |   |   |   |   |   |   |
| Cost                                            |       | $                  | 597,433    |   |   |   |   |   |   |   |
| Accumulated  depreciation                       |       | 207,022            |       |   |   |   |   |   |   |
| Net book  value                                 |       | $                  | 390,411    |   |   |   |   |   |   |   |
|                                            |       |               |       |   |   |   |   |   |   |
| Construction  work in progress (included above) |       | $                  | 4,378      |   |   |   |   |   |   |   |

 

116

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LG&E and KU jointly own the following combustion turbines:

 
| **(in thousands)**    | ** ** | ** **     | ** ** | **LG&E** | ** ** | **KU** | ** ** | **Total** | ** ** |
|-----------------------|------------|----------------|------------|--------------|------------|--------|------------|-----------|------------|
|                  |       |           |       |         |       |   |       |      |       |
| Paddy’s Run 13   |       | Ownership %    |       | 53           | %          | 47     | %          | 100       | %          |
|                  |       | Mw capacity    |       | 84           |       | 74     |       | 158       |       |
|                  |       | Cost           |       | $            | 34,033     |   | $          | 30,038    |       | $ | 64,071 |   |
|                  |       | Depreciation   |       | 4,042        |       | 3,555  |       | 7,597     |       |
|                  |       | Net book value |       | $            | 29,991     |   | $          | 26,483    |       | $ | 56,474 |   |
|                  |       |           |       |         |       |   |       |      |       |
| E.W. Brown 5          |       | Ownership %    |       | 53           | %          | 47     | %          | 100       | %          |
|                  |       | Mw capacity    |       | 62           |       | 55     |       | 117       |       |
|                  |       | Cost           |       | $            | 23,978     |   | $          | 20,221    |       | $ | 44,199 |   |
|                  |       | Depreciation   |       | 2,712        |       | 2,269  |       | 4,981     |       |
|                  |       | Net book value |       | $            | 21,266     |   | $          | 17,952    |       | $ | 39,218 |   |
|                  |       |           |       |         |       |   |       |      |       |
| E.W. Brown 6          |       | Ownership %    |       | 38           | %          | 62     | %          | 100       | %          |
|                  |       | Mw capacity    |       | 59           |       | 95     |       | 154       |       |
|                  |       | Cost           |       | $            | 25,353     |   | $          | 38,935    |       | $ | 64,288 |   |
|                  |       | Depreciation   |       | 3,426        |       | 6,644  |       | 10,070    |       |
|                  |       | Net book value |       | $            | 21,927     |   | $          | 32,291    |       | $ | 54,218 |   |
|                  |       |           |       |         |       |   |       |      |       |
| E.W. Brown 7          |       | Ownership %    |       | 38           | %          | 62     | %          | 100       | %          |
|                  |       | Mw capacity    |       | 59           |       | 95     |       | 154       |       |
|                  |       | Cost           |       | $            | 22,718     |   | $          | 36,137    |       | $ | 58,855 |   |
|                  |       | Depreciation   |       | 5,679        |       | 7,012  |       | 12,691    |       |
|                  |       | Net book value |       | $            | 17,039     |   | $          | 29,125    |       | $ | 46,164 |   |
|                  |       |           |       |         |       |   |       |      |       |
| Trimble 5             |       | Ownership %    |       | 29           | %          | 71     | %          | 100       | %          |
|                  |       | Mw capacity    |       | 46           |       | 114    |       | 160       |       |
|                  |       | Cost           |       | $            | 16,241     |   | $          | 39,665    |       | $ | 55,906 |   |
|                  |       | Depreciation   |       | 1,363        |       | 3,327  |       | 4,690     |       |
|                  |       | Net book value |       | $            | 14,878     |   | $          | 36,338    |       | $ | 51,216 |   |
|                  |       |           |       |         |       |   |       |      |       |
| Trimble 6             |       | Ownership %    |       | 29           | %          | 71     | %          | 100       | %          |
|                  |       | Mw capacity    |       | 46           |       | 114    |       | 160       |       |
|                  |       | Cost           |       | $            | 16,205     |   | $          | 39,703    |       | $ | 55,908 |   |
|                  |       | Depreciation   |       | 1,361        |       | 3,332  |       | 4,693     |       |
|                  |       | Net book value |       | $            | 14,844     |   | $          | 36,371    |       | $ | 51,215 |   |
|                  |       |           |       |         |       |   |       |      |       |
| Trimble 7             |       | Ownership %    |       | 37           | %          | 63     | %          | 100       | %          |
|                  |       | Mw capacity    |       | 59           |       | 101    |       | 160       |       |
|                  |       | Cost           |       | $            | 19,274     |   | $          | 32,913    |       | $ | 52,187 |   |
|                  |       | Depreciation   |       | 355          |       | 606    |       | 961       |       |
|                  |       | Net book value |       | $            | 18,919     |   | $          | 32,307    |       | $ | 51,226 |   |
|                  |       |           |       |         |       |   |       |      |       |
| Trimble 8             |       | Ownership %    |       | 37           | %          | 63     | %          | 100       | %          |
|                  |       | Mw capacity    |       | 59           |       | 101    |       | 160       |       |
|                  |       | Cost           |       | $            | 19,161     |   | $          | 32,762    |       | $ | 51,923 |   |
|                  |       | Depreciation   |       | 353          |       | 604    |       | 957       |       |
|                  |       | Net book value |       | $            | 18,808     |   | $          | 32,158    |       | $ | 50,966 |   |
|                  |       |           |       |         |       |   |       |      |       |
| Trimble 9             |       | Ownership %    |       | 37           | %          | 63     | %          | 100       | %          |
|                  |       | Mw capacity    |       | 59           |       | 101    |       | 160       |       |
|                  |       | Cost           |       | $            | 19,195     |   | $          | 32,835    |       | $ | 52,030 |   |
|                  |       | Depreciation   |       | 299          |       | 512    |       | 811       |       |
|                  |       | Net book value |       | $            | 18,896     |   | $          | 32,323    |       | $ | 51,219 |   |
|                  |       |           |       |         |       |   |       |      |       |
| Trimble 10            |       | Ownership %    |       | 37           | %          | 63     | %          | 100       | %          |
|                  |       | Mw capacity    |       | 59           |       | 101    |       | 160       |       |
|                  |       | Cost           |       | $            | 19,141     |   | $          | 32,802    |       | $ | 51,943 |   |
|                  |       | Depreciation   |       | 298          |       | 511    |       | 809       |       |
|                  |       | Net book value |       | $            | 18,843     |   | $          | 32,291    |       | $ | 51,134 |   |
|                  |       |           |       |         |       |   |       |      |       |
| Trimble CT Pipeline   |       | Ownership %    |       | 29           | %          | 71     | %          | 100       | %          |
|                  |       | Cost           |       | $            | 1,978      |   | $          | 4,813     |       | $ | 6,791 |   |
|                  |       | Depreciation   |       | 165          |       | 403    |       | 568       |       |
|                  |       | Net book value |       | $            | 1,813      |   | $          | 4,410     |       | $ | 6,223 |   |
|                  |       |           |       |         |       |   |       |      |       |
| Trimble CT Substation |       | Ownership %    |       | 29           | %          | 71     | %          | 100       | %          |
| 5 & 6             |       | Cost           |       | $            | 1,474      |   | $          | 3,598     |       | $ | 5,072 |   |
|                  |       | Depreciation   |       | 76           |       | 196    |       | 272       |       |
|                  |       | Net book value |       | $            | 1,398      |   | $          | 3,402     |       | $ | 4,800 |   |
|                  |       |           |       |         |       |   |       |      |       |
| Trimble CT Substation |       | Ownership %    |       | 37           | %          | 63     | %          | 100       | %          |
| 7 - 10                |       | Cost           |       | $            | 2,856      |   | $          | 4,711     |       | $ | 7,567 |   |
|                  |       | Depreciation   |       | 30           |       | 53     |       | 83        |       |
|                  |       | Net book value |       | $            | 2,826      |   | $          | 4,658     |       | $ | 7,484 |   |

 

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In addition to these generating units, LG&E and KU share jointownership in the Brown Inlet Air Cooling system. LG&E owns 10% of thesystem, attributable to Brown Unit 5, which provides an additional 10 Mw ofcapacity.

 

**Note 13 - Segments of Business and RelatedInformation**

 

LG&E is a regulated public utility engaged in the generation,transmission, distribution, and sale of electricity and the storage,distribution, and sale of natural gas. LG&E is regulated by the Kentucky Commission and files electric andgas financial information separately with the Kentucky Commission.  The Kentucky Commission establishes ratesspecifically for the electric and gas businesses.  Therefore, management reports and analyzesfinancial performance based on the electric and gas segments of thebusiness.  Financial data for businesssegments follow:

 
| **(in thousands)**             | ** ** | **Electric** | ** ** | **Gas** | ** ** | **Total** | ** ** |
|--------------------------------|------------|--------------|------------|---------|------------|-----------|------------|
| 2004                           |       |         |       |    |       |      |       |
| Operating  revenues            |       | $            | 815,697    |    | $          | 357,071   |       | $ | 1,172,768 |   |
| Depreciation  and amortization |       | 99,971       |       | 16,606  |       | 116,577   |       |
| Income taxes                   |       | 48,296       |       | 4,998   |       | 53,294    |       |
| Interest  income               |       | 223          |       | 31      |       | 254       |       |
| Interest  expense              |       | 27,320       |       | 5,467   |       | 32,787    |       |
| Net income                     |       | 87,249       |       | 8,369   |       | 95,618    |       |
| Total assets                   |       | 2,416,500    |       | 550,052 |       | 2,966,552 |       |
| Construction  expenditures     |       | 113,382      |       | 34,924  |       | 148,306   |       |
|                           |       |         |       |    |       |      |       |
| 2003                           |       |         |       |    |       |      |       |
| Operating  revenues            |       | $            | 768,188    |    | $          | 325,333   |       | $ | 1,093,521 |   |
| Depreciation  and amortization |       | 96,486       |       | 16,801  |       | 113,287   |       |
| Income taxes                   |       | 44,692       |       | 5,381   |       | 50,073    |       |
| Interest  income               |       | 27           |       | 4       |       | 31        |       |
| Interest  expense              |       | 25,694       |       | 4,953   |       | 30,647    |       |
| Net income                     |       | 80,612       |       | 10,227  |       | 90,839    |       |
| Total assets                   |       | 2,338,938    |       | 543,144 |       | 2,882,082 |       |
| Construction  expenditures     |       | 177,961      |       | 34,996  |       | 212,957   |       |
|                           |       |         |       |    |       |      |       |
| 2002                           |       |         |       |    |       |      |       |
| Operating  revenues            |       | $            | 736,042    |    | $          | 267,693   |       | $ | 1,003,735 |   |
| Depreciation  and amortization |       | 90,248       |       | 15,658  |       | 105,906   |       |
| Income taxes                   |       | 47,419       |       | 5,260   |       | 52,679    |       |
| Interest  income               |       | 381          |       | 76      |       | 457       |       |
| Interest  expense              |       | 24,837       |       | 4,968   |       | 29,805    |       |
| Net income                     |       | 79,246       |       | 9,683   |       | 88,929    |       |
| Total assets                   |       | 2,276,712    |       | 492,218 |       | 2,768,930 |       |
| Construction  expenditures     |       | 195,662      |       | 24,754  |       | 220,416   |       |

 

**Note 14 -****Related Party Transactions**

 

LG&E, subsidiaries of LG&E Energy and other subsidiaries ofE.ON engage in related party transactions. Transactions between LG&E and its subsidiary LG&E R areeliminated upon consolidation with LG&E. Transactions between LG&E and LG&E Energy subsidiaries areeliminated upon consolidation of LG&E Energy. Transactions between LG&Eand E.ON subsidiaries are eliminated upon consolidation of E.ON. Thesetransactions are generally performed at cost and are in accordance with the SECregulations under the PUHCA and the applicable Kentucky Commissionregulations.  Amounts payable to andreceivable from related parties are netted and presented as accounts payable toaffiliated companies on the balance sheet of LG&E, as allowed due to theright of offset. Obligations related to intercompany debt arrangements withLG&E Energy and

 

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Fidelia are presented as separate line items on the balance sheet, asappropriate. The significant related party transactions are disclosed below.

 

Electric Purchases

 

LG&E and KU purchase energy from each other in order to effectivelymanage the load of their retail and off-system customers.  In addition, LG&E and LEM, a subsidiaryof LG&E Energy, purchase energy from each other. These sales and purchasesare included in the Consolidated Statements of Income as Electric OperatingRevenues and Purchased Power Operating Expense. LG&E intercompany electric revenues and purchased power expense forthe years ended December 31, 2004, 2003 and 2002 were as follows:

 
| **(in thousands)**                    | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|---------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Electric  operating revenues from KU  |       | $        | 58,687     |     | $          | 53,747   |       | $ | 41,480 |   |
| Electric  operating revenues from LEM |       | 374      |       | 9,372    |       | 9,939    |       |
| Purchased  power from KU              |       | 61,743   |       | 46,690   |       | 33,249   |       |
| Purchased  power from LEM             |       | —   |       | —   |       | 913      |       |
|                                       |            |          |            |          |            |          |            |  |  |  |

 

Interest Charges

 

LG&E participates in an intercompany money pool agreement whereinLG&E Energy and/or KU make funds available to LG&E at market-basedrates (based on an index of highly rated commercial paper issues as of theprior month end) up to $400 million.  Thebalance of the money pool loan from LG&E Energy (shown as “Notes payable toaffiliated company”) was $58.2 million at an average rate of 2.22% and $80.3million at an average rate of 1.00%, at December 31, 2004 and 2003,respectively.  The amount available toLG&E under the money pool agreement at December 31, 2004 was $341.8million.  LG&E Energy maintains arevolving credit facility totaling $150 million with an affiliate to ensurefunding availability for the money pool. The outstanding balance under LG&E Energy’s facility as of December 31,2004 was $65.4 million, and availability of $84.6 million remained.  LG&E Energy increased the size of itsrevolving credit facility to $200 million effective January 24, 2005.

 

In addition, in 2003 LG&E began borrowing long-term funds fromFidelia (see Note 9).

 

Intercompany agreements do not require interest payments forreceivables related to services provided when settled within 30 days.  The only interest income or expense recordedby LG&E relates to its receipt and payment of KU’s portion of off-systemsales and purchases.

 

LG&E’s intercompany interest income and expense for the years endedDecember 31, 2004, 2003 and 2002 were as follows:

 
| **(in thousands)**                | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|-----------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Interest on  money pool loans     |       | $        | 303        |     | $          | 1,751    |       | $ | 2,114 |   |
| Interest on  Fidelia loans        |       | 11,895   |       | 5,025    |       | —   |       |
| Interest  expense paid to KU      |       | 44       |       | 8        |       | 61       |       |
| Interest  income received from KU |       | 2        |       | 6        |       | 5        |       |
|                                   |            |          |            |          |            |          |            |  |  |  |

 

Other Intercompany Billings

 

LG&E Services provides LG&E with a variety of centralizedadministrative, management, and support services in accordance with agreementsapproved by the SEC under PUHCA. These charges include taxes paid by LG&EEnergy on behalf of LG&E, labor and burdens of LG&E Services employeesperforming services for LG&E, and vouchers paid by LG&E Services onbehalf of LG&E.  The cost of theseservices are directly

 

119

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charged to LG&E, or for general costs which cannot be directlyattributed, charged based on predetermined allocation factors, including thefollowing ratios: number of customers, total assets, revenues, number ofemployees, and other statistical information. These costs are charged on an actual cost basis.

 

In addition, LG&E and KU provide certain services to each other andto LG&E Services, in accordance with exceptions granted under PUHCA.Billings between LG&E and KU relate to labor and overheads associated withunion employees performing work for the other utility, charges related tojointly-owned combustion turbines, and other miscellaneous charges.  Billings from LG&E to LG&E Servicesrelate to information technology-related services provided by LG&Eemployees, cash received by LG&E Services on behalf of LG&E, andservices provided by LG&E to other non-regulated businesses which are paidthrough LG&E Services.

 

Intercompany billings to and from LG&E for the years ended December31, 2004, 2003 and 2002 were as follows:

 
| **(in thousands)**                     | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|----------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| LG&E Services billings to LG&E |       | $        | 190,351    |     | $          | 194,394  |       | $ | 183,100 |   |
| LG&E billings to KU                |       | 59,513   |       | 77,166   |       | 71,127   |       |
| KU billings to LG&E                |       | 7,188    |       | 16,636   |       | 11,921   |       |
| LG&E billings to LG&E Services |       | 12,470   |       | 23,743   |       | 15,079   |       |
|                                        |            |          |            |          |            |          |            |  |  |  |

 

**Note 15 – Accumulated Other Comprehensive Income**

 

Accumulated other comprehensive income consisted of the following:

 
| ** **                                                                                           | ** ** | **Minimum Pension**      | ** **    | **Accumulated Derivative** | ** ** | ** **    | ** ** | **Income** | ** **    | ** ** | ** ** |
|------------------------------------------------------------------------------------------------------|------------|-------------------------------|---------------|---------------------------------|------------|---------------|------------|------------|---------------|------------|------------|
| **(in thousands)**                                                                                   | ** ** | **Liability Adjustment** | ** **    | **Gain or Loss**      | ** ** | **Pre-Tax**   | ** ** | **Taxes**  | ** **    | **Net**    | ** ** |
|                                                                                                 |       |                          |          |                            |       |          |       |       |          |       |       |
| Balance at December 31, 2001                                                                         |       | $                             |  (24,712 | )                               | $          |  (8,655  | )          | $          |  (33,367 | )          | $          |  (13,467 | ) | $ |  (19,900 | ) |
| Minimum pension liability adjustment                                                                 |       | (25,999                       | )             | —                          |       | (25,999       | )          | (10,493    | )             | (15,506    | )          |
| Gains (losses) on derivative instruments designated  and qualifying as cash flow hedging instruments |       | —                        |          | (8,563                          | )          | (8,563        | )          | (3,457     | )             | (5,106     | )          |
| Balance at December 31, 2002                                                                         |       | (50,711                       | )             | (17,218                         | )          | (67,929       | )          | (27,417    | )             | (40,512    | )          |
|                                                                                                 |       |                          |          |                            |       |          |       |       |          |       |       |
| Minimum pension liability adjustment                                                                 |       | 3,114                         |          | —                          |       | 3,114         |       | 1,257      |          | 1,857      |       |
| Gains (losses) on derivative instruments designated  and qualifying as cash flow hedging instruments |       | —                        |          | 912                             |       | 912           |       | 368        |          | 544        |       |
| Balance at December 31, 2003                                                                         |       | (47,597                       | )             | (16,306                         | )          | (63,903       | )          | (25,792    | )             | (38,111    | )          |
|                                                                                                 |       |                          |          |                            |       |          |       |       |          |       |       |
| Minimum pension liability adjustment                                                                 |       | (10,228                       | )             | —                          |       | (10,228       | )          | (4,128     | )             | (6,100     | )          |
| Gains (losses) on derivative instruments designated  and qualifying as cash flow hedging instruments |       | —                        |          | (2,346                          | )          | (2,346        | )          | (947       | )             | (1,399     | )          |
| Balance at December 31, 2004                                                                         |       | $                             |  (57,825 | )                               | $          |  (18,652 | )          | $          |  (76,477 | )          | $          |  (30,867 | ) | $ |  (45,610 | ) |

 

**Note 16 - Selected Quarterly Data (Unaudited)**

 

Selected financial data for the four quarters of 2004 and 2003 areshown below.  Because of seasonalfluctuations in temperature and other factors, results for quarters mayfluctuate throughout the year.

 
| ** **           | ** ** | **Quarters Ended** | ** **    |
|----------------------|------------|--------------------|---------------|
| **(in thousands)**   | ** ** | **March**          | ** **    | **June** | ** ** | **September** | ** ** | **December** | ** ** |
| 2004                 |       |               |          |   |   |   |   |   |   |
| Operating revenues   |       | $                  |  361,963 |   | $ |  236,211 |   | $ |  261,842 |   | $ |  312,752 |   |
| Net operating income |       | 47,623             |          | 34,592 |   | 62,830 |   | 39,986 |   |
| Net income           |       | 24,219             |          | 17,139 |   | 32,538 |   | 21,722 |   |
|                 |       |               |          |   |   |   |   |   |   |
| 2003                 |       |               |          |   |   |   |   |   |   |
| Operating revenues   |       | $                  |  326,844 |   | $ |  215,373 |   | $ |  262,833 |   | $ |  288,471 |   |
| Net operating income |       | 49,831             |          | 21,004 |   | 71,387 |   | 36,530 |   |
| Net income           |       | 27,264             |          | 7,755 |   | 39,871 |   | 15,949 |   |

 

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Effective December 31, 2004, operating and non-operating income taxesare presented as “Federal and State Income Taxes” on LG&E’s ConsolidatedStatements of Income.  Prior to December31, 2004, the component of income taxes associated with operating income wasincluded in net operating income and the component of income taxes associatedwith non-operating income taxes was included in other income (expense) – net.  LG&E has applied this change inpresentation to all prior periods.

 
| ** **                                                    | ** ** | **Quarters Ended** | ** **   |
|---------------------------------------------------------------|------------|--------------------|--------------|
| **(in thousands)**                                            | ** ** | **March**          | ** **   | **June** | ** ** | **September** | ** ** | **December** | ** ** |
| 2004                                                          |       |               |         |   |   |   |   |   |   |
| Net operating income as previously reported                   |       | $                  |  32,598 |   | $ |  25,219 |   | $ |  41,741 |   |   |   |
| Plus income taxes reclassified from total  operating expenses |       | 15,025             |         | 9,373 |   | 21,089 |   |   |   |
| Net operating income                                          |       | $                  |  47,623 |   | $ |  34,592 |   | $ |  62,830 |   |   |   |
|                                                          |       |               |         |   |   |   |   |   |   |
| 2003                                                          |       |               |         |   |   |   |   |   |   |
| Net operating income as previously reported                   |       | $                  |  33,190 |   | $ |  16,290 |   | $ |  47,680 |   | $ |  25,525 |   |
| Plus income taxes reclassified from total  operating expenses |       | 16,641             |         | 4,714 |   | 23,707 |   | 11,005 |   |
| Net operating income                                          |       | $                  |  49,831 |   | $ |  21,004 |   | $ |  71,387 |   | $ |  36,530 |   |

 

As the result of EITF No. 02-03, LG&E has netted the powerpurchased expense for trading activities against electric operatingrevenue.  LG&E applied this guidanceto all prior periods beginning with the June 2003 10-Q filing, which had noimpact on previously reported net income or common equity (See Note 1).

 
| ** **                                       | ** ** | **Quarter Ended**  | ** ** |
|--------------------------------------------------|------------|--------------------|------------|
| **(in thousands)**                               | ** ** | **March 31, 2003** | ** ** |
|                                             |       |               |       |
| Gross operating revenues as previously  reported |       | $                  | 335,117    |   |
| Less costs reclassified from power  purchased    |       | 8,273              |       |
| Net operating revenues                           |       | $                  | 326,844    |   |

 

**Note 17 - Subsequent Events**

 

In January 2005, LG&E paid at maturity the $50 million loan fromFidelia using proceeds from short-term loans from the money pool.

 

In February2005, Kentucky’s Governor signed an executive order directing the KentuckyCommission, in conjunction with the Commerce Cabinet and the Environmental andPublic Protection Cabinet, to ‘develop a Strategic Blueprint for the continueduse and development of electric energy.’ This Strategic Blueprint will bedesigned to promote future investment in electric infrastructure for theCommonwealth of Kentucky, to protect Kentucky’s low-cost electric advantage, tomaintain affordable rates for all Kentuckians, and to preserve Kentucky’scommitment to environmental protection. In March 2005, the Kentucky Commission established Administrative CaseNo. 2005-00090 to collect information from all jurisdictional utilities inKentucky, including LG&E, pertaining to Kentucky electric generation,transmission and distribution systems. The Kentucky Commission must provide its Strategic Blueprint to theGovernor in early August 2005.  LG&Emust respond to the Kentucky Commission’s first set of data requests by the endof March 2005.

 

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LG&Epurchased from AEP an additional 0.73% interest in OVEC for a purchase price ofapproximately $0.1 million, resulting in an increase in LG&E ownership inOVEC from 4.9% to 5.63%.  The partiescompleted the share purchase transaction during March 2005.

 

Kentucky House Bill 272, also known as Kentucky’s Tax ModernizationPlan, was signed into law in March 2005.  This bill contains a numberof changes in Kentucky’s tax system, including the reduction of the Corporateincome tax rate from 8.25% to 7% effective January 1, 2005, and a furtherreduction to 6% effective January 1, 2007. The impact of these reduced rates is expected to decrease LG&E’sincome tax expense in future periods. Furthermore, these reduced rates will result in the reversal ofaccumulated temporary differences at lower rates than originally provided.  LG&E is presently evaluating the impactof this and other changes to the Kentucky tax system, however, no materialadverse impacts on cash flows or results of operations are expected.

 

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Louisville Gas and Electric Company

REPORT OF MANAGEMENT

 

The management of Louisville Gas and Electric Company (“LG&E”) isresponsible for the preparation and integrity of the financial statements andrelated information included in this Annual Report.  These statements have been prepared inaccordance with accounting principles generally accepted in the United Statesapplied on a consistent basis and, necessarily, include amounts that reflectthe best estimates and judgment of management.

 

LG&E’s financial statements for the three years ended December 31,2004 have been audited by PricewaterhouseCoopers LLP, an independent registeredpublic accounting firm.  Management madeavailable to PricewaterhouseCoopers LLP all LG&E’s financial records andrelated data as well as the minutes of shareholders’ and directors’ meetings.

 

Management has established and maintains a system of internal controlsthat provides reasonable assurance that transactions are completed inaccordance with management’s authorization, that assets are safeguarded andthat financial statements are prepared in conformity with generally acceptedaccounting principles.  Managementbelieves that an adequate system of internal controls is maintained through theselection and training of personnel, appropriate division of responsibility,establishment and communication of policies and procedures and by regularreviews of internal accounting controls by LG&E’s internal auditors.  Management reviews and modifies its system ofinternal controls in light of changes in conditions and operations, as well asin response to recommendations from the internal and external auditors.  These recommendations for the year endedDecember 31, 2004, did not identify any material weaknesses in the design andoperation of LG&E’s internal control structure.

 

LG&E isnot an accelerated filer under the Sarbanes-Oxley Act of 2002 and associatedrules (the “Act”) and consequently anticipates issuing Management’sCertification on Internal Controls over Financial Reporting pursuant to Section404 of the Act in its first periodic report covering the fiscal year endedDecember 31, 2006 as permitted by SEC rulemaking.

 

In carrying out its oversight role for the financial reporting andinternal controls of LG&E, the Board of Directors meets regularly withLG&E’s independent auditors, internal auditors and management.  The Board of Directors reviews the results ofthe independent auditors’ audit of the financial statements and their auditprocedures, and discusses the adequacy of internal accounting controls.  The Board of Directors also approves theannual internal auditing program and reviews the activities and results of theinternal auditing function.  Both theindependent registered public accounting firm and the internal auditors haveaccess to the Board of Directors at any time.

 

LG&E maintains and internally communicates a written code ofbusiness conduct and a senior financial officer code of ethics which address,among other items, potential conflicts of interest, compliance with laws,including those relating to financial disclosure, and the confidentiality ofproprietary information.

 

S. Bradford Rives

Chief Financial Officer

 

Louisville Gas and Electric Company

Louisville, Kentucky

 

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Louisville Gas and Electric Company andSubsidiary

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Shareholders of Louisville Gas and Electric Company andSubsidiary:

 

In our opinion, the accompanying consolidated balance sheets and therelated consolidated statements of capitalization, income, retained earnings,cash flows and comprehensive income present fairly, in all material respects,the financial position of Louisville Gas and Electric Company and Subsidiary atDecember 31, 2004 and December 31, 2003, and the results of their operationsand their cash flows for each of the three years in the period ended December31, 2004 in conformity with accounting principles generally accepted in theUnited States of America.  In addition, in our opinion, based on ouraudits, the financial statement schedule asof and for the three years in the period ended December 31, 2004, listed in theindex appearing under Item 15(a)(2), presents fairly, in all material respects,the information set forth therein when read in conjunction with the relatedconsolidated****financial statements.  These financial statements are theresponsibility of the Company’s management. Our responsibility is to express anopinion on these financial statements based on our audits.  We conducted our audits of these statementsin accordance with the standards of the Public Company Accounting OversightBoard (United States). Those standards require that we plan and perform theaudit to obtain reasonable assurance about whether the financial statements arefree of material misstatement.  An auditincludes examining, on a test basis, evidence supporting the amounts anddisclosures in the financial statements, assessing the accounting principlesused and significant estimates made by management, and evaluating the overall financialstatement presentation.  We believe thatour audits provide a reasonable basis for our opinion.

 

As discussed in Note 1 to the consolidatedfinancial statements, effective January 1, 2003,  Louisville Gas and Electric Company andSubsidiary adopted EITF No. 02-03*, Issues Involved inAccounting for Derivative Contracts Held for Trading Purposes and ContractsInvolved in Energy Trading and Risk Management Activities*.

 

As discussed in Note 1 to the consolidatedfinancial statements, effective January 1, 2003, Louisville Gas and ElectricCompany and Subsidiary adopted Statement of Financial Accounting Standards No.143, *Accounting for Asset Retirement Obligations*.

 

As discussed in Note 1 to the consolidatedfinancial statements, effective July 1, 2003, Louisville Gas and ElectricCompany and Subsidiary adopted Statement of Financial Accounting Standards No.150, *Accounting for Certain Financial Instruments withCharacteristics of Both Liabilities and Equity.*

 
| /s/ PricewaterhouseCoopers LLP |   |
|--------------------------------|--------|
|                           |
|                           |
|                           |
| Louisville, Kentucky           |
| February 4, 2005               |

 

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INDEX OF ABBREVIATIONS

 
| AFUDC               |   | Allowance for Funds Used During  Construction                |
|---------------------|--------|--------------------------------------------------------------|
| ARO                 |   | Asset Retirement Obligation                                  |
| 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                                          |
| CWIP                |   | Construction Work in Progress                                |
| DSM                 |   | Demand Side Management                                       |
| ECAR                |   | East Central Area Reliability Region                         |
| 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                         |
| FGD                 |   | Flue Gas Desulfurization                                     |
| 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                               |
| IRP                 |   | Integrated Resource Plan                                     |
| 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 LLC (as successor to  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 Transmission 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 Executive 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 LLC                   |
| 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 |
| WNA                 |   | Weather Normalization Adjustment             |

 

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Kentucky Utilities Company and Subsidiary

Consolidated Statements of Income

(Thousands of $)

 
| ** **                                          | ** ** | **Years Ended December 31** | ** ** |
|-----------------------------------------------------|------------|-----------------------------|------------|
| ** **                                          | ** ** | **2004**                    | ** ** | **2003** | ** ** | **2002** | ** ** |
|                                                |       |                        |       |   |   |   |   |
| OPERATING REVENUES:                                 |       |                        |       |   |   |   |   |
| Total operating revenues (Notes 1 and 13)           |       | $                           | 995,362    |   | $ | 891,778 |   | $ | 861,664 |   |
|                                                |       |                        |       |   |   |   |   |
| OPERATING EXPENSES:                                 |       |                        |       |   |   |   |   |
| Fuel for electric generation                        |       | 292,046                     |       | 265,935 |   | 250,117 |   |
| Power purchased (Note 11)                           |       | 144,232                     |       | 140,063 |   | 131,400 |   |
| Other operation and maintenance expenses            |       | 222,584                     |       | 221,765 |   | 222,010 |   |
| Depreciation and amortization (Note 1)              |       | 108,653                     |       | 101,805 |   | 95,462 |   |
| Total operating expenses                            |       | 767,515                     |       | 729,568 |   | 698,989 |   |
|                                                |       |                        |       |   |   |   |   |
| Net operating income                                |       | 227,847                     |       | 162,210 |   | 162,675 |   |
|                                                |       |                        |       |   |   |   |   |
| Other income – net (Note 8 and Note 13)        |       | 7,545                       |       | 4,522 |   | 6,521 |   |
| Interest expense (Notes 9 and 10)                   |       | 11,343                      |       | 19,309 |   | 24,612 |   |
| Interest expense to affiliated companies  (Note 13) |       | 14,158                      |       | 5,940 |   | 1,076 |   |
|                                                |       |                        |       |   |   |   |   |
| Net income before income taxes                      |       | 209,891                     |       | 141,483 |   | 143,508 |   |
|                                                |       |                        |       |   |   |   |   |
| Federal and state income taxes (Note 7)             |       | 76,420                      |       | 50,081 |   | 50,124 |   |
|                                                |       |                        |       |   |   |   |   |
| Net income                                          |       | $                           | 133,471    |   | $ | 91,402 |   | $ | 93,384 |   |
|                                                     |            |                             |            |  |  |  |  |  |  |  |  |  |

 

Consolidated Statements of Retained Earnings

(Thousands of $)

 
| ** **          | ** **                        | **Years Ended December 31** | ** ** |
|---------------------|-----------------------------------|-----------------------------|------------|
| ** **          | ** **                        | **2004**                    | ** ** | **2003** | ** ** | **2002** | ** ** |
|                |                              |                        |       |   |   |   |   |
| Balance January 1   |                              | $                           | 591,170    |   | $ | 502,024 |   | $ | 410,896 |   |
| Add net income      |                              | 133,471                     |       | 91,402 |   | 93,384 |   |
|                |                              | 724,641                     |       | 593,426 |   | 504,280 |   |
|                |                              |                        |       |   |   |   |   |
| Deduct:             | Cash dividends declared on stock: |                        |       |   |   |   |   |   |
|                | 4.75% cumulative preferred        |                        | 950        |   | 950 |   | 950 |   |
|                | 6.53% cumulative preferred        |                        | 1,305      |   | 1,306 |   | 1,306 |   |
|                | Common                            |                        | 63,000     |   | — |   | — |   |
|                |                              | 65,255                      |       | 2,256 |   | 2,256 |   |
|                |                              |                        |       |   |   |   |   |
| Balance December 31 |                              | $                           | 659,386    |   | $ | 591,170 |   | $ | 502,024 |   |

 

The accompanying notes are an integral part of these consolidatedfinancial statements.

 

127

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Kentucky Utilities Company and Subsidiary

Consolidated Statements of ComprehensiveIncome

(Thousands of $)

 
| ** **                                                                                                                                                                      | ** ** | **Years Ended December 31** | ** ** |
|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-----------------------------|------------|
| ** **                                                                                                                                                                      | ** ** | **2004**                    | ** ** | **2003** | ** ** | **2002** | ** ** |
|                                                                                                                                                                            |       |                        |       |   |   |   |   |
| Net income                                                                                                                                                                      |       | $                           | 133,471    |   | $ | 91,402 |   | $ | 93,384 |   |
|                                                                                                                                                                            |       |                        |       |   |   |   |   |
| Gains (losses) on derivative instruments  and hedging activities, net of tax benefit/(expense) of $(100), $99 and $1,075  for 2004, 2003 and 2002, respectively (Notes 1 and 4) |       | 146                         |       | (147 | ) | (1,588 | ) |
|                                                                                                                                                                            |       |                        |       |   |   |   |   |
| Additional minimum pension liability  adjustment, net of tax benefit/(expense) of $4,990, $(3,098) and $7,081 for  2004, 2003 and 2002, respectively (Note 6)                   |       | (7,373                      | )          | 4,578 |   | (10,462 | ) |
|                                                                                                                                                                            |       |                        |       |   |   |   |   |
| Other comprehensive (loss) income, net of  tax (Note 14)                                                                                                                        |       | (7,227                      | )          | 4,431 |   | (12,050 | ) |
|                                                                                                                                                                            |       |                        |       |   |   |   |   |
| Comprehensive income                                                                                                                                                            |       | $                           | 126,244    |   | $ | 95,833 |   | $ | 81,334 |   |

 

The accompanying notes are an integral part of these consolidatedfinancial statements.

 

128

----

 

Kentucky Utilities Company and Subsidiary

Consolidated Balance Sheets

(Thousands of $)

 
| ** **                                                                               | ** ** | **December 31** | ** ** |
|------------------------------------------------------------------------------------------|------------|-----------------|------------|
| ** **                                                                               | ** ** | **2004**        | ** ** | **2003** | ** ** |
|                                                                                     |       |            |       |   |   |
| ASSETS:                                                                                  |       |            |       |   |   |
| Current assets:                                                                          |       |            |       |   |   |
| Cash and cash equivalents (Note 1)                                                       |       | $               | 4,581      |   | $ | 4,869 |   |
| Accounts receivable-less reserve of $623 in  2004 and $672 in 2003 (Note 4)              |       | 112,580         |       | 49,289 |   |
| Materials and supplies - at average cost:                                                |       |            |       |   |   |
| Fuel (predominantly coal) (Note 1)                                                       |       | 52,249          |       | 45,538 |   |
| Other (Note 1)                                                                           |       | 27,972          |       | 27,094 |   |
| Prepayments and other                                                                    |       | 9,910           |       | 13,100 |   |
|                                                                                     |       | 207,292         |       | 139,890 |   |
|                                                                                     |       |            |       |   |   |
| Other property and investments - less  reserve of $131 in 2004 and $130 in 2003 (Note 1) |       | 20,478          |       | 17,862 |   |
|                                                                                     |       |            |       |   |   |
| Utility plant, at original cost (Note 1)                                                 |       | 3,571,166       |       | 3,193,145 |   |
|                                                                                     |       |            |       |   |   |
| Less: reserve for depreciation                                                           |       | 1,415,008       |       | 1,360,253 |   |
|                                                                                     |       | 2,156,158       |       | 1,832,892 |   |
|                                                                                     |       |            |       |   |   |
| Construction work in progress                                                            |       | 140,983         |       | 403,512 |   |
|                                                                                     |       | 2,297,141       |       | 2,236,404 |   |
| Deferred debits and other assets:                                                        |       |            |       |   |   |
| Unamortized debt expense (Note 1)                                                        |       | 4,732           |       | 4,481 |   |
| Regulatory assets (Note 3)                                                               |       | 61,435          |       | 72,318 |   |
| Long-term derivative asset                                                               |       | 6,102           |       | 12,223 |   |
| Other                                                                                    |       | 13,259          |       | 21,916 |   |
|                                                                                     |       | 85,528          |       | 110,938 |   |
|                                                                                     |       |            |       |   |   |
|                                                                                     |       | $               | 2,610,439  |   | $ | 2,505,094 |   |
|                                                                                          |            |                 |            |  |  |  |  |  |  |

 

Theaccompanying notes are an integral part of these consolidated financialstatements.

 

129

----

 

Kentucky Utilities Company and Subsidiary

ConsolidatedBalance Sheets(continued)

(Thousands of $)

 
| ** **                                                        | ** ** | **December 31** | ** ** |
|-------------------------------------------------------------------|------------|-----------------|------------|
| ** **                                                        | ** ** | **2004**        | ** ** | **2003** | ** ** |
|                                                              |       |            |       |   |   |
| CAPITAL AND LIABILITIES:                                          |       |            |       |   |   |
| Current liabilities:                                              |       |            |       |   |   |
| Current portion of long-term debt:                                |       |            |       |   |   |
| Current portion of long-term bonds (Note 9)                       |       | $               | 87,130     |   | $ | 91,930 |   |
| Current portion of long-term notes to  affiliated company         |       | 75,000          |       | — |   |
|                                                              |       | 162,130         |       | 91,930 |   |
|                                                              |       |            |       |   |   |
| Notes payable to affiliated company (Notes  10 and 13)            |       | 34,820          |       | 43,231 |   |
| Accounts payable                                                  |       | 77,885          |       | 69,947 |   |
| Accounts payable to affiliated companies  (Note 13)               |       | 32,834          |       | 26,426 |   |
| Accrued income taxes                                              |       | 5,889           |       | 7,104 |   |
| Customer deposits                                                 |       | 14,998          |       | 13,453 |   |
| Other                                                             |       | 15,338          |       | 14,245 |   |
|                                                              |       | 181,764         |       | 174,406 |   |
|                                                              |       |            |       |   |   |
|                                                              |       | 343,894         |       | 266,336 |   |
|                                                              |       |            |       |   |   |
| Long-term debt (see statements of  capitalization):               |       |            |       |   |   |
| Long-term bonds (Note 9)                                          |       | 306,081         |       | 312,646 |   |
| Long-term notes to affiliated company (Note  9)                   |       | 258,000         |       | 283,000 |   |
|                                                              |       | 564,081         |       | 595,646 |   |
| Deferred credits and other liabilities:                           |       |            |       |   |   |
| Accumulated deferred income taxes (Notes 1  and 7)                |       | 282,635         |       | 261,258 |   |
| Investment tax credit, in process of  amortization                |       | 3,805           |       | 5,859 |   |
| Accumulated provision for pensions and  related benefits (Note 6) |       | 77,915          |       | 103,101 |   |
| Asset retirement obligations                                      |       | 20,953          |       | 19,698 |   |
| Regulatory liabilities (Note 3):                                  |       |            |       |   |   |
| Accumulated cost of removal of utility  plant                     |       | 266,805         |       | 256,744 |   |
| Other                                                             |       | 24,718          |       | 38,027 |   |
| Other                                                             |       | 16,960          |       | 10,741 |   |
|                                                              |       | 693,791         |       | 695,428 |   |
|                                                              |       |            |       |   |   |
| Commitments and contingencies (Note 11)                           |       |            |       |   |   |
|                                                              |       |            |       |   |   |
| Cumulative preferred stock (see statements  of capitalization)    |       | 39,727          |       | 39,727 |   |
|                                                              |       |            |       |   |   |
| Common equity (see statements of  capitalization)                 |       | 968,946         |       | 907,957 |   |
|                                                              |       |            |       |   |   |
|                                                              |       | $               | 2,610,439  |   | $ | 2,505,094 |   |

 

Theaccompanying notes are an integral part of these consolidated financialstatements.

 

130

----

 

Kentucky UtilitiesCompany and Subsidiary

Consolidated Statements of Cash Flows

(Thousands of $)

 
| ** **                                                  | ** ** | **Years Ended December 31** | ** ** |
|-------------------------------------------------------------|------------|-----------------------------|------------|
| ** **                                                  | ** ** | **2004**                    | ** ** | **2003** | ** ** | **2002** | ** ** |
|                                                        |       |                        |       |   |   |   |   |
| CASH FLOWS FROM OPERATING ACTIVITIES:                       |       |                        |       |   |   |   |   |
| Net income                                                  |       | $                           | 133,471    |   | $ | 91,402 |   | $ | 93,384 |   |
| Items not requiring cash currently:                         |       |                        |       |   |   |   |   |
| Depreciation and amortization                               |       | 108,653                     |       | 101,805 |   | 95,462 |   |
| Deferred income taxes - net                                 |       | 16,597                      |       | 15,278 |   | (2,038 | ) |
| Investment tax credit - net                                 |       | (2,054                      | )          | (2,641 | ) | (2,955 | ) |
| VDT amortization                                            |       | 11,754                      |       | 12,030 |   | 11,500 |   |
| Deferred storm costs                                        |       | (3,562                      | )          | — |   | — |   |
| Other                                                       |       | (4,239                      | )          | 16,112 |   | 12,784 |   |
| Change in certain net current assets:                       |       |                        |       |   |   |   |   |
| Accounts receivable                                         |       | (13,291                     | )          | (401 | ) | (8,497 | ) |
| Materials and supplies                                      |       | (7,589                      | )          | (134 | ) | (2,928 | ) |
| Accounts payable                                            |       | 14,346                      |       | 999 |   | 10,225 |   |
| Accrued income taxes                                        |       | (1,215                      | )          | 3,854 |   | (15,565 | ) |
| Prepayments and other                                       |       | 5,828                       |       | (2,851 | ) | (2,350 | ) |
| Sale of accounts receivable (Note 4)                        |       | (50,000                     | )          | 700 |   | 4,200 |   |
| Pension funding                                             |       | (43,409                     | )          | (10,231 | ) | (15,283 | ) |
| Earnings sharing mechanism receivable                       |       | 9,267                       |       | 1,118 |   | — |   |
| Environmental cost recovery mechanism  refundable           |       | (8,013                      | )          | 6,227 |   | 2,326 |   |
| Litigation settlement                                       |       | 11,386                      |       | — |   | — |   |
| Other                                                       |       | 7,990                       |       | 98 |   | (4,508 | ) |
| Net cash provided by operating activities                   |       | 185,920                     |       | 233,365 |   | 175,757 |   |
|                                                        |       |                        |       |   |   |   |   |
| CASH FLOWS FROM INVESTING ACTIVITIES:                       |       |                        |       |   |   |   |   |
| Long-term investments                                       |       | (57                         | )          | 140 |   | — |   |
| Construction expenditures                                   |       | (157,579                    | )          | (341,869 | ) | (237,909 | ) |
| Net cash used for investing activities                      |       | (157,636                    | )          | (341,729 | ) | (237,909 | ) |
|                                                        |       |                        |       |   |   |   |   |
| CASH FLOWS FROM FINANCING ACTIVITIES:                       |       |                        |       |   |   |   |   |
| Long-term borrowings from affiliated  company               |       | 50,000                      |       | 283,000 |   | — |   |
| Short-term borrowings from affiliated  company              |       | 497,750                     |       | 655,241 |   | 518,400 |   |
| Repayment of short-term borrowings from  affiliated company |       | (506,161                    | )          | (731,500 | ) | (446,700 | ) |
| Retirement of first mortgage bonds                          |       | —                      |       | (95,000 | ) | — |   |
| Issuance of pollution control bonds                         |       | 50,000                      |       | — |   | 133,930 |   |
| Issuance expense on pollution control bonds                 |       | (2,126                      | )          | (1,643 | ) | (5,196 | ) |
| Retirement of pollution control bonds                       |       | (54,800                     | )          | — |   | (133,930 | ) |
| Interest rate swap settlement                               |       | 2,020                       |       | — |   | — |   |
| Payment of dividends                                        |       | (65,255                     | )          | (2,256 | ) | (2,256 | ) |
| Net cash (used for) provided by financing  activities       |       | (28,572                     | )          | 107,842 |   | 64,248 |   |
|                                                        |       |                        |       |   |   |   |   |
| Change in cash and cash equivalents                         |       | (288                        | )          | (522 | ) | 2,096 |   |
|                                                        |       |                        |       |   |   |   |   |
| Cash and cash equivalents at beginning of  year             |       | 4,869                       |       | 5,391 |   | 3,295 |   |
|                                                        |       |                        |       |   |   |   |   |
| Cash and cash equivalents at end of year                    |       | $                           | 4,581      |   | $ | 4,869 |   | $ | 5,391 |   |
|                                                        |       |                        |       |   |   |   |   |
| Supplemental disclosures of cash flow  information:         |       |                        |       |   |   |   |   |
| Cash paid during the year for:                              |       |                        |       |   |   |   |   |
| Income taxes                                                |       | $                           | 58,203     |   | $ | 37,166 |   | $ | 59,580 |   |
| Interest on borrowed money                                  |       | 15,641                      |       | 20,204 |   | 37,866 |   |
| Interest to affiliated companies on  borrowed money         |       | 13,164                      |       | 3,533 |   | 1,725 |   |

 

The accompanying notes are an integral part of these consolidatedfinancial statements.

 

131

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Kentucky Utilities Company and Subsidiary

Consolidated Statements of Capitalization

(Thousands of $)

 
| ** **                                                                                     | ** ** | **December 31**             | ** **   |
|------------------------------------------------------------------------------------------------|------------|-----------------------------|--------------|
| ** **                                                                                     | ** ** | **2004**                    | ** **   | **2003** | ** ** |
| LONG-TERM DEBT (Note 9):                                                                       |       |                        |         |   |   |
| First mortgage bonds -                                                                         |       |                        |         |   |   |
| S due January 15, 2006, 5.99%                                                                  |       | $                           |  36,000 |   | $ |  36,000 |   |
| P due May 15, 2007, 7.92%                                                                      |       | 53,000                      |         | 53,000 |   |
| R due June 1, 2025, 7.55%                                                                      |       | 50,000                      |         | 50,000 |   |
| Pollution control series:                                                                      |       |                        |         |   |   |
| 9, due December 1, 2023, 5.75%                                                                 |       | —                      |         | 50,000 |   |
| 10, due November 1, 2024, variable %                                                           |       | 54,000                      |         | 54,000 |   |
| 11, due May 1, 2023, variable %                                                                |       | 12,900                      |         | 12,900 |   |
| 12, due February 1, 2032, variable %                                                           |       | 20,930                      |         | 20,930 |   |
| 13, due February 1, 2032, variable %                                                           |       | 2,400                       |         | 2,400 |   |
| 14, due February 1, 2032, variable %                                                           |       | 2,400                       |         | 7,200 |   |
| 15, due February 1, 2032, variable %                                                           |       | 7,400                       |         | 7,400 |   |
| 16, due October 1, 2032, variable %                                                            |       | 96,000                      |         | 96,000 |   |
| 17, due October 1, 2034, variable %                                                            |       | 50,000                      |         | — |   |
| Notes payable to Fidelia:                                                                      |       |                        |         |   |   |
| Due April 30, 2013, 4.55%, unsecured                                                           |       | 100,000                     |         | 100,000 |   |
| Due August 15, 2013, 5.31%, secured                                                            |       | 75,000                      |         | 75,000 |   |
| Due November 24, 2010, 4.24%, secured                                                          |       | 33,000                      |         | 33,000 |   |
| Due December 19, 2005, 2.29%, secured                                                          |       | 75,000                      |         | 75,000 |   |
| Due January 16, 2012, 4.39%, unsecured                                                         |       | 50,000                      |         | — |   |
| Long-term debt marked to market (Note 4)                                                       |       | 8,181                       |         | 14,746 |   |
|                                                                                           |       |                        |         |   |   |
| Total long-term debt outstanding                                                               |       | 726,211                     |         | 687,576 |   |
|                                                                                           |       |                        |         |   |   |
| Less current portion of long-term debt                                                         |       | 162,130                     |         | 91,930 |   |
|                                                                                           |       |                        |         |   |   |
| Long-term debt                                                                                 |       | 564,081                     |         | 595,646 |   |
|                                                                                           |       |                        |         |   |   |
| CUMULATIVE PREFERRED STOCK:                                                                    |       |                        |         |   |   |
| ** **                                                                                     | ** ** | **Shares**

**Outstanding** | ** **   | **Current**

**Redemption Price** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Without par value, 5,300,000 shares  authorized -                                              |       |                        |         |   |   |   |   |   |   |
| 4.75% series, $100 stated value redeemable  on 30 days notice by KU                            |       | 200,000                     |         | $ |  101.00 |   | 20,000 |   | 20,000 |   |
| 6.53% series, $100 stated value                                                                |       | 200,000                     |         | $ |  102.94 |   | 20,000 |   | 20,000 |   |
| Preferred stock expense                                                                        |       |                        |         |   |   | (273 | ) | (273 | ) |
|                                                                                           |       |                        |         |   |   | 39,727 |   | 39,727 |   |
|                                                                                           |       |                        |         |   |   |   |   |   |   |
| COMMON EQUITY:                                                                                 |       |                        |         |   |   |   |   |   |   |
| Common stock, without par value - authorized  80,000,000 shares, outstanding 37,817,878 shares |       |                        |         |   |   | 308,140 |   | 308,140 |   |
| Common stock expense                                                                           |       |                        |         |   |   | (322 | ) | (322 | ) |
| Additional paid-in-capital                                                                     |       |                        |         |   |   | 15,000 |   | 15,000 |   |
| Accumulated other comprehensive income (Note 14)                                          |       |                        |         |   |   | (13,258 | ) | (6,031 | ) |
|                                                                                           |       |                        |         |   |   |   |   |   |   |
| Retained earnings                                                                              |       |                        |         |   |   | 647,300 |   | 581,644 |   |
| Undistributed subsidiary earnings                                                              |       |                        |         |   |   | 12,086 |   | 9,526 |   |
| Total retained earnings                                                                        |       |                        |         |   |   | 659,386 |   | 591,170 |   |
|                                                                                           |       |                        |         |   |   |   |   |   |   |
|                                                                                           |       |                        |         |   |   | 968,946 |   | 907,957 |   |
|                                                                                           |       |                        |         |   |   |   |   |   |   |
| Total capitalization                                                                           |       |                        |         |   |   | $ |  1,572,754 |   | $ |  1,543,330 |   |

 

The accompanying notes are an integral part of these consolidatedfinancial statements.

 

132

----

 

Kentucky Utilities Company and Subsidiary

Notes to Consolidated Financial Statements

 

**Note 1 - Summary of Significant Accounting Policies**

 

KU, a subsidiary of LG&E Energy and an indirect subsidiary of E.ON,is a regulated public utility engaged in the generation, transmission,distribution, and sale of electric energy. LG&E Energy is an exempt public utility holding company with whollyowned subsidiaries including LG&E, KU, Capital Corp., LEM, and LG&EServices.  All of KU’s common stock isheld by LG&E Energy.  In May 2004, KUdissolved its accounts receivable securitization-related subsidiary, KU R.  Prior to May 2004, the consolidated financialstatements include the accounts of KU and KU R with the elimination ofintercompany accounts and transactions.

 

On December 11, 2000, LG&E Energy was acquired byPowergen.  On July 1, 2002, E.ON, aGerman company, completed its acquisition of Powergen plc (now PowergenLimited).  E.ON is a registered publicutility holding company under PUHCA.

 

No costs associated with the E.ON purchase of Powergen or the Powergenpurchase of LG&E Energy nor any effects of purchase accounting have been reflectedin the financial statements of KU.

 

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

 

Certain reclassification entries have been made to the previous years’financial statements to conform to the 2004 presentation with no impact on thebalance sheet net assets or previously reported income.  Effective December 31, 2004, operating andnon-operating income taxes are presented as “Federal and State Income Taxes” onKU’s Consolidated Statements of Income. Prior to December 31, 2004, the component of income taxes associatedwith operating income was included in net operating income and the component ofincome taxes associated with non-operating income taxes was included in otherincome (expense) – net.  KU has appliedthis change in presentation to all prior periods.

 

**Regulatory Accounting. **Accountingfor the regulated utility business conforms with generally accepted accountingprinciples as applied to regulated public utilities and as prescribed by FERC,the Kentucky Commission and the Virginia Commission.  KU is subject to SFAS No. 71, under whichcertain costs that would otherwise be charged to expense are deferred asregulatory assets based on expected recovery from customers in futurerates.  Likewise, certain credits thatwould otherwise be reflected as income are deferred as regulatory liabilitiesbased on expected return to customers in future rates.  KU’s current or expected recovery of deferredcosts and expected return of deferred credits is based on specific ratemakingdecisions or precedent for each item.  See Note 3 for additional detail regarding regulatory assets andliabilities.

 

**Utility Plant.** KU’s utility plant is stated at original cost, which includespayroll-related costs such as taxes, fringe benefits, and administrative andgeneral costs.  Construction work inprogress has been included in the rate base for determining retail customerrates.  KU has not recorded a significantallowance for funds used during construction.

 

The cost of plant retired or disposed of in the normal course ofbusiness is deducted from plant accounts and such cost, plus removal expenseless salvage value, is charged to the reserve for depreciation.  When complete operating units are disposed of,appropriate adjustments are made to the reserve for depreciation and gains andlosses, if any, are recognized.

 

**Depreciation and Amortization.**  Depreciation is provided on the straight-linemethod over the estimated service lives of depreciable plant.  The amounts provided were approximately 3.1%in 2004, 3.1% in 2003 and

 

133

----

 

3.1% in 2002, of average depreciable plant. Of the amount provided fordepreciation at December 31, 2004 and 2003, approximately 0.5% and 0.6%,respectively, was related to the retirement, removal and disposal costs of longlived assets.

 

**Cash and Cash Equivalents. **KUconsiders all debt instruments purchased with a maturity of three months orless to be cash equivalents.

 

**Fuel Inventory.**  Fuel inventories of $52.2 million and $45.5million at December 31, 2004 and 2003, respectively, are included in Fuel inthe balance sheet.  The inventory isaccounted for using the average-cost method.

 

**Other Materials and Supplies.**  Non-fuel materials and supplies of $28.0million and $27.1 million at December 31, 2004 and 2003, respectively, areaccounted for using the average-cost method.

 

**Financial Instruments.**  KU uses over-the-counter interest-rate swapagreements to hedge its exposure to interest rates.  Gains and losses on interest-rate swaps usedto hedge interest rate risk are reflected in interest charges monthly.  KU uses sales of market-traded electricforward contracts for periods less than one year to hedge the price volatilityof its forecasted peak electric off-system sales.  Gains and losses resulting fromineffectiveness are shown in other income (expense) and to the extent that thehedging relationship has been effective, gains and losses are reflected inother comprehensive income.  Wholesalesales of excess asset capacity and wholesale purchases are treated as normalsales and purchases under SFAS No. 133, SFAS No. 138 and SFAS No. 149 and arenot marked-to-market.  See Note 4,Financial Instruments and Note 14, Accumulated Other Comprehensive Income.

 

**Unamortized Debt Expense.**  Debt expense is capitalized in deferreddebits and amortized over the lives of the related bond issues, consistent withregulatory practices.

 

**Deferred Income Taxes.**  Deferred income taxes are recognized atcurrently enacted tax rates for all material temporary differences between thefinancial reporting and income tax basis of assets and liabilities.

 

**Investment Tax Credits.**  Investment tax credits resulted from provisionsof the tax law that permitted a reduction of KU’s tax liability based oncredits for certain construction expenditures. Deferred investment tax credits are being amortized to income over theestimated lives of the related property that gave rise to the credits.

 

**IncomeTaxes.** Income taxes are accounted for under SFAS No.109.  In accordance with this statement,deferred tax assets and liabilities are recognized for the future taxconsequences attributable to differences between the financial statementcarrying amounts of existing assets and liabilities and their respective taxbases, as measured by enacted tax rates that are expected to be in effect inthe periods when the deferred tax assets and liabilities are expected to besettled or realized. Significant judgment is required in determining theprovision for income taxes, and there are many transactions for which theultimate tax outcome is uncertain.  Toprovide for these uncertainties or exposures, an allowance is maintained fortax contingencies, the balance of which management believes is adequate.  Tax contingencies are analyzed periodicallyand adjustments are made when events occur to warrant a change.  The company is currently in the examinationphase of IRS audits for the years 1999 to 2003 and expects some or all of theseaudits to be completed within the next 12 months.  The results of audit assessments by taxingauthorities are not anticipated to have a material adverse effect on cash flowsor results of operations.

 

**Revenue Recognition.**  Revenues are recorded based on servicerendered to customers through month-end. KU accrues an estimate for unbilled revenues from each meter readingdate to the end of the accounting period based on allocating the daily systemnet deliveries between billed volumes and unbilled volumes.  The allocation is based on a daily ratio ofthe number of meter reading cycles remaining in the month to the total numberof meter reading

 

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cycles in each month.  Each day’sratio is then multiplied by each day’s system net deliveries to determine anestimated billed and unbilled volume for each day of the accountingperiod.  The unbilled revenue estimatesincluded in accounts receivable were approximately $47.5 million and $38.7million at December 31, 2004, and 2003, respectively.

 

**Allowance for Doubtful Accounts.** At December 31, 2004 and 2003, the KUallowance for doubtful accounts was $0.6 million and $0.7 million,respectively.  The allowance is based onthe ratio of the amounts charged-off during the last twelve months to theretail revenues billed over the same period multiplied by the retail revenuesbilled over the last four months. Accounts with no payment activity are charged-off after four months.

 

**Fuel Costs.** The cost of fuel for electric generation is charged to expense as used.

 

**Other Property and Investments. **Otherproperty and investments on the Balance Sheet consists of KU’s investment inEEI, economic development loans provided to various communities in KU’s serviceterritory, KU’s investment in OVEC, funds related to KU’s long-term purchasedpower contract with OMU and non-utility plant.  KU’s investment in EEI is accounted for under the equity method ofaccounting and, as of December 31, 2004 and 2003, totaled $13.4 million and$10.8 million, respectively.  KU’s investmentin OVEC is accounted for under the cost method of accounting.  As of December 31, 2004 and 2003, KU’sinvestment in OVEC totaled $0.3 million. KU is not the primary beneficiary of EEI or OVEC, and, therefore,neither are consolidated into the financial statements of KU.

 

**Management’s Use of Estimates.**  The preparation of financial statements inconformity with generally accepted accounting principles requires management tomake estimates and assumptions that affect the reported assets and liabilitiesand disclosure of contingent items at the date of the financial statements andthe reported amounts of revenues and expenses during the reporting period.  Accrued liabilities, including legal andenvironmental, are recorded when they are probable and estimable.  Actual results could differ from thoseestimates.  See Note 11, Commitments andContingencies, for a further discussion.

 

**New Accounting Pronouncements.**  The following accounting pronouncements wereissued that affected KU in 2003:

 

SFAS No. 143

 

SFAS No. 143 was issued in 2001. SFAS No. 143 establishes accounting and reporting standards forobligations associated with the retirement of tangible long-lived assets andthe associated asset retirement costs.

 

The effective implementation date for SFAS No. 143 was January 1,2003.  Management has calculated theimpact of SFAS No. 143 and FERC Final Order No. 631 issued in Docket No.RM02-7.  As of January 1, 2003, KUrecorded ARO assets in the amount of $8.6 million and liabilities in the amountof $18.5 million.  KU also recorded acumulative effect adjustment in the amount of $9.9 million to reflect theaccumulated depreciation and accretion of ARO assets at the transition date lessamounts previously accrued under regulatory depreciation.  KU recorded offsetting regulatory assets of$9.9 million, pursuant to regulatory treatment prescribed under SFAS No.71.  Also pursuant to SFAS No. 71, KUrecorded regulatory liabilities in the amount of $0.9 million offsettingremoval costs previously accrued under regulatory accounting in excess ofamounts allowed under SFAS No. 143.

 

Had SFAS No. 143 been in effect for the 2002 reporting period, KU wouldhave established asset retirement

 

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obligations as described in the following table:

 
| **(in thousands)**             | ** ** | ** ** | ** ** |
|--------------------------------|------------|------------|------------|
| Provision at January 1, 2002   |       | $          | 17,331     |   |
| Accretion expense              |       | 1,146      |       |
| Provision at December 31, 2002 |       | $          | 18,477     |   |

 

As of December 31, 2004, KU recorded ARO assets, net of accumulateddepreciation, of $6.7 million and liabilities of $21 million.  As of December 31, 2003, KU recorded AROassets, net of accumulated depreciation, of $6.9 million and liabilities of$19.7 million.  KU recorded offsettingregulatory assets of $12.8 million and $11.3 million and regulatory liabilitiesof $1.4 million and $1.2 million as of December 31, 2004 and 2003,respectively.

 

For the year ended December 31, 2004, KU recorded ARO accretionexpense of $1.3 million, ARO depreciation expense of $0.2 million and anoffsetting regulatory credit in the income statement of $1.5 million, pursuantto regulatory treatment prescribed under SFAS No. 71. For the year endedDecember 31, 2003, KU recorded ARO accretion expense of $1.2 million, AROdepreciation expense of $0.2 million and an offsetting regulatory credit in theincome statement of $1.4 million.  SFASNo. 143 has no impact on the results of operations of KU.

 

KU AROs are primarily related to final retirement of assets associatedwith generating units.  For assetsassociated with AROs, the removal cost accrued through depreciation underregulatory accounting is established as a regulatory asset or liabilitypursuant to regulatory treatment prescribed under SFAS No. 71.  For the years ended December 31, 2004and 2003, KU recorded $0.3 million for both periods, in depreciation expenserelated to the cost of removal of ARO related assets.  An offsetting regulatory liability wasestablished pursuant to regulatory treatment prescribed under SFAS No. 71.

 

KU also continues to include a cost of removal component in depreciationfor assets that do not have a legal ARO. As of December 31, 2004 and 2003, KUhas segregated this cost of removal, embedded in accumulated depreciation, of$266.8 million and $256.7 million, respectively, in accordance with FERC OrderNo. 631*.*  For reporting purposes in its ConsolidatedBalance Sheets, KU has presented this cost of removal as a regulatory liabilitypursuant to SFAS No. 71.

 

KU transmission and distribution lines largely operate under perpetualproperty easement agreements which do not generally require restoration uponremoval of the property.  Therefore,under SFAS No. 143, no material asset retirement obligations are recorded fortransmission and distribution assets.

 

EITF No. 02-03

 

KU adopted EITF No. 98-10**effectiveJanuary 1, 1999.  This pronouncementrequired that energy trading contracts be marked to market on the balancesheet, with the gains and losses shown net in the income statement.  Effective January 1, 2003, KU adopted EITFNo. 02-03.  EITF No. 02-03 establishedthe following:

 

•                  Rescinded EITFNo. 98-10,

•                  Contracts thatdo not meet the definition of a derivative under SFAS No. 133 should not bemarked to fair market value, and

•                  Revenues shouldbe shown in the income statement net of costs associated with tradingactivities, whether or not the trades are physically settled.

 

With the rescission of EITF No. 98-10, energy trading contracts that donot also meet the definition of a

 

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derivative under SFAS No. 133 must be accounted for as executorycontracts.  Contracts previously recordedat fair value under EITF No. 98-10 that are not also derivatives under SFAS No.133 must be restated to historical cost through a cumulative effectadjustment.  The rescission of thisstandard had no impact on financial position or results of operations of KUsince all forward and option contracts marked to market under EITF No. 98-10were also within the scope of SFAS No. 133.

 

As a result of EITF No. 02-03, KU has nettedthe power purchased expense for trading activities against electric operatingrevenue to reflect this accounting change. KU applied this guidance to 2002 balances as shown below.  The reclassifications had no impact on previouslyreported net income or common equity.

 
| **(in thousands)**                                        | ** ** | ** ** | ** ** |
|-----------------------------------------------------------|------------|------------|------------|
| Gross electric operating revenues as  previously reported |       | $          | 888,219    |   |
| Less costs reclassified from power  purchased             |       | 26,555     |       |
| Net electric operating revenues                           |       | $          | 861,664    |   |
|                                                      |       |       |       |
| Gross power purchased as previously  reported             |       | $          | 157,955    |   |
| Less costs reclassified to revenues                       |       | 26,555     |       |
| Net power purchased                                       |       | $          | 131,400    |   |
|                                                           |            |            |            |  |  |

 

SFAS No. 150

 

InMay 2003, the Financial Accounting Standards Board issued SFAS No. 150, whichwas effective immediately for financial instruments entered into or modifiedafter May 31, 2003, and otherwise was effective for interim reporting periodsbeginning after June 15, 2003, except for certain instruments and certain entitieswhich have been deferred by the FASB. Such deferrals do not affect KU. KU has no financial instruments that fall within the scope of SFAS No.150.

 

FIN 46

 

In January 2003, the Financial Accounting Standards Board issued FIN46.  FIN 46 requires certain variableinterest entities to be consolidated by the primary beneficiary of the entityif the equity investors in the entity do not have the characteristics of acontrolling financial interest or do not have sufficient equity at risk for theentity to finance its activities without additional subordinated financialsupport from other parties.  FIN 46 waseffective immediately for all new variable interest entities created oracquired after January 31, 2003.  Forvariable interest entities created or acquired prior to February 1, 2003, theprovisions of FIN 46 must have been applied for the first interim or annualperiod beginning after June 15, 2003.

 

In December 2003, FIN 46 was revised, delaying the effective dates forcertain entities created before February 1, 2003, and making other amendmentsto clarify application of the guidance. For potential variable interest entities other than special purposeentities, FIN 46R was required to be applied no later than the end of the firstfiscal year or interim reporting period ending after March 15, 2004.  The original guidance under FIN 46 wasapplicable, however, for all special purpose entities created prior to February1, 2003, at the end of the first interim or annual reporting period endingafter December 15, 2003.  FIN 46R may beapplied prospectively with a cumulative-effect adjustment as of the date it isfirst applied, or by restating previously issued financial statements with acumulative-effect adjustment as of the beginning of the first year restated.  FIN 46R also requires certain disclosures ofan entity’s relationship with variable interest entities.  The adoption of FIN 46 and FIN 46R has noimpact on the financial position or results of operations for KU.

 

Although KU holds investment interests in OVEC and EEI, it is not theprimary beneficiary of OVEC or EEI, and, therefore, neither are consolidatedinto the financial statements of KU.

 

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KU and 11 other electric utilities are participating owners of OVEC,located in Piketon, Ohio.  OVEC owns andoperates two power plants that burn coal to generate electricity, Kyger CreekStation in Ohio and Clifty Creek Station in Indiana.  KU’s share is 2.5%, representingapproximately 55 Mw of generation capacity.

 

KU’s original investment in OVEC was made in 1952.  KU’s investment in OVEC is the equivalent of2.5% of OVEC’s common stock and is accounted for under the cost method ofaccounting.  As of December 31, 2004, KU’sinvestment in OVEC totaled $0.3 million. KU’s maximum exposure to loss as aresult of the involvement with OVEC is limited to the value of theinvestment.  In the event of theinability of OVEC to fulfill its power provision requirements, KU wouldsubstitute such power supply with either owned generation or market purchasesand would generally recover associated incremental costs through regulatoryrate mechanisms.  See Note 11 for furtherdiscussion of developments regarding KU’s ownership interests and power purchaserights.

 

KU owns 20% of the common stock of EEI, which owns and operates a1,000-Mw generating station in southern Illinois.  KU is entitled to take 20% of the availablecapacity of the station.  Purchases fromEEI are made under a contractual formula which has resulted in costs which wereand are expected to be comparable to the cost of other power generated byKU.  This contract governing thepurchases from EEI will terminate on December 31, 2005.  Such power equated to approximately 10% of KU’snet generation system output in 2004.

 

KU’s original investment in EEI was made in 1953.  KU’s investment in EEI is accounted for underthe equity method of accounting and, as of December 31, 2004, totaled $13.4million.  KU’s direct exposure to loss asa result of its involvement with EEI is generally limited to the value of itsinvestment.  In the event of theinability of EEI to fulfill its power provision requirements, KU wouldsubstitute such power supply with either owned generation or market purchasesand would generally recover associated incremental costs through regulatoryrate mechanisms.

 

FSP 106-2

 

In May 2004,the FASB finalized FSP 106-2 with guidance on accounting for subsidies providedunder the Medicare Act which became law in December 2003.  FSP 106-2 is effective for the first interimor annual period beginning after June 15, 2004. FSP 106-2 does not have a material impact on KU.

 

FSP 109-1

 

In December2004, the FASB finalized FSP 109-1*,*which**requires the tax deduction on qualifiedproduction activities to be treated as a special deduction in accordance withFAS 109.  FSP 109-1 became effectiveDecember 21, 2004, and does not have a material impact on KU.

 

# **Note 2 – Mergers and Acquisitions**

# ** **

On July 1,2002, E.ON completed its acquisition of Powergen, including LG&E Energy,for approximately £5.1 billion ($7.3 billion). As a result of the acquisition, LG&E Energy became a wholly ownedsubsidiary of E.ON and, as a result, KU also became an indirect subsidiary ofE.ON.  KU has continued its separateidentity and serves customers in Kentucky, Virginia and Tennessee under itsexisting names.  The preferred stock anddebt securities of KU were not affected by this transaction and the utilitiescontinue to file SEC reports.  Followingthe acquisition, E.ON became a registered holding company under PUHCA.  KU, as a subsidiary of a registered holdingcompany, is subject to additional regulations under PUHCA.  In March 2003, E.ON, Powergen and LG&E Energycompleted an administrative reorganization to move the LG&E Energy groupfrom an indirect Powergen subsidiary to an indirect E.ON subsidiary.  In early 2004, LG&E Energy commenceddirect reporting arrangements to E.ON.

 

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LG&E Energy and KU Energy merged on May 4, 1998, with LG&E Energyas the surviving corporation. Management accounted for the merger as a poolingof interests and as a tax-free reorganization under the Internal RevenueCode.  Following these acquisitions, KUhas continued to maintain its separate identity and serve customers under itspresent name.

 

**Note 3 - Rates and Regulatory Matters**

 

Electric Rate Case

 

In December 2003, KU filed an application with the Kentucky Commissionrequesting an adjustment in KU’s electric rates.  KU asked for a general adjustment in electricrates based on a twelve month test year ended September 30, 2003.  The revenue increase requested was $58.3million.

 

On June 30, 2004, theKentucky Commission issued an order approving an increase in the base electricrates of KU.  The Kentucky Commission’sorder largely accepted proposed settlement agreements filed in May 2004 by KUand a majority of the parties to the rate case proceedings.   The rate increase took effect on July 1,2004.

 

In theKentucky Commission’s order, KU was granted an increase in annual base electricrates of approximately $46.1 million (6.8%). Other provisions of the order include decisions on certain depreciation,ECR and VDT amounts or mechanisms and a termination of the ESM with respect toall periods after 2003.  The order alsoprovided for a recovery before March 31, 2005, by KU of previously requestedamounts relating to the ESM during 2003.

 

DuringJuly 2004, the AG served subpoenas on KU, as well as on the Kentucky Commissionand its staff, requesting information regarding allegedly impropercommunications between KU and the Kentucky Commission, particularly during theperiod covered by the rate case. The Kentucky Commission has procedurallyreopened the rate case for the limited purpose of taking evidence, if any, asto the communication issues. Subsequently, the AG filed pleadings with theKentucky Commission requesting rehearing of the rate case on certaincomputational components of the increased rates, including income tax, cost ofremoval and depreciation amounts. In August 2004, the Kentucky Commissiondenied the AG’s rehearing request on the cost of removal and depreciationissues, with the effect that the rate increase order is final as to thesematters, subject to the parties’ rights to judicial appeals. The KentuckyCommission further agreed to hold in abeyance further proceedings in the ratecase, including the AG’s concerns about alleged improper communications, untilthe AG could file with the Kentucky Commission an investigative reportregarding the latter issue. In addition, the Kentucky Commission granted arehearing on the income tax component once the abeyance discussed above islifted.

 

In Septemberand October 2004, various proceedings were held in circuit courts in Franklinand Jefferson Counties, Kentucky regarding the scope and timing of documentproduction or other information required or agreed to be produced under the AG’ssubpoenas and matters were consolidated into the Franklin County court.  In October 2004, the AG filed a motion withthe Kentucky Commission requesting that the previously granted rate increase beset aside, that KU resubmit any applications for rate increases and thatrelevant Kentucky Commission personnel be recused from participation in ratecase proceedings.  In November 2004, theFranklin County, Kentucky court denied an AG request for sanctions on KUrelating to production matters and narrowed the AG’s permitted scope ofdiscovery.   In January 2005, the AGconducted interviews of certain Company individuals.

 

In January 2005,the AG submitted its report to the Franklin County, Kentucky Circuit Court inconfidence.  Concurrently the AG filed amotion summarizing the report as containing evidence of improper communicationsand record-keeping errors by KU in its conduct of activities before the KentuckyCommission or other

 

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stategovernmental entities and requesting release of the report to suchagencies.  During February 2005 the courtruled that the report be forwarded to the Kentucky Commission under continuedconfidential treatment to allow it to consider the report, including its impact,if any, on completing its investigation and any remaining steps in the ratecase, including ending the current abeyance. To date, KU has neither seen nor requested copies of the report or itscontents.

 

KU believes no improprieties have occurred in its communications withthe Kentucky Commission and is cooperating with the proceedings before the AGand the Kentucky Commission.

 

KU is currently unable to determine the ultimate impact, if any, of, orany possible future actions of the AG or the Kentucky Commission arising outof, the AG’s report and investigation, including whether there will be furtheractions to appeal, review or otherwise challenge the granted increase in baserates.

 

Regulatory Assets and Liabilities

 

The following regulatory assets and liabilities were included in KU’sbalance sheets as of December 31:

 
| **(in thousands)**                            | ** ** | **2004** | ** ** | **2003** | ** ** |
|-----------------------------------------------|------------|----------|------------|----------|------------|
|                                          |       |     |       |     |       |
| VDT costs                                     |       | $        | 14,697     |     | $          | 26,451 |   |
| Unamortized loss on bonds                     |       | 11,370   |       | 10,511   |       |
| ARO                                           |       | 12,844   |       | 11,322   |       |
| Merger surcredit                              |       | 3,745    |       | 4,815    |       |
| ESM                                           |       | 3,115    |       | 12,382   |       |
| Rate case expenses                            |       | 1,136    |       | 1,041    |       |
| FAC                                           |       | 9,375    |       | 4,298    |       |
| Deferred storm costs                          |       | 3,562    |       | —   |       |
| Post retirement and pension                   |       | 1,181    |       | 1,006    |       |
| Management audit                              |       | 410      |       | 492      |       |
| Total regulatory assets                       |       | $        | 61,435     |     | $          | 72,318 |   |
|                                          |       |     |       |     |       |
| Accumulated cost of removal of utility  plant |       | $        | 266,805    |     | $          | 256,744 |   |
| Deferred income taxes - net                   |       | 19,277   |       | 24,058   |       |
| ECR                                           |       | 1,176    |       | 9,189    |       |
| DSM                                           |       | 1,640    |       | 1,563    |       |
| ARO                                           |       | 1,415    |       | 1,162    |       |
| FAC                                           |       | 119      |       | 1,000    |       |
| Spare parts                                   |       | 1,091    |       | 1,055    |       |
| Total regulatory liabilities                  |       | $        | 291,523    |     | $          | 294,771 |   |
|                                               |            |          |            |          |            |  |  |  |  |  |

 

KU currently earns a return on all regulatory assets except for ESM,DSM and FAC, all of which are separate recovery mechanisms with recovery withintwelve months.  Additionally, no currentreturn is earned on the ARO regulatory asset. This regulatory asset will be offset against the associated regulatoryliability, ARO asset, and ARO liability at the time the underlying asset isretired.  See Note 1, Summary ofSignificant Accounting Policies.

 

**VDT Costs - Kentucky Commission Settlement Order. **During the firstquarter of 2001, KU recorded a $64 million charge for a workforce reductionprogram.  Primary components of thecharge were separation benefits, enhanced early retirement benefits, andhealthcare benefits.  The result of thisworkforce reduction was the elimination of approximately 300 positions,accomplished primarily through a voluntary enhanced severance program.

 

In June 2001, KU filed an application (VDT case) with the KentuckyCommission to create a regulatory asset

 

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relating to these first quarter 2001 charges.  The application requested permission to amortizethese costs over a four-year period.  TheKentucky Commission also opened a case to review a new depreciation study andresulting depreciation rates implemented in 2001.

 

In December 2001, the Kentucky Commission approved a settlement in theVDT case as well as other cases involving the depreciation rates and ESM. Theorder approving the settlement allowed KU to set up a regulatory asset of $54million for the workforce reduction costs and begin amortizing these costs overa five-year period starting in April 2001. The first quarter 2001 charge of $64million represented all employees who had accepted a voluntary enhancedseverance program.  Some employeesrescinded their participation in the voluntary enhanced severance program and,along with the non-recurring charge of $6.9 million for FERC and Virginiajurisdictions, thereby decreasing the original charge to the regulatory assetfrom $64 million to $54 million. The settlement reduces revenues approximately$11 million through a surcredit on bills to ratepayers over the same five-yearperiod.  The surcredit represents netsavings stipulated by KU.

 

As mentioned, the current five-year VDT amortization period isscheduled to expire in March 2006.  Aspart of the settlement agreements in the electric and gas rate cases, KU shallfile with the Kentucky Commission a plan for the future ratemaking treatment ofthe VDT surcredits and costs six months prior to the March 2006expiration.  The surcredit shall remainin effect following the expiration of the fifth year until the Commissionenters an order on the future disposition of VDT-related issues.

 

**ARO.**  AtDecember 31, 2004 and 2003, KU had recorded approximately $12.8 million and$11.3 million in regulatory assets and approximately $1.4 million and $1.2 millionin regulatory liabilities, respectively, related to SFAS No. 143.

 

**Merger Surcredit**.  As part of the LG&E Energy merger with KUEnergy in 1998, KU estimated non-fuel savings over a ten-year period followingthe merger.  Costs to achieve thesesavings 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 periodpursuant to regulatory orders.  Primarycomponents of the merger costs were separation benefits, relocation costs, andtransaction fees, the majority of which were paid by December 31, 1998.  KU expensed the remaining costs associatedwith the merger ($21.8 million) in the second quarter of 1998.

 

In approving the merger, the Kentucky Commission adopted KU’s proposalto reduce its retail customers’ bills based on one-half of the estimatedmerger-related savings, net of deferred and amortized amounts, over a five-yearperiod.  The surcredit mechanism providesthat 50% of the net non-fuel cost savings estimated to be achieved from themerger be provided to ratepayers through a monthly bill credit, and 50% beretained by KU and LG&E, over a five-year period.  The surcredit was allocated 53% to KU and 47%to LG&E.  In that same order, theCommission required LG&E and KU, after the end of the five-year period, topresent a plan for sharing with ratepayers the then-projected non-fuel savingsassociated with the merger.  TheCompanies submitted this filing in January 2003, proposing to continue to sharewith ratepayers, on a 50%/50% basis, the estimated fifth-year gross level ofnon-fuel savings associated with the merger. In October 2003, the Kentucky Commission issued an order approving asettlement agreement reached with the parties in the case.  KU’s merger surcredit will remain in placefor another five-year term beginning July 1, 2003 and the merger savings willcontinue to be shared 50% with ratepayers and 50% with shareholders.

 

**ESM.** Prior to 2004, KU’s Kentucky retail electric rates were subject to anESM.  The ESM, initially in place forthree years beginning in 2000, set an upper and lower point for rate of returnon equity, whereby if KU’s rate of return for the calendar year fell within therange of 10.5% to 12.5%, no action was necessary.  If earnings were above the upper limit, theexcess earnings were shared 40% with ratepayers and 60% with shareholders; ifearnings were below the lower limit, the earnings deficiency was recovered 40%from ratepayers and 60% from shareholders. By order of the Kentucky Commission, rate changes prompted by the ESMfiling went into effect in April of

 

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each year subject to a balancing adjustment in successive periods.  There is no ESM for Virginia retail electricrates.

 

In November 2002, KU filed a revised ESM tariff which proposedcontinuance of the existing ESM through December 2005.  In addition, the Kentucky Commission initiated a focused management audit to review the ESMplan and reassess its reasonableness.  KUand interested parties had the opportunity to provide recommendations formodification and continuance of the ESM or other forms of alternative orincentive regulation.

 

KU filed itsfinal 2003 ESM calculations with the Kentucky Commission on March 1, 2004, andapplied for recovery of $16.2 million. Based upon estimates, KU previouslyaccrued $9.3 million for the 2003 ESM as of December 31, 2003.

 

On June 30,2004, the Kentucky Commission issued an order largely accepting proposedsettlement agreements by KU and all intervenors regarding the ESM.  Under the ESM settlements, KU will continueto collect approximately $16.2 million of previously requested 2003 ESM revenueamounts through March 2005.  As part ofthe settlement, the parties agreed to a termination of the ESM mechanismrelating to all periods after 2003.

 

As a result ofthe settlement, KU accrued an additional $6.9 million in June 2004, related to2003 ESM revenue.

 

**FAC.** KU’s retail electric rates contain a FAC,whereby increases or decreases in the cost of fuel for electric generation arereflected in the rates charged to retail electric customers.  In January 2003, the Kentucky Commission reviewed KU’s FAC for the sixmonth period ended October 31, 2001. The Kentucky Commission ordered KU toreduce its fuel costs for purposes of calculating its FAC by $0.7 million. Atissue was the purchase of approximately 102,000 tons of coal from WesternKentucky Energy Corporation, a non-regulated affiliate, for use at KU’s Ghentfacility. The Kentucky Commission further ordered that an independent audit beconducted to examine operational and management aspects of both KU’s andLG&E’s fuel procurement functions.  Afinal report was issued in February 2004. The report’s recommendations related to documentation and processimprovements.  Management Audit ActionPlans were agreed upon by KU and the Kentucky Commission Staff in the secondquarter of 2004.  KU filed its firstAudit Progress Report with the Kentucky Commission Staff in November 2004.  A second Audit Progress Report is due in May2005.

 

In December 2004, the Kentucky Commission initiated a two-year reviewof KU’s past operations of the fuel clause and transfer of fuel costs from thefuel adjustment clause to base rates.   Apublic hearing on the matter was held on March 17, 2005.  An order by the Kentucky Commission isexpected in April 2005.  KU is seeking toincrease the fuel component of base rates. KU does not anticipate any issues will arise during the regulatoryproceeding.

 

In February 2005, KU filed with the Virginia Commission an applicationseeking approval of an increase in its fuel cost factor to reflect higher fuelcosts incurred. KU anticipates implementing the increased fuel cost factor withApril 2005 billings.

 

The Kentucky Commission requires public hearings at six-month intervalsto examine past fuel adjustments, and at two-year intervals to review pastoperations of the fuel clause and transfer of the then current fuel adjustmentcharge or credit to the base charges.  KUalso employs a FAC mechanism for Virginia customers that uses an average fuelcost factor based primarily on projected fuel costs.  The fuel cost factor may be adjusted annuallyfor over or under collections of fuel costs from the previous year.  No other significant issues have beenidentified as a result of these reviews.

 

# **DSM.** In May 2001, the Kentucky Commission approveda plan that would expand LG&E’sDSM programs into the service territory served byKU.  The plan included a rate mechanismthat provided for concurrent

 

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# **recoveryof DSM costs, provided an incentive for implementing DSM programs, andrecovered revenues from lost sales associated with the DSM programs based onprogram plan engineering estimates and post-implementation evaluation.**

# ** **

**Deferred Storm Costs. **Basedon an order from the Kentucky Commission in September 2004, KU reclassifiedfrom maintenance expense to a regulatory asset, $4.0 million related to costsnot reimbursed from the 2003 ice storm. These costs will be amortized through June 2009.  KU earns a return of these amortized costs,which are included in KU’s jurisdictional operating expenses.

 

**Accumulated Cost of Removal.**  As of December 31, 2004 and 2003, KU hassegregated the cost of removal, embedded in accumulated depreciation, of $266.8million and $256.7 million, respectively, in accordance with FERC Order No. 631*.* For reporting purposes in the Consolidated Balance Sheet, KU haspresented this cost of removal as a regulatory liability pursuant to SFAS No.71.

 

**ECR.**  InAugust 2002, KU filed an application with the Kentucky Commission to amend itscompliance plan to allow recovery of the cost of a new and additionalenvironmental compliance facilities.  Theestimated capital cost of the additional facilities is $17.3 million.  A final order was issued in February 2003.The final order approved recovery of the new environmental compliance facilitytotaling $17.3 million.  Cost recoverythrough the environmental surcharge of the approved project commenced withbills rendered in April 2003.

 

In March 2003, the Kentucky Commissioninitiated a series of six-month and two-year reviews of the operation of KU’sEnvironmental Surcharge.  A final orderwas issued on October 17, 2003 resolving all outstanding issues related toover-recovery from customers and under-recovery of allowed O&Mexpense.  The Commission found that KUhad over-collected a net $6.0 million from customers and ordered the refund tooccur through adjustments to the calculation of the monthly surcharge billingfactor over the subsequent 12 month period. The Commission further ordered KU to roll $17.9 million of environmentalassets into base rates and make corresponding adjustments in the monthlyenvironmental surcharge filings to reflect that portion of environmental ratebase now included in base rates going forward. The rates of return for KU’s 1994 and post-1994 plans were reset to1.24% and 12.60%, respectively.

 

In June 2004, the Kentucky Commission issuedan order approving a settlement agreement that, among other things, revised therate of return for KU’s post-1994 plan to 11.19%, with an 11% return on commonequity.  The order also approved theelimination of KU’s 1994 Plan for its ECR billing mechanism, with all remainingcosts associated with that plan to be included in their entirety in base rates.

 

In December 2004, KU filed an applicationwith the Kentucky Commission for approval of a CCN to construct new SO2control technology (FGDs) at the Ghent and Brown stations, and to amend itscompliance plan to allow recovery of new and additional environmentalcompliance facilities.  The estimatedcapital cost of the additional facilities is $702.5 million, of which $658.9million is for the FGDs.  A final orderin the case is expected in June 2005.

 

Other Regulatory Matters

 

**MISO.** KU is a founding member of the MISO. Membership was obtained in 1998 in response to and consistent withfederal policy initiatives.  In February2002, KU turned over operational control of its high voltage transmissionfacilities (100kV and above) to the MISO. The MISO currently controls over 100,000 miles of transmission over 1.1million square miles located in the northern Midwest between Manitoba, Canadaand Kentucky.  In September 2002, FERCgranted a 12.88% ROE on transmission facilities for KU and the rest of the MISOowners.  On February 18, 2005, the UnitedStates Court of Appeals for the District of Columbia Circuit ruled that FERCdid not provide proper notice that it would consider an incentive adder of 50basis

 

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points, but affirmed the September 2002 FERC order in all otherrespects.  Effective ROE, retroactive toFebruary 1, 2002, is 12.38% for KU and the original MISO owners.

 

In October 2001, the FERC issued an order requiring that the bundledretail load and grandfathered wholesale load of each member transmission ownerbe included in the current calculation of the MISO’s “cost-adder,” the Schedule10 charges designed to recover the MISO’s costs of operation, includingstart-up capital (debt) costs.  KU, alongwith several other transmission owners, opposed the FERC’s ruling on thismatter. The opposition was rejected by the FERC in 2002.   Later that year, the MISO’s transmissionowners, appealed the FERC’s decision to the United States Court of Appeals forthe District of Columbia Circuit.  Inresponse, in November 2002, the FERC requested that the Court issue a partialremand of its challenged orders to allow the FERC to revisit certain issues,and requested that the case be held in abeyance pending the agency’s resolutionof such issues.  The Court granted theFERC’s petition in December 2002.   InFebruary 2003, FERC issued an order reaffirming its position concerning thecalculation of the Schedule 10 charges and in July 2003 denied a rehearing. KU,along with several other transmission owners, again petitioned the DistrictCourt of Columbia Circuit for review. In July 2004, the court affirmed the FERCruling.

 

In August 2004, the MISO filed its FERC-required proposed TEMT.  In September and October 2004, manyMISO-related parties (including KU) filed proposals with the FERC regardingpending MISO-filed changes to transmission pricing principles, including theTEMT and elimination of RTORs. Additional filings of the companies before FERCin September 2004 sought to address issues relating to the treatment of certainGFA's should TEMT become effective. The utility proposals generally seek toappropriately delay the RTORs and TEMT effective dates based upon errors inadministrative or procedural processes used by FERC or to appropriately limitpotential reductions in transmission revenues received by the utilities shouldthe RTORs, TEMT or GFA structures be implemented.  At present, existing FERC ordersconditionally approve elimination of RTORs and implementation of general TEMTrates in the MISO by spring 2005.  Atthis time, KU cannot predict the outcome or effects of the various FERCproceedings described above, including whether such will have a material impacton the financial condition or results of operations of the companies. Financialconsequences (changes in transmission revenues and costs) associated with theupcoming transmission market tariff changes are subject to varying assumptions andcalculations and are therefore difficult to estimate. Changes in revenues andcosts related to broader shifts in energy market practices and economics arenot currently estimable.  Should KU beordered to exit MISO, current MISO rules may also impose an exit fee.  KU is not able to predict the estimatedoutcome or economic impact of any of the MISO-related matters.  While KU believes legal and regulatoryprecedent should permit most or many of the MISO-related costs to be recoveredin their rates charged to customers, they can give no assurance that state orfederal regulators will ultimately agree with such position with respect to allcosts, components or timing of recovery.

 

The MISO plans to implement a Day ahead and Real-time market, includinga congestion management system in April 2005. This system will be similar tothe LMP system currently used by the PJM RTO and contemplated in FERC’s SMDNOPR, currently being discussed.  TheMISO filed with FERC a mechanism for recovery of costs for the congestion managementsystem.  They proposed the addition oftwo new Schedules, 16 and 17.  Schedule16 is the MISO’s cost recovery mechanism for the Financial Transmission RightsAdministrative Service it will provide. Schedule 17 is the MISO’s mechanism for recovering costs it will incurfor providing Energy Marketing Support Administrative Service.  The MISO transmission owners, including KU,have objected to the allocation of costs among market participants and retailnative load. FERC ruled in 2004 in favor of the MISO.

 

The Kentucky Commission opened an investigation into KU’s membership inthe MISO in July 2003. The Kentucky Commission directed KU to file testimonyaddressing the costs and benefits of the MISO membership both currently andover the next five years and other legal issues surrounding continuedmembership.  KU engaged an independentthird-party to conduct a cost benefit analysis on this issue.  The information was filed with the KentuckyCommission in September 2003.  Theanalysis and testimony supported the exit from the MISO, under certainconditions.  The MISO filed its owntestimony and cost benefit analysis in December 2003.  A final Kentucky Commission order was expectedin the second quarter of 2004; that ruling has since been delayed until summer2005 due to the Kentucky Commission’s request for additional testimony on theMISO’s Market Tariff filing at FERC.

 

**Kentucky Commission Administrative Case forSystem Adequacy.** In June 2001, Kentucky’s Governor issued Executive Order 2001-771, whichdirected the Kentucky Commission to review and study issues relating to theneed for and development of new electric generating capacity in Kentucky.  In response to that Executive Order, in July2001 the Kentucky Commission opened Administrative Case No. 387 to review theadequacy of Kentucky’s generation capacity and transmission system.  Specifically, the items reviewed were theappropriate level of reliance on purchased power, the appropriate reservemargins to meet existing and future electric demand, the impact of spikes innatural gas prices on electric utility planning strategies, and the adequacy ofKentucky’s electric transmission facilities. In December 2001, the Kentucky Commission issued an order in which itnoted that KU is responsibly addressing the long-term supply needs of nativeload customers and that current reserve margins are appropriate.  However, due to the rapid pace of change inthe industry, the order also requires KU to provide an annual assessment ofsupply resources, future demand, reserve margin, and the need for newresources.

 

Regarding the transmission system, the Kentucky Commission concludedthat the transmission system within Kentucky can reliably serve native load anda significant portion of the proposed new unregulated power plants.

 

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However, it will not be able to handle the volume of transactionsenvisioned by FERC without future upgrades, the costs of which should be borneby those for whom the upgrades are required.

 

The Kentucky Commission pledged to continue to monitor all relevantissues and advocate Kentucky’s interests at all opportunities.

 

**KentuckyCommission Strategic Blueprint. **InFebruary 2005, Kentucky’s Governor signed an executive order directing theKentucky Commission, in conjunction with the Commerce Cabinet and theEnvironmental and Public Protection Cabinet, to ‘develop a Strategic Blueprintfor the continued use and development of electric energy.’ This StrategicBlueprint will be designed to promote future investment in electricinfrastructure for the Commonwealth of Kentucky, to protect Kentucky’s low-costelectric advantage, to maintain affordable rates for all Kentuckians, and topreserve Kentucky’s commitment to environmental protection.  In March 2005, the Kentucky Commissionestablished Administrative Case No. 2005-00090 to collect information from alljurisdictional utilities in Kentucky, including KU, pertaining to Kentuckyelectric generation, transmission and distribution systems.  The Kentucky Commission must provide itsStrategic Blueprint to the Governor in early August 2005.  KU must respond to the Kentucky Commission’sfirst set of data requests by the end of March 2005.

 

**FERC SMD NOPR. **InJuly 2002, the FERC issued a NOPR in Docket No. RM01-12-000 which wouldsubstantially alter the regulations governing the nation’s wholesaleelectricity markets by establishing a common set of rules, defined as SMD. TheSMD NOPR would require each public utility that owns, operates, or controlsinterstate transmission facilities to become an ITP, belong to an RTO that isan ITP, or contract with an ITP for operation of its transmission assets. Itwould also establish a standardized congestion management system, real-time andday-ahead energy markets, and a single transmission service for network andpoint-to-point transmission customers. Review of the proposed rulemaking isunderway and no timeframe has been established by the FERC for adoption of afinal rule.  While it is expected thatthe SMD final rule will affect KU revenues and expenses, the specific impact ofthe rulemaking is not known at this time.

 

**Kentucky Commission Administrative Case for Affiliate Transactions.**  In December 1997, the Kentucky Commissionopened Administrative Case No. 369 to consider Kentucky Commission policyregarding cost allocations, affiliate transactions and codes of conductgoverning the relationship between utilities and their non-utility operationsand affiliates.  The Kentucky Commissionintended to address two major areas in the proceedings: the tools andconditions needed to prevent cost shifting and cross-subsidization betweenregulated and non-utility operations; and whether a code of conduct should beestablished to assure that non-utility segments of the holding company are notengaged in practices that could result in unfair competition caused by costshifting from the non-utility affiliate to the utility.  In early 2000, the Kentucky General Assemblyenacted legislation, House Bill 897, which authorized the Kentucky Commissionto require utilities that provide nonregulated activities to keep separateaccounts and allocate costs in accordance with procedures established by theKentucky Commission. In the same bill, the General Assembly set forth provisionsto govern a utility’s activities related to the sharing of information,databases, and resources between its employees or an affiliate involved in themarketing or the provision of nonregulated activities and its employees or anaffiliate involved in the provision of regulated services. The legislationbecame law in July 2000 and KU has been operating pursuant thereto since thattime.  In February 2001, the KentuckyCommission published notice of their intent to promulgate new administrativeregulations under the auspices of this new law. This effort is still on-going.

 

**Note 4 - Financial Instruments**

 

The cost and estimated fair values of KU’s non-trading financialinstruments as of December 31, 2004, and 2003 follow:

 

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| ** **                                 | ** ** | **2004**   | ** ** | **2003**  | ** ** |
|--------------------------------------------|------------|------------|------------|-----------|------------|
| ** **                                 | ** ** | ** ** | ** ** | **Fair**  | ** ** | ** ** | ** ** | **Fair** | ** ** |
| **(in thousands)**                         | ** ** | **Cost**   | ** ** | **Value** | ** ** | **Cost** | ** ** | **Value** | ** ** |
|                                       |       |       |       |      |       |   |   |   |   |
| Long-term debt (including current portion) |       | $          | 385,030    |      | $          | 393,484 |   | $ | 389,830 |   | $ | 405,439 |   |
| Long-term debt from affiliate              |       | $          | 333,000    |      | $          | 336,969 |   | $ | 283,000 |   | $ | 288,292 |   |
| Interest-rate swaps - asset                |       | —     |       | $         | 6,102      |   | — |   | $ | 12,223 |   |
|                                            |            |            |            |           |            |  |  |  |  |  |  |  |  |  |  |

 

All of the above valuations reflect prices quoted by exchanges exceptfor the swaps and the intercompany loans. The fair values of the swaps and intercompany loans reflect price quotesfrom dealers or amounts calculated using accepted pricing models.

 

**Interest Rate Swaps.** KU uses interest rate swaps to hedge exposure to market fluctuations incertain of its debt instruments. Pursuant to policy, use of these financial instruments is intended tomitigate risk, earnings and cash flow volatility and is not speculative innature.  Management has designated all ofthe interest rate swaps as hedge instruments. Financial instruments designated as fair value hedges and the underlyinghedged items are periodically marked to market with the resulting net gains andlosses recorded directly into net income. Upon termination of any fair value hedge, the resulting gain or loss isrecorded into net income. Financial instruments designated as cash flow hedgeshave resulting gains and losses recorded within other comprehensive income andstockholders’ equity.  To the extent afinancial instrument designated as a cash flow hedge or the underlying itembeing hedged is prematurely terminated or the hedge becomes ineffective, theresulting gains or losses are reclassified from other comprehensive income tonet income.

 

As of December 31, 2004 and 2003, KU was party to various interest rateswap agreements with aggregate notional amounts of $103 million in 2004 and$153 million 2003.  Under these swapagreements, KU paid variable rates based on either LIBOR or the Bond MarketAssociation’s municipal swap index averaging 3.29% and 1.85%, and receivedfixed rates averaging 7.74% and 7.13% at December 31, 2004 and 2003,respectively. The swap agreements in effect at December 31, 2004 have beendesignated as fair value hedges and mature on dates ranging from 2007 to2025.  The fair value designation wasassigned because the underlying fixed rate debt has a firm futurecommitment.  For 2004 and 2003, theeffect of marking these financial instruments and the underlying debt to marketresulted in immaterial pretax gains (less than $0.1 million) recorded ininterest expense.

 

Interest rate swaps hedge interest rate risk on the underlying debtunder SFAS No. 133, in addition to swaps being marked to market, the item beinghedged must also be marked to market, consequently at December 31, 2004, KU’sdebt reflects a $8.2 million mark-to-market adjustment.

 

# **In February2004, KU terminated the swap it had in place at December 31, 2003 related tothe Series 9 pollution control bonds. The notional amount of the terminated swap was $50 million and KUreceived a payment of $2.0 million as part of the termination.  The swap was terminated because it was nolonger an effective hedge of the underlying bond.**

# ** **

# **Energy Trading & Risk Management Activities.  **KU conducts energy trading and risk management activities to maximizethe value of power sales from physical assets it owns, in addition to thewholesale sale of excess asset capacity. Certain energy trading activities are accounted for on a mark-to-marketbasis in accordance with SFAS No. 133, SFAS No. 138**andSFAS No. 149.  Wholesale sales of excessasset capacity are treated as normal sales under  these pronouncements and are not marked tomarket.  To be eligible for the normalsales exclusion under SFAS No. 133, sales are limited to the forecasted excesscapacity of KU’s generation assets over what is needed to serve KU’s nativeload.  To be eligible for the normalpurchases exclusion under SFAS No. 133

 

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# **purchasesmust be used to serve KU’s native load. Without the normal sales and purchases exclusion these transactionswould be considered derivatives and marked to market under SFAS No. 133.**

# ** **

The rescission of EITF 98-10, effective for fiscal years after December15, 2002, had no impact on KU’s energy trading and risk management reporting asall forward and option contracts marked to market under EITF 98-10 are alsowithin the scope of SFAS No. 133.

 

No changes to valuation techniques for energy tradingand risk management activities occurred during 2004.  Changes in market pricing, interest rate andvolatility assumptions were made during both years.  All contracts outstanding at December 31,2004, have a maturity of less than one year and are valued using pricesactively quoted for proposed or executed transactions or quoted by brokers.

 

KU maintains policies intended to minimize credit risk and revaluescredit exposures daily to monitor compliance with those policies.  At December 31, 2004, 100% of the trading andrisk management commitments were with counterparties rated BBB-/Baa3 equivalentor better.

 

KU hedges the price volatility of its forecasted peak electricoff-system sales with the sales of market-traded electric forward contracts forperiods less than one year.  Theseelectric forward sales have been designated as cash flow hedges and are notspeculative in nature.  Gains or losseson these instruments, to the extent that the hedging relationship has beeneffective, are deferred in other comprehensive income.  Gains and losses resulting fromineffectiveness are shown in KU’s Consolidated Statements of Income in otherincome (expense) – net.  Upon expirationof these instruments, the amount recorded in other comprehensive income isrecorded in earnings. No material pre-tax gains and losses resulted from thesecash flow hedges in 2004, 2003 and 2002. See Note 14, Accumulated OtherComprehensive Income.

 

**Accounts Receivable Securitization.  **On February 6, 2001, KU implemented an accountsreceivable securitization program.  KUterminated the accounts receivable securitization program in January 2004, andin May 2004, KU dissolved its inactive accounts receivablesecuritization-related subsidiary, KU R. The purpose of this program was to enable KU to accelerate the receiptof cash from the collection of retail accounts receivable, thereby reducingdependence upon more costly sources of working capital. The securitizationprogram allowed for a percentage of eligible receivables to be sold.  Eligible receivables were generally allreceivables associated with retail sales that had standard terms and were notpast due.  KU was able to terminate thisprogram at any time without penalty.

 

As part of the program, KU sold retail accounts receivable to KUR.  Simultaneously, KU R entered into twoseparate three-year accounts receivable securitization facilities with twofinancial institutions and their affiliates whereby KU R could sell, on arevolving basis, an undivided interest in certain of its receivables andreceive up to $50 million from unrelated third-party purchasers.  The effective cost of the receivables programwas comparable to KU’s lowest cost source of capital, and was based on primerated commercial paper. KU retained servicing rights of the sold receivablesthrough two separate servicing agreements with the third-party purchasers.  KU obtained an opinion from independent legalcounsel indicating these transactions qualified as a true sale of receivables.

 

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To determine KU’s retained interest, the proceeds on the sale ofreceivables to the financial institutions were netted against the amount ofeligible receivables sold by KU to KU R. Interest expense, program fees, and facility fees paid to the financialinstitutions and an allowance for doubtful accounts were deducted to arrive atthe future value of retained interest. The future value was discounted using the prime rate plus 25 basispoints, assuming a 45-day receivable life. No material pre-tax gains and losses resulted from the sale of thereceivables in 2004, 2003 and 2002.  KU’snet cash flows from KU R were $(50.1) million, $(0.1) million, and $3.3 millionfor 2004, 2003 and 2002, respectively.

 

The allowance for doubtful accounts associated with the eligiblesecuritized receivables at December 31 was $0.5 million in 2003 and 2002.  This allowance was based on historicalexperience of KU. Each securitization facility contained a fully funded reservefor uncollectible receivables.

 

**Note 5 - Concentrations of Credit and Other Risk**

 

Credit risk represents the accounting loss that would be recognized atthe reporting date if counterparties failed to perform as contracted.  Concentrations of credit risk (whether on- oroff-balance sheet) relate to groups of customers or counterparties that havesimilar economic or industry characteristics that would cause their ability tomeet contractual obligations to be similarly affected by changes in economic orother conditions.

 

KU’s customer receivables and revenues arisefrom deliveries of electricity to approximately 488,000 customers in over 600communities and adjacent suburban and rural areas in 77 counties in central,southeastern and western Kentucky, to approximately 30,000  customers in five counties in southwesternVirginia and less than ten customers in Tennessee.  For the year ended December 31, 2004, 100% oftotal utility revenue was derived from electric operations.

 

In August 2003, KU and itsemployees represented by IBEW Local 2100 entered into a three-year collectivebargaining agreement. KU and its employees represented by USWA Local 9447-01entered into a three-year collective bargaining agreement effective August 2002and expiring August 2005.  The employeesrepresented by these two bargaining units comprise approximately 17% of KU’s workforce.

 

**Note 6 - Pension Plansand Other Postretirement Benefit Plans**

** **

KU has both funded andunfunded non-contributory defined benefit pension plans and otherpost-retirement benefit plans that together cover substantially all of itsemployees.   The healthcare plans arecontributory with participants’ contributions adjusted annually.

 

KU uses December 31 as the measurement date for itsplans.

 

**Obligations and Funded Status. **The following tableprovides a reconciliation of the changes in the plan’s benefit obligations andfair value of assets over the three-year period ending December 31, 2004, and astatement of the funded status as of December 31, 2004, for KU’s sponsoreddefined benefit:

 
| **(in thousands)**                              | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|-------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
|                                            |       |     |       |     |       |     |       |
| Pension Plans:                                  |       |     |       |     |       |     |       |
| Change in benefit obligation                    |       |     |       |     |       |     |       |
| Benefit obligation at beginning of year         |       | $        | 257,705    |     | $          | 247,727  |       | $ | 244,472 |   |
| Service cost                                    |       | 3,711    |       | 2,962    |       | 2,637    |       |
| Interest cost                                   |       | 15,959   |       | 15,924   |       | 16,598   |       |
| Plan amendment                                  |       | 18       |       | 40       |       | 28       |       |
| Change due to transfers                         |       | 81       |       | (269     | )          | —   |       |
| Benefits paid                                   |       | (19,569  | )          | (22,594  | )          | (23,291  | )          |
| Actuarial (gain) or loss and other              |       | 32,810   |       | 13,915   |       | 7,283    |       |
| Benefit obligation at end of year               |       | $        | 290,715    |     | $          | 257,705  |       | $ | 247,727 |   |
|                                            |       |     |       |     |       |     |       |
| Change in plan assets                           |       |     |       |     |       |     |       |
| Fair value of plan assets at beginning of  year |       | $        | 201,093    |     | $          | 178,534  |       | $ | 216,947 |   |
| Actual return on plan assets                    |       | 24,613   |       | 36,528   |       | (13,767  | )          |
| Employer contributions                          |       | 43,409   |       | 10,231   |       | 15,283   |       |
| Change due to transfers                         |       | 23       |       | (206     | )          | (15,382  | )          |
| Benefits paid                                   |       | (19,569  | )          | (22,594  | )          | (23,291  | )          |
| Administrative expenses                         |       | (1,333   | )          | (1,400   | )          | (1,256   | )          |
| Fair value of plan assets at end of year        |       | $        | 248,236    |     | $          | 201,093  |       | $ | 178,534 |   |
|                                            |       |     |       |     |       |     |       |
| Reconciliation of funded status                 |       |     |       |     |       |     |       |
| Funded status                                   |       | $        | (42,479    | )        | $          | (56,611  | )          | $ | (69,193 | ) |
| Unrecognized actuarial (gain) or loss           |       | 56,216   |       | 27,917   |       | 36,233   |       |
| Unrecognized transition (asset) or  obligation  |       | (266     | )          | (399     | )          | (532     | )          |
| Unrecognized prior service cost                 |       | 8,331    |       | 9,184    |       | 10,106   |       |
| Net amount recognized at end of year            |       | $        | 21,802     |     | $          | (19,909  | )          | $ | (23,386 | ) |
|                                            |       |     |       |     |       |     |       |
| Other Benefits:                                 |       |     |       |     |       |     |       |
| Change in benefit obligation                    |       |     |       |     |       |     |       |
| Benefit obligation at beginning of year         |       | $        | 105,763    |     | $          | 104,602  |       | $ | 83,223 |   |
| Service cost                                    |       | 1,252    |       | 805      |       | 610      |       |
| Interest cost                                   |       | 5,761    |       | 6,313    |       | 6,379    |       |
| Benefits paid net of retiree contributions      |       | (6,132   | )          | (7,329   | )          | (4,640   | )          |
| Actuarial (gain) or loss                        |       | (6,359   | )          | 1,372    |       | 19,030   |       |
| Benefit obligation at end of year               |       | $        | 100,285    |     | $          | 105,763  |       | $ | 104,602 |   |
|                                            |       |     |       |     |       |     |       |
| Change in plan assets                           |       |     |       |     |       |     |       |
| Fair value of plan assets at beginning of  year |       | $        | 5,379      |     | $          | 7,943    |       | $ | 14,330 |   |
| Actual return on plan assets                    |       | 2,499    |       | (775     | )          | (2,698   | )          |
| Employer contributions                          |       | 4,430    |       | 5,506    |       | 1,648    |       |
| Change due to transfers                         |       | (202     | )          | —   |       | —   |       |
| Benefits paid net of retiree contributions      |       | (6,182   | )          | (7,295   | )          | (5,337   | )          |
| Fair value of plan assets at end of year        |       | $        | 5,924      |     | $          | 5,379    |       | $ | 7,943 |   |
|                                            |       |     |       |     |       |     |       |
| Reconciliation of funded status                 |       |     |       |     |       |     |       |
| Funded status                                   |       | $        | (94,361    | )        | $          | (100,383 | )          | $ | (96,659 | ) |
| Unrecognized actuarial (gain) or loss           |       | 14,811   |       | 24,013   |       | 22,667   |       |
| Unrecognized transition (asset) or obligation   |       | 8,967    |       | 10,088   |       | 11,209   |       |
| Unrecognized prior service cost                 |       | 1,428    |       | 2,142    |       | 2,891    |       |
| Net amount recognized at end of year            |       | $        | (69,155    | )        | $          | (64,140  | )          | $ | (59,892 | ) |

 

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## **AmountsRecognized in Statement of Financial Position. **The following tables provide the amounts recognized inthe balance sheet and information for plans with benefit obligations in excessof plan assets as of December 31, 2004, 2003 and 2002:

 
| **(in  thousands)**                                                                                       | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|-----------------------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
|                                                                                                      |       |     |       |     |       |     |       |
| Pension Plans:                                                                                            |       |     |       |     |       |     |       |
| Amounts recognized in the balance sheet  consisted of:                                                    |       |     |       |     |       |     |       |
| Accrued benefit liability                                                                                 |       | $        | (8,759     | )        | $          | (38,960  | )          | $ | (51,035 | ) |
| Intangible asset                                                                                          |       | 8,331    |       | 9,184    |       | 10,106   |       |
| Accumulated other comprehensive income                                                                    |       | 22,230   |       | 9,867    |       | 17,543   |       |
| Net amount recognized at year-end                                                                         |       | $        | 21,802     |     | $          | (19,909  | )          | $ | (23,386 | ) |
|                                                                                                      |       |     |       |     |       |     |       |
| Increase (decrease) in minimum liability  included in other comprehensive income                          |       | $        | 12,363     |     | $          | (7,676   | )          | $ | 17,543 |   |
|                                                                                                      |       |     |       |     |       |     |       |
| Additional year-end information for plans  with accumulated benefit obligations in excess of plan assets: |       |     |       |     |       |     |       |
| Projected benefit obligation                                                                              |       | $        | 290,715    |     | $          | 257,705  |       | $ | 247,727 |   |
| Accumulated benefit obligation                                                                            |       | 256,995  |       | 240,054  |       | 229,569  |       |
| Fair value of plan assets                                                                                 |       | 248,236  |       | 201,093  |       | 178,534  |       |
|                                                                                                      |       |     |       |     |       |     |       |
| Other Benefits:                                                                                           |       |     |       |     |       |     |       |
| Amounts recognized in the balance sheet  consisted of:                                                    |       |     |       |     |       |     |       |
| Accrued benefit liability                                                                                 |       | $        | (69,155    | )        | $          | (64,140  | )          | $ | (59,892 | ) |
|                                                                                                      |       |     |       |     |       |     |       |
| Additional year-end information for plans  with benefit obligations in excess of plan assets:             |       |     |       |     |       |     |       |
| Benefit obligation                                                                                        |       | $        | 100,285    |     | $          | 105,763  |       | $ | 104,602 |   |
| Fair value of plan assets                                                                                 |       | 5,924    |       | 5,379    |       | 7,943    |       |

 

**Components of Net Periodic Benefit Cost. **The following tableprovides the components of net periodic benefit cost for the plans for 2004,2003 and 2002:

 
| **(in  thousands)**                                 | ** ** | **2004**   | ** ** | **2003**   | ** ** | **2002**   | ** ** |
|-----------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| ** **                                          | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Pension Plans:                                      |       |       |       |       |       |       |       |
| Components of net periodic benefit cost             |       |       |       |       |       |       |       |
| Service cost                                        |       | $          | 3,711      |       | $          | 2,962      |       | $ | 2,637 |   |
| Interest cost                                       |       | 15,959     |       | 15,925     |       | 16,598     |       |
| Expected return on plan assets                      |       | (19,543    | )          | (14,888    | )          | (18,406    | )          |
| Amortization of transition (asset) or  obligation   |       | (133       | )          | (133       | )          | (133       | )          |
| Amortization of prior service cost                  |       | 871        |       | 957        |       | 956        |       |
| Amortization of actuarial (gain) or loss            |       | 833        |       | 1,211      |       | 1          |       |
| Net periodic benefit cost                           |       | $          | 1,698      |       | $          | 6,034      |       | $ | 1,653 |   |
|                                                |       |       |       |       |       |       |       |
| Other Benefits:                                     |       |       |       |       |       |       |       |
| Components of net periodic benefit cost             |       |       |       |       |       |       |       |
| Service cost                                        |       | $          | 1,252      |       | $          | 806        |       | $ | 610 |   |
| Interest cost                                       |       | 5,761      |       | 6,313      |       | 6,379      |       |
| Expected return on plan assets                      |       | (396       | )          | (337       | )          | (1,022     | )          |
| Amortization of prior service cost                  |       | 714        |       | 714        |       | 691        |       |
| Amortization of transitional (asset) or  obligation |       | 1,121      |       | 1,121      |       | 1,081      |       |
| Amortization of actuarial (gain) or loss            |       | 993        |       | 1,137      |       | 343        |       |
| Net periodic benefit cost                           |       | $          | 9,445      |       | $          | 9,754      |       | $ | 8,082 |   |

 

The assumptions used in the measurement of KU’spension benefit obligation are shown in the following table:

 
| ** **                                       | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|--------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Weighted-average assumptions as of December  31: |       |     |       |     |       |     |       |
| Discount rate                                    |       | 5.75     | %          | 6.25     | %          | 6.75     | %          |
| Rate of compensation increase                    |       | 4.50     | %          | 3.00     | %          | 3.75     | %          |

 

The assumptions used in the measurement of KU’snet periodic benefit cost are shown in the following table: 

 
| ** **                               | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
|                                     |       |     |       |     |       |     |       |
| Discount rate                            |       | 6.25     | %          | 6.75     | %          | 7.25     | %          |
| Expected long-term return on plan assets |       | 8.50     | %          | 9.00     | %          | 9.50     | %          |
| Rate of compensation increase            |       | 3.50     | %          | 3.75     | %          | 4.25     | %          |

 

To develop the expected long-term rate ofreturn on assets assumption, KU considered the current level of expectedreturns on risk free investments (primarily government bonds), the historicallevel of the risk premium 

 

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associated with the other asset classes inwhich the portfolio is invested and the expectations for future returns of eachasset class.  The expected return foreach asset class was then weighted based on the target asset allocation todevelop the expected long-term rate of return on assets assumption for theportfolio.

 

## **AssumedHealthcare Cost Trend Rates. **Formeasurement purposes, a 12.0% annual increase in the per capita cost of coveredhealthcare benefits was assumed for 2004. The rate was assumed to decrease gradually to 5.0% by 2015 and remain atthat level thereafter.

 

Assumed healthcare cost trend rates have asignificant effect on the amounts reported for the healthcare plans. A 1%change in assumed healthcare cost trend rates would have the following effects:

 
| **(in  thousands)**                                               | ** ** | **1% Decrease** | ** ** | **1% Increase** | ** ** |
|-------------------------------------------------------------------|------------|-----------------|------------|-----------------|------------|
| Effect on total of service and interest  cost components for 2004 |       | $               | (450       | )               | $          | 512 |   |
| Effect on year-end 2004 postretirement  benefit obligations       |       | $               | (6,549     | )               | $          | 7,449 |   |

 

## **ExpectedFuture Benefit Payments. **Thefollowing list provides the amount of expected future benefit payments, whichreflect expected future service, as appropriate:

 
| **(in thousands)** | ** ** | **Pension  Plans** | ** ** | **Other  Benefits** | ** ** |
|--------------------|------------|--------------------|------------|---------------------|------------|
| 2005               |       | $                  | 20,005     |                | $          | 7,284 |   |
| 2006               |       | $                  | 19,472     |                | $          | 7,234 |   |
| 2007               |       | $                  | 18,897     |                | $          | 7,614 |   |
| 2008               |       | $                  | 18,270     |                | $          | 7,870 |   |
| 2009               |       | $                  | 17,667     |                | $          | 8,195 |   |
| 2010-2014          |       | $                  | 83,008     |                | $          | 45,059 |   |

##  

## **PlanAssets. **The followingtable shows KU’s weighted-average asset allocation by asset category atDecember 31:

 
| ** **        | ** ** | **Target Range** | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|-------------------|------------|------------------|------------|----------|------------|----------|------------|----------|------------|
|              |       |             |       |     |       |     |       |     |       |
| Pension Plans:    |       |             |       |     |       |     |       |     |       |
| Equity securities |       | 55% - 85         | %          | 66       | %          | 66       | %          | 64       | %          |
| Debt securities   |       | 20% - 40         | %          | 33       | %          | 33       | %          | 34       | %          |
| Other             |       | 0% - 10          | %          | 1        | %          | 1        | %          | 2        | %          |
| Totals            |       |             |       | 100      | %          | 100      | %          | 100      | %          |
|              |       |             |       |     |       |     |       |     |       |
| Other Benefits:   |       |             |       |     |       |     |       |     |       |
| Equity securities |       | —           | %          | —   | %          | —   | %          | —   | %          |
| Debt securities   |       | 100              | %          | 100      | %          | 100      | %          | 100      | %          |
|              |       | 100              | %          | 100      | %          | 100      | %          | 100      | %          |

 

The investment policy of the pension plans was developed in conjunctionwith financial consultants, investment advisors and legal counsel.  The goal of the investment policy is topreserve the capital of the fund and maximize investment earnings with atargeted real rate of return (adjusted for inflation) objective of 6.0 percent.

 

**The fund focuses on a long-terminvestment time horizon of at least three to five years or a complete marketcycle.  The assets of the pension plansare broadly diversified within different asset classes (equities, fixed incomesecurities and cash equivalents).**

 

Tominimize the risk of large losses in a single asset class, no more than 5% ofthe portfolio will be invested in the securities of any one issuer with theexclusion of the U.S. government and its agencies.  The equity portion of the fund is diversifiedamong the market’s various subsections to diversify risk, maximize returns andavoid 

 

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undueexposure to any single economic sector, industry group or individualsecurity.  The equity subsectors include,but are not limited to growth, value, small capitalization and international.

 

Inaddition, the overall fixed income portfolio holdings have a maximum averageweighted maturity of no more than fifteen (15) years, with the weighted averageduration of the portfolio being no more than eight (8) years.  All securities must be rated “investmentgrade” or better and foreign bonds in the aggregate shall not exceed 10% of thetotal fund.  The cash investments shouldbe in securities that either are of short maturities (not to exceed 180 days)or readily marketable with modest risk.

 

Derivative securities are permitted only to improve the portfolio’srisk/return profile or to reduce transaction costs and must be used inconjunction with underlying physical assets in the portfolio. Derivativesecurities that involve speculation, leverage, interest rate anticipation, orany undue risk whatsoever are not deemed appropriate investments.

 

The investment objective for the post retirement benefit plan is toprovide current income consistent with stability of principal and liquiditywhile maintaining a stable net asset value of $1.00 per share.  The post retirement funds are invested in aprime cash money market fund that invests primarily in a portfolio ofshort-term, high-quality fixed income securities issued by banks, corporationsand the U.S. government.

 

### **Contributions. **KU made discretionarycontributions to the pension plan of $43.4 million in January 2004 and $10.2million during 2003.  No discretionarycontributions are planned for 2005.

 

**FSP 106-2. **InMay 2004, the FASB finalized FSP 106-2 with the guidance on accounting forsubsidies provided under the Medicare Act which became law in December2003.  FSP 106-2 was effective for thefirst interim or annual period beginning after June 15, 2004.  The following table reflects the impact ofthe subsidy:

 
| **(in  thousands)**                                                                        | ** ** | ** ** | ** ** |
|--------------------------------------------------------------------------------------------|------------|------------|------------|
| Reduction in accumulated postretirement  benefit obligation (“APBO”)             |       | $          | 3,268      |   |
|                                                                                       |       |       |       |
| Effect of the subsidy on the measurement of  the net periodic postretirement benefit cost: |       |       |       |
|                                                                                       |       |       |       |
| Amortization of the actuarial experience  gain/(loss)                                      |       | $          | 266        |   |
| Reduction in service cost due to the  subsidy                                              |       | 0          |       |
| Resulting reduction in interest cost on the  APBO                                          |       | 204        |       |
| Total                                                                                      |       | $          | 470        |   |

 

**Thrift Savings Plans. **KU has a thriftsavings plan under section 401(k) of the Internal Revenue Code.  Under the plan, eligible employees may deferand contribute to the plan a portion of current compensation in order to providefuture retirement benefits. KU makes contributions to the plan by matching aportion of the employee contributions. The costs of this matching wereapproximately $1.5 million for 2004, $1.9 million for 2003 and $1.5 million for2002.

 

**Note 7 - Income Taxes**

 

Components of income tax expense are shown inthe table below:

 
| **(in  thousands)**                   | ** ** | **2004**           | ** ** | **2003** | ** ** | **2002** | ** ** |
|---------------------------------------|------------|--------------------|------------|----------|------------|----------|------------|
|                                  |       |               |       |     |       |     |       |   |   |
| Related to operating income:          |       |               |       |     |       |     |       |
| Current                               | -          | federal            |       | $        | 39,821     |     | $          | 31,079 |   | $ | 38,524 |   |
|                                  | -          | state              |       | 17,835   |       | 11,456   |       | 10,494 |   |
| Deferred                              | -          | federal – net |       | 21,942   |       | 11,198   |       | 3,467 |   |
|                                  | -          | state – net   |       | (469     | )          | 923      |       | 1,547 |   |
| Total                                 |       |               |       | 79,129   |       | 54,656   |       | 54,032 |   |
|                                  |       |               |       |     |       |     |       |   |   |
| Related to other income - net:        |       |               |       |     |       |     |       |
| Current                               | -          | federal            |       | (530     | )          | (1,961   | )          | (685 | ) |
|                                  | -          | state              |       | (137     | )          | (134     | )          | (195 | ) |
| Deferred                              | -          | federal – net |       | 46       |       | 180      |       | 15 |   |
|                                  | -          | state – net   |       | (34      | )          | (19      | )          | (88 | ) |
| Amortization of investment tax credit |       | (2,054             | )          | (2,641   | )          | (2,955   | )          |
| Total                                 |       |               |       | (2,709   | )          | (4,575   | )          | (3,908 | ) |
|                                  |       |               |       |     |       |     |       |   |   |
| Total income tax expense              |       | $                  | 76,420     |     | $          | 50,081   |       | $ | 50,124 |   |

 

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Components of net deferred tax liabilitiesincluded in the balance sheet are shown below:

 
| **(in  thousands)**                        | ** ** | **2004** | ** ** | **2003** | ** ** |
|--------------------------------------------|------------|----------|------------|----------|------------|
|                                       |       |     |       |     |       |
| Deferred tax liabilities:                  |       |     |       |     |       |
| Depreciation and other plant-related items |       | $        | 304,692    |     | $          | 282,376 |   |
| Regulatory assets and other                |       | 25,877   |       | 27,499   |       |
|                                       |       | 330,569  |       | 309,875  |       |
|                                       |       |     |       |     |       |
| Deferred tax assets:                       |       |     |       |     |       |
| Investment tax credit                      |       | 1,536    |       | 2,365    |       |
| Income taxes due to customers              |       | 7,781    |       | 9,710    |       |
| Pensions and related benefits              |       | 21,164   |       | 16,154   |       |
| Liabilities and other                      |       | 17,453   |       | 20,388   |       |
|                                       |       | 47,934   |       | 48,617   |       |
| Net deferred income tax liability          |       | $        | 282,635    |     | $          | 261,258 |   |
|                                       |       |     |       |     |       |
| Thereof non-current                        |       | $        | 282,436    |     | $          | 259,402 |   |
| Thereof current                            |       | 199      |       | 1,856    |       |
|                                       |       | $        | 282,635    |     | $          | 261,258 |   |

 

A reconciliation of differences between thestatutory U.S. federal income tax rate and KU’s effective income tax ratefollows:

 
| ** **                                 | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|--------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
|                                       |       |     |       |     |       |     |       |
| Statutory federal income tax rate          |       | 35.0     | %          | 35.0     | %          | 35.0     | %          |
| State income taxes, net of federal benefit |       | 5.4      |       | 5.8      |       | 5.5      |       |
| Amortization of investment tax credit      |       | (1.2     | )          | (1.9     | )          | (2.4     | )          |
| Other differences – net               |       | (2.8     | )          | (3.5     | )          | (3.2     | )          |
| Effective income tax rate                  |       | 36.4     | %          | 35.4     | %          | 34.9     | %          |

 

Other differences for 2004 include tax benefits related to a reserveadjustment (0.5%), excess deferred taxes which reflect the benefits of deferredtaxes reversing at lower tax rates than what were provided (1.4%), and variousother permanent differences (0.9%).

 

Other differences for 2003 include tax benefits related to prior yearaudit settlements (1.0%), excess deferred taxes which reflect the benefits ofdeferred taxes reversing at lower tax rates than what were provided (1.9%), andvarious other permanent differences (.6%).

 

Other differences for 2002 include tax benefits related to excessdeferred taxes which reflect the benefits of deferred taxes reversing at lowertax rates than what were provided (1.8%), and various other permanentdifferences (1.4%).

 

H. R. 4520, known as the “American Jobs Creation Act of 2004” allowselectric utilities to take a deduction of up to 3% of their generation taxableincome in 2005. On a stand-alone basis, KU expects to generate a deduction in2005 which will reduce KU’s effective tax rate by less than 1%. 

 

Kentucky House Bill 272, also known as Kentucky’s Tax ModernizationPlan, was signed into law in March 2005. This bill contains a number of changes in Kentucky’s tax system,including the reduction of the Corporate income tax rate from 8.25% to 7%effective January 1, 2005, and a further reduction to 6% effective January 1,2007.  The impact of these reduced ratesis expected to decrease KU’s income tax expense in future periods.  Furthermore, these reduced rates will resultin the reversal of accumulated temporary differences at lower rates thanoriginally provided.  KU is presentlyevaluating the impact of this and other changes to the Kentucky tax system,however, no material adverse impacts on cash flows or results of operations areexpected.

 

KU is subject to periodic changes in state tax law, regulation orinterpretation, as well as enforcement proceedings.  KU is currently undergoing a routine Kentuckysales tax audit for the period January 1996 to July 2000.  The possible assessment or amount at issue isnot known at this time, but is not expected to have a material adverse effecton cashflows or results of operations.  

 

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**Note 8 - Other Income - Net**

 

Other income – net consisted of the followingat December 31:

 
| **(in  thousands)**                     | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|-----------------------------------------|------------|----------|------------|----------|------------|----------|------------|
|                                    |       |     |       |     |       |     |       |
| Equity in earnings - subsidiary company |       | $        | 2,559      |     | $          | 3,644    |       | $ | 6,967 |   |
| Interest and dividend income            |       | 558      |       | 682      |       | 580      |       |
| AFUDC                                   |       | 1,135    |       | 1,037    |       | 87       |       |
| Gain on disposition of property         |       | 525      |       | 135      |       | 0        |       |
| Terminated projects                     |       | 0        |       | (1,665   | )          | 0        |       |
| Benefit expense                         |       | 0        |       | 0        |       | (1,310   | )          |
| Other income (expense)                  |       | 2,768    |       | 689      |       | 197      |       |
|                                    |       | $        | 7,545      |     | $          | 4,522    |       | $ | 6,521 |   |
|                                         |            |          |            |          |            |          |            |  |  |  |  |

 

Equity in earnings – subsidiary company refers to KU’s earnings relatedto EEI (see Note 1).

 

**Note 9 - Long-Term Debt**

 

Refer to the Consolidated Statements ofCapitalization for detailed information for KU’s long-term debt.

 

As of December 31, 2004, long-term debt and the current portion oflong-term debt consists primarily of first mortgage bonds, pollution controlbonds, and long-term loans from affiliated companies as summarized below.  Interest rates and maturities in the tablebelow reflect the impact of interest rate swaps.

 
| **(in  thousands)**                     | ** ** | **Stated  Interest Rates** | ** ** | **Weighted  Average  Interest  Rate** | ** ** | **Maturities** | ** ** | **Principal  Amounts** | ** ** |
|-----------------------------------------|------------|----------------------------|------------|---------------------------------------|------------|----------------|------------|------------------------|------------|
|                                    |       |                       |       |                                  |       |           |       |                   |       |
| Outstanding at December 31, 2004:       |       |                       |       |                                  |       |           |       |                   |       |
| Noncurrent portion                      |       | Variable – 7.92%      |       | 3.68%                                 |       | 2006-2032      |       | $                      | 564,081    |   |
| Current portion                         |       | Variable                   |       | 2.23%                                 |       | 2005-2032      |       | $                      | 162,130    |   |
|                                    |       |                       |       |                                  |       |           |       |                   |       |
| Outstanding at December 31, 2003 : |       |                       |       |                                  |       |           |       |                   |       |
| Noncurrent  portion                     |       | Variable – 7.92%      |       | 3.10%                                 |       | 2006-2032      |       | $                      | 595,646    |   |
| Current  portion                        |       | Variable                   |       | 1.34%                                 |       | 2024-2032      |       | $                      | 91,930     |   |

 

 

Under the provisions for KU’s variable-rate pollution control bondsSeries 10, 12, 13, 14, and 15, the bonds are subject to tender for purchase atthe option of the holder and to mandatory tender for purchase upon theoccurrence of certain events, causing the bonds to be classified as currentportion of long-term debt in the Consolidated Balance Sheets.  The average annualized interest rate forthese bonds during 2004 was 1.37%.

 

Pollutioncontrol series bonds are first mortgage bonds that have been issued by KU inconnection with tax-exempt pollution control revenue bonds issued by variousgovernmental entities, principally counties in Kentucky.  A loan agreement obligates KU to make debtservice payments to the county that equate to the debt service due from thecounty on the related pollution control revenue bonds.  The county’s debt is also secured by an equalamount of KU’s first mortgage bonds (the pollution control series bonds) thatare pledged to the trustee for the pollution control revenue bonds, and thatmatch the terms and conditions of the county’s debt, but require no payment ofprincipal and interest unless KU defaults on the loan agreement.

 

Substantially all of KU’s assets are pledged as security for its firstmortgage bonds.

 

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Interest rate swaps are used to hedge KU’s underlying debtobligations.  These swaps hedge specificdebt issuances and, consistent with management’s designation, are accordedhedge accounting treatment.  The swapseffectively convert fixed rate obligations on KU’s first mortgage bonds SeriesP and R to variable-rate obligations.  Asof December 31, 2004 and 2003, KU had swaps with a combined notional value of$103 million and $153 million, respectively. See Note 4.

 

In October 2004, KU completed a refinancing transaction regarding $50million in existing pollution control indebtedness.  The original indebtedness, 5.75% PollutionControl Bonds, Series 9, due December 1, 2023, was discharged in November 2004,with the proceeds from the replacement indebtedness, KU Pollution ControlBonds, Series 17, due October 1, 2034, which carries a variable, auction rateof interest.  The call premium andunamortized debt expense of the Series 9 bonds are deferred assets beingamortized over the life of the Series 17 bonds.

 

In May 2004, KU redeemed $4.8 million of its Series 14 PollutionControl Bonds which were initially issued in the amount of $7.2 million.

 

In February2004, KU terminated the swap it had in place at December 31, 2003 related tothe Series 9 pollution control bonds. The notional amount of the terminated swap was $50 million and KUreceived a payment of $2.0 million as part of the termination. The swap wasterminated because it was no longer an effective hedge of the underlying bond.

 

In January 2004, KU entered into one unsecured long-term loan fromFidelia totaling $50 million with an interest rate of 4.39% that matures inJanuary 2012.  The proceeds were used torepay amounts due under the accounts receivable securitization program.

 

In November 2003, KU called its first mortgage bond,Series P 8.55% of $33 million, due in 2027, and replaced it with a loan fromFidelia.

 

In June 2003, KU’s first mortgage bond, 6.32% Series Q of $62 million,matured.

 

During 2003, KU entered into four long-term loans from Fidelia totaling$283 million.  Of this total, $100million is unsecured with an interest rate of 4.55% and matures in April2003.  The remaining $183 million (whichis made up of $75 million at 5.31% due August 2013, $33 million at 4.24% dueNovember 2010 and $75 million at 2.29% due December 2005) is collateralized bya pledge of substantially all assets of KU that is subordinated to the firstmortgage bond lien.

 

# **SeeNote 11, Commitments and Contingencies for all long-term debt maturities.**

 

**Note 10 - Notes Payable and Other Short-TermObligations**

 

KU participates in an intercompany money pool agreement whereinLG&E Energy and/or LG&E make funds available to KU at market-basedrates (based on an index of highly rated commercial paper issues as of theprior month end) up to $400 million.  Thebalance of the money pool loan from LG&E Energy (shown as “Notes payable toaffiliated company”) was $34.8 million at an average rate of 2.22% and $43.2million at an average rate of 1.00% at December 31, 2004 and 2003,respectively.  The amount available to KUunder the money pool agreement at December 31, 2004 was $365.2 million.LG&E Energy maintains a revolving credit facility totaling $150 millionwith an affiliate to ensure funding availability for the money pool.  The outstanding balance under LG&E Energy’sfacility as of December 31, 2004 was $65.4 million, and availability of $84.6million remained.   LG&E Energyincreased the size of its revolving credit facility to $200 million effectiveJanuary 24, 2005.

 

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# **Note 11 - Commitments and Contingencies**

 

The following is provided to summarize KU’scontractual cash obligations for periods after December 31, 2004.  KU anticipates cash from operations andexternal financing will be sufficient to fund future obligations.  Future interest obligations cannot bequantified because most of KU's debt is variable rate (see KU's ConsolidatedStatements of Capitalization).

 
| **(in  thousands)**                           | ** ** | **Payments Due by Period** | ** ** |
|-----------------------------------------------|------------|----------------------------|------------|
| **Contractual  Cash Obligations**             | ** ** | **2005**                   | ** ** | **2006** | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** | **Thereafter** | ** ** | **Total** | ** ** |
| Short-term debt (a)                           |       | $                          | 34,820     |   | $ | — |   | $ | — |   | $ | — |   | $ | — |   | $ | — |   | $ | 34,820 |   |
| Long-term debt                                |       | 162,130                    |       | 36,000 |   | 58,088 |   | — |   | — |   | 469,993 | (b) | 726,211 |   |
| Unconditional power purchase obligations  (c) |       | 40,098                     |       | 41,141 |   | 42,625 |   | 43,690 |   | 45,138 |   | 655,720 |   | 868,412 |   |
| Coal purchase obligations (d)                 |       | 263,418                    |       | 156,613 |   | 64,886 |   | 35,808 |   | — |   | — |   | 520,725 |   |
| Retirement obligations (e)                    |       | 6,564                      |       | 6,915 |   | 7,236 |   | 7,479 |   | 7,757 |   | — |   | 35,951 |   |
| Other long-term obligations (f)               |       | 14,771                     |       | — |   | — |   | — |   | — |   | — |   | 14,771 |   |
| Total contractual cash obligations            |       | $                          | 521,801    |   | $ | 240,669 |   | $ | 172,835 |   | $ | 86,977 |   | $ | 52,895 |   | $ | 1,125,713 |   | $ | 2,200,890 |   |

 

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(a)          Represents borrowings from affiliated companydue within one year.

(b)         Includes long-term debt of $87.1 millionclassified as current liabilities because these bonds are subject to tender forpurchase at the option of the holder and to mandatory tender for purchase uponthe occurrence of certain events. Maturity dates for these bonds range from 2024 to 2032.  KU does not expect to pay these amounts in2005.

(c)          Represents future minimum payments under OVEC,OMU and EEI purchased power agreements through 2024.

(d)         Represents contracts to purchase coal.

(e)          Represents currently projected contributionsto pension plans and other post-employment benefits obligations as calculatedby the actuary.

(f)            Represents construction commitments.

 

**Operating Leases.**  KU leases office space, office equipment, andvehicles.  KU accounts for these leasesas operating leases.  In addition, KUreimburses LG&E for a portion of the lease expense paid by LG&E for KU’susage of office space leased by LG&E. Total lease expense for 2004, 2003 and 2002, was $2.8 million, $2.2million and $3.1 million, respectively.

 

**Sale andLeaseback Transaction.** KU is a participant in a saleand leaseback transaction involving its 62% interest in two jointly-owned CTsat KU’s E.W. Brown generating station (Units 6 and 7).  Commencing in December 1999, LG&E and KUentered into a tax-efficient, 18-year lease of the CTs. LG&E and KU haveprovided funds to fully defease the lease, and have executed an irrevocablenotice to exercise an early purchase option contained in the lease after 15.5years. The financial statement treatment of this transaction is no differentthan if KU had retained its ownership. The transaction produced a pre-tax gain of approximately $1.9 millionwhich was recorded in other income on the income statement in 2000, pursuant toa Kentucky Commission order.  The leasingtransaction was entered into following receipt of required state and federalregulatory approvals.

 

In case ofdefault under the lease, KU is obligated to pay to the lessor its share ofcertain fees or amounts. Primary events of default include loss or destructionof the CTs, failure to insure or maintain the CTs and unwinding of thetransaction due to governmental actions. No events of default currently exist with respect to the lease.  Upon any termination of the lease, whether bydefault or expiration of its term, title to the CTs reverts jointly to LG&Eand KU.

 

At December31, 2004, the maximum aggregate amount of default fees or amounts, whichdecrease over the term of the lease, was $9.5 million, of which KU would beresponsible for $5.9 million (62%).  KUhas made arrangements with LG&E Energy, via guarantee and regulatorycommitment, for LG&E Energy to pay its full portion of any default fees oramounts.

 

**Letter ofCredit. **KU hasprovided a letter of credit totaling $0.8 million to support certainobligations related to self-insurance and workers compensation of longshore andharbor workers for barge unloading.

 

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**Purchased Power.**  KU has purchased power arrangements with OMU,EEI, and OVEC.  Under the OMU agreement,which expires on January 1, 2020, KU purchases all of the output of a 400-Mw(approximate) coal-fired generating station not required by OMU.  The amount of purchased power available to KUduring 2005-2009, which is expected to be approximately 7% of KU’s total kWhnative load energy requirements, is dependent upon a number of factorsincluding the OMU units’ availability, maintenance schedules, fuel costs andOMU requirements.  Payments are based onthe total costs of the station allocated per terms of the OMU agreement.  Included in the total costs is KU’sproportionate share of debt service requirements on $205.6 million of OMU bondsoutstanding at December 31, 2004.  Thedebt service is allocated to KU based on its annual allocated share ofcapacity, which averaged approximately 45% in 2004.  KU does not guarantee the OMU bonds, or anyrequirements therein, in the event of default by OMU.

 

KU has a 20% equity ownership in EEI, which is accounted for on theequity method of accounting.  KU’sentitlement is 20% of the available capacity of a 1,000 Mw station.  Payments are based on the total costs of thestation allocated per terms of an agreement among the owners, which generallyfollow delivered kWh.

 

KU has an investment of 2.5% ownership inOVEC’s common stock, which is accounted for on the cost method ofaccounting.  KU’s entitlement is 2.5% ofOVEC’s generation capacity or approximately 55 Mw.

 

**Construction Program.**  KU had approximately $14.8 million ofcommitments in connection with its construction program at  December 31, 2004.  Construction expenditures for the years 2005and 2006 are estimated to total approximately $448 million, although all ofthis is not currently committed, including future expenditures related to theconstruction of Trimble County Unit 2 and the installation of FGDs at Ghent.

 

**Environmental Matters. ** KU is subject to SO2 and NOxemission limits on its electric generating units pursuant to the Clean AirAct.  KU met its Phase I SO2requirements primarily through installation of FGD equipment on Ghent Unit 1and through the consumption of emission allowances granted under the Clean AirAct.  KU’s strategy for Phase II SO2reductions, which commenced January 1, 2000, has been to use accumulatedemissions allowances to delay additional capital expenditures and will includefuel switching and the installation of additional FGDs as necessary. KU decidedin December 2004 that additional FGDs will be necessary to maintain compliancewith Phase II SO2 reductions. Those installations are currently scheduled for completion in 2007-2009.   KU met the NOx emission requirements of theAct through installation of low-NOx burner systems. KU’s compliance plans aresubject to many factors including developments in the emission allowance andfuel markets, future regulatory and legislative initiatives, and advances inclean air control technology.  KU willcontinue to monitor these developments to ensure that its environmentalobligations are met in the most efficient and cost-effective manner.

 

In September 1998, the EPA announced its final “NOx SIP Call” rulerequiring states to impose significant additional reductions in NOx emissionsby May 2003, in order to mitigate alleged ozone transport impacts on theNortheast region.  The Commonwealth ofKentucky SIP, which was approved by the EPA on June 24, 2003, requiresreductions in NOx emissions from coal-fired generating units to the 0.15lb./MMBtu level on a system-wide basis. In related proceedings in response to petitions filed by various Northeaststates, in December 1999, the EPA issued a final rule pursuant to Section 126of the Clean Air Act directing similar NOx reductions from a number ofspecifically targeted generating units including all KU units in the easternhalf of Kentucky.  Additional petitionscurrently pending before the EPA may potentially result in rules encompassingKU’s remaining generating units.  As aresult of appeals to both rules, the compliance date was extended to May 31,2004.  All KU generating units are incompliance with these NOx emissions reduction rules.

 

KU has added significant NOx controls to its generating units throughthe installation of SCR systems, advanced low-NOx burners and neuralnetworks.  The NOx controls projectcommenced in late 2000 with the 

 

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controls being placed into operation prior to the 2004 Summer OzoneSeason. As of December 31, 2004, KU incurred total capital costs ofapproximately $219 million to reduce its NOx emissions below the 0.15 lb./MMBtulevel on a company-wide basis.  Inaddition, KU will incur additional operating and maintenance costs in operatingnew NOx controls.  KU believes its costsin this regard to be comparable to those of similarly situated utilities withlike generation assets. KU anticipated that such capital and operating costsare the type of costs that are eligible for recovery from customers under itsenvironmental surcharge mechanism and believed that a significant portion ofsuch costs could be recovered.  In April2001, the Kentucky Commission granted recovery of these costs for KU.

 

KU is also monitoring several other air quality issues which maypotentially impact coal-fired power plants, including EPA’s revised air qualitystandards for ozone and particulate matter, measures to implement EPA’s regionalhaze rule, and EPA’s Clean Air Mercury Rule which regulates mercury emissionsfrom steam electric generating units and reductions in emissions of SO2and NOx required under the Clean Air Interstate Rule. KU has implemented a planfor adding significant additional SO2 controls to its generatingunits. Installation of additional SO2 controls will proceed on aphased basis, with construction of controls (i.e. FGD’s) commencing in mid 2005and continuing through the final installation and operation in 2009.  KU estimates that it will incur $678 millionin capital costs related to the reduction of its SO2 emissions toachieve compliance with current emission limits on a company-wide basis.  In addition, KU will incur additionaloperating and maintenance costs in operating new SO2 controls.  KU believes its costs in this regard to becomparable to those of similarly situated utilities with like generationassets.  KU anticipates that such capitaland operating costs are the type of costs that are eligible for recovery fromcustomers under its environmental surcharge mechanism and believes that asignificant portion of such costs could be recovered.  In December 2004, KU filed an applicationseeking recovery of its costs. KU expects the Kentucky Commission to issue anOrder granting recovery of these costs in June 2005.

 

KU owns or formerly owned several properties that were used for companyor company-predecessor operations, including MGP’s, power production facilitiesand substations.  While KU has completeda cleanup of one such site in 1995, evaluations of these types of propertiesgenerally have not identified issues of significance.  With regard to these properties, KU isunaware of any imminent exposure or liability.

 

In October 1999, approximately 38,000 gallons of diesel fuel leakedfrom a cracked valve in an underground pipeline at KU’s E.W. BrownStation.  KU commenced immediate spillcontainment and recovery measures which continued under the oversight of EPAand state officials and prevented the spill from reaching the KentuckyRiver.  KU ultimately recoveredapproximately 34,000 gallons of diesel fuel. In November 1999, the Kentucky Division of Water issued a notice ofviolation for the incident.  KU hassettled all outstanding issues for this incident with the Commonwealth ofKentucky.  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 failureto timely submit a facility response plan and a per-gallon fine for the amountof oil discharged.  During August 2004,KU, the EPA, and the Department of Justice agreed in principle to settleoutstanding matters concerning a 1999 oil discharge at KU’s E.W. Brown plantfor approximately $0.6 million. The settlement is subject to completion offinal definitive documents but is anticipated to be resolved by theconstruction of a separate environmental capital project and a cash payment ofapproximately $0.2 million. At December 31, 2004, KU has recorded an accrualand expense of $0.2 million.

 

In April 2002, the EPA sent correspondence to KU regarding potentialexposure in connection with $1.5 million in completed remediation costsassociated with a transformer scrap-yard. KU believes it is one of the more remote parties, among a number ofpotentially responsible parties, and has entered into settlement discussionswith the EPA and the Kentucky Division of Waste Management on this matter.

 

In January 2005, approximately 1,000 gallonsof fuel oil leaked from a cracked weld in a storage tank at 

 

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KU’s Green River Generating Station.  KU commenced immediate spill containment,recovery and remediation actions and has received satisfactory inspections fromstate regulators to date.  The costrelated to the clean up of the oil spill is expected to be immaterial.

 

# **Note 12 – Jointly Owned Electric Utility Plant**

 

LG&E and KU jointly own the followingcombustion turbines:

 
| **(in  thousands)**   | ** ** | ** **     | ** ** | **LG&E** | ** ** | **KU** | ** ** | **Total** | ** ** |
|-----------------------|------------|----------------|------------|--------------|------------|--------|------------|-----------|------------|
|                  |       |           |       |         |       |   |       |      |       |
| Paddy’s Run 13   |       | Ownership %    |       | 53           | %          | 47     | %          | 100       | %          |
|                  |       | Mw capacity    |       | 84           |       | 74     |       | 158       |       |
|                  |       | Cost           |       | $            | 34,033     |   | $          | 30,038    |       | $ | 64,071 |   |
|                  |       | Depreciation   |       | 4,042        |       | 3,555  |       | 7,597     |       |
|                  |       | Net book value |       | $            | 29,991     |   | $          | 26,483    |       | $ | 56,474 |   |
|                  |       |           |       |         |       |   |       |      |       |
| E.W. Brown 5          |       | Ownership %    |       | 53           | %          | 47     | %          | 100       | %          |
|                  |       | Mw capacity    |       | 62           |       | 55     |       | 117       |       |
|                  |       | Cost           |       | $            | 23,978     |   | $          | 20,221    |       | $ | 44,199 |   |
|                  |       | Depreciation   |       | 2,712        |       | 2,269  |       | 4,981     |       |
|                  |       | Net book value |       | $            | 21,266     |   | $          | 17,952    |       | $ | 39,218 |   |
|                  |       |           |       |         |       |   |       |      |       |
| E.W. Brown 6          |       | Ownership %    |       | 38           | %          | 62     | %          | 100       | %          |
|                  |       | Mw capacity    |       | 59           |       | 95     |       | 154       |       |
|                  |       | Cost           |       | $            | 25,353     |   | $          | 38,935    |       | $ | 64,288 |   |
|                  |       | Depreciation   |       | 3,426        |       | 6,644  |       | 10,070    |       |
|                  |       | Net book value |       | $            | 21,927     |   | $          | 32,291    |       | $ | 54,218 |   |
|                  |       |           |       |         |       |   |       |      |       |
| E.W. Brown 7          |       | Ownership %    |       | 38           | %          | 62     | %          | 100       | %          |
|                  |       | Mw capacity    |       | 59           |       | 95     |       | 154       |       |
|                  |       | Cost           |       | $            | 22,718     |   | $          | 36,137    |       | $ | 58,855 |   |
|                  |       | Depreciation   |       | 5,679        |       | 7,012  |       | 12,691    |       |
|                  |       | Net book value |       | $            | 17,039     |   | $          | 29,125    |       | $ | 46,164 |   |
|                  |       |           |       |         |       |   |       |      |       |
| Trimble 5             |       | Ownership %    |       | 29           | %          | 71     | %          | 100       | %          |
|                  |       | Mw capacity    |       | 46           |       | 114    |       | 160       |       |
|                  |       | Cost           |       | $            | 16,241     |   | $          | 39,665    |       | $ | 55,906 |   |
|                  |       | Depreciation   |       | 1,363        |       | 3,327  |       | 4,690     |       |
|                  |       | Net book value |       | $            | 14,878     |   | $          | 36,338    |       | $ | 51,216 |   |
|                  |       |           |       |         |       |   |       |      |       |
| Trimble 6             |       | Ownership %    |       | 29           | %          | 71     | %          | 100       | %          |
|                  |       | Mw capacity    |       | 46           |       | 114    |       | 160       |       |
|                  |       | Cost           |       | $            | 16,205     |   | $          | 39,703    |       | $ | 55,908 |   |
|                  |       | Depreciation   |       | 1,361        |       | 3,332  |       | 4,693     |       |
|                  |       | Net book value |       | $            | 14,844     |   | $          | 36,371    |       | $ | 51,215 |   |
|                  |       |           |       |         |       |   |       |      |       |
| Trimble 7             |       | Ownership %    |       | 37           | %          | 63     | %          | 100       | %          |
|                  |       | Mw capacity    |       | 59           |       | 101    |       | 160       |       |
|                  |       | Cost           |       | $            | 19,274     |   | $          | 32,913    |       | $ | 52,187 |   |
|                  |       | Depreciation   |       | 355          |       | 606    |       | 961       |       |
|                  |       | Net book value |       | $            | 18,919     |   | $          | 32,307    |       | $ | 51,226 |   |
|                  |       |           |       |         |       |   |       |      |       |
| Trimble 8             |       | Ownership %    |       | 37           | %          | 63     | %          | 100       | %          |
|                  |       | Mw capacity    |       | 59           |       | 101    |       | 160       |       |
|                  |       | Cost           |       | $            | 19,161     |   | $          | 32,762    |       | $ | 51,923 |   |
|                  |       | Depreciation   |       | 353          |       | 604    |       | 957       |       |
|                  |       | Net book value |       | $            | 18,808     |   | $          | 32,158    |       | $ | 50,966 |   |
|                  |       |           |       |         |       |   |       |      |       |
| Trimble 9             |       | Ownership %    |       | 37           | %          | 63     | %          | 100       | %          |
|                  |       | Mw capacity    |       | 59           |       | 101    |       | 160       |       |
|                  |       | Cost           |       | $            | 19,195     |   | $          | 32,835    |       | $ | 52,030 |   |
|                  |       | Depreciation   |       | 299          |       | 512    |       | 811       |       |
|                  |       | Net book value |       | $            | 18,896     |   | $          | 32,323    |       | $ | 51,219 |   |
|                  |       |           |       |         |       |   |       |      |       |
| Trimble 10            |       | Ownership %    |       | 37           | %          | 63     | %          | 100       | %          |
|                  |       | Mw capacity    |       | 59           |       | 101    |       | 160       |       |
|                  |       | Cost           |       | $            | 19,141     |   | $          | 32,802    |       | $ | 51,943 |   |
|                  |       | Depreciation   |       | 298          |       | 511    |       | 809       |       |
|                  |       | Net book value |       | $            | 18,843     |   | $          | 32,291    |       | $ | 51,134 |   |
|                  |       |           |       |         |       |   |       |      |       |
| Trimble CT Pipeline   |       | Ownership %    |       | 29           | %          | 71     | %          | 100       | %          |
|                  |       | Cost           |       | $            | 1,978      |   | $          | 4,813     |       | $ | 6,791 |   |
|                  |       | Depreciation   |       | 165          |       | 403    |       | 568       |       |
|                  |       | Net book value |       | $            | 1,813      |   | $          | 4,410     |       | $ | 6,223 |   |
|                  |       |           |       |         |       |   |       |      |       |
| Trimble CT Substation |       | Ownership %    |       | 29           | %          | 71     | %          | 100       | %          |
| 5 & 6             |       | Cost           |       | $            | 1,474      |   | $          | 3,598     |       | $ | 5,072 |   |
|                  |       | Depreciation   |       | 76           |       | 196    |       | 272       |       |
|                  |       | Net book value |       | $            | 1,398      |   | $          | 3,402     |       | $ | 4,800 |   |
|                  |       |           |       |         |       |   |       |      |       |
| Trimble CT Substation |       | Ownership %    |       | 37           | %          | 63     | %          | 100       | %          |
| 7 - 10                |       | Cost           |       | $            | 2,856      |   | $          | 4,711     |       | $ | 7,567 |   |
|                  |       | Depreciation   |       | 30           |       | 53     |       | 83        |       |
|                  |       | Net book value |       | $            | 2,826      |   | $          | 4,658     |       | $ | 7,484 |   |

 

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In addition to these generating units,LG&E and KU share joint ownership in the Brown Inlet Air Cooling system. KUowns 90% of the system, attributable to Brown Unit 5 and Units 8-11, whichprovides an additional 88 Mw of capacity.

 

**Note 13 - Related Party Transactions**

 

KU, subsidiaries of LG&E Energy and other subsidiaries of E.ONengage in related party transactions. Transactions between KU and its subsidiary KU R are eliminated uponconsolidation with KU.  Transactionsbetween KU and LG&E Energy subsidiaries are eliminated upon consolidationof LG&E Energy. Transactions between KU and E.ON subsidiaries areeliminated upon consolidation of E.ON. These transactions are generallyperformed at cost and are in accordance with the SEC regulations under thePUHCA and the applicable Kentucky Commission and Virginia Commissionregulations.  Amounts payable to andreceivable from related parties are netted and presented as accounts payable toaffiliated companies on the balance sheet of KU, as allowed due to the right ofoffset. Obligations related to intercompany debt arrangements with LG&EEnergy and Fidelia are presented as separate line items on the balance sheet,as appropriate. The significant related party transactions are disclosed below.

 

Electric Purchases

 

KU and LG&E purchase energy from each other in order to effectivelymanage the load of their retail and off-system customers.  In addition, KU and LEM, a subsidiary ofLG&E Energy, purchase energy from each other. These sales and purchases areincluded in the Consolidated Statements of Income as Electric OperatingRevenues and Purchased Power Operating Expense. KU intercompany electric revenues and purchased power expense for theyears ended December 31, 2004, 2003 and 2002 were as follows:

 
| **(in  thousands)**                       | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|-------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Electric operating revenues from LG&E |       | $        | 61,743     |     | $          | 46,690   |       | $ | 33,249 |   |
| Electric operating revenues from LEM      |       | 205      |       | 2,408    |       | 3,581    |       |
| Purchased power from LG&E             |       | 58,687   |       | 53,747   |       | 41,480   |       |
| Purchased power from LEM                  |       | —   |       | —   |       | 913      |       |
|                                           |            |          |            |          |            |          |            |  |  |  |

 

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Interest Charges

 

KU participates in an intercompany money pool agreement whereinLG&E Energy and/or LG&E make funds available to KU at market-basedrates (based on an index of highly rated commercial paper issues as of theprior month end) up to $400 million.  Thebalance of the money pool loan from LG&E Energy (shown as “Notes payable toaffiliated company”) was $34.8 million at an average rate of 2.22% and $43.2million at an average rate of 1.00% at December 31, 2004 and 2003,respectively.  The amount available to KUunder the money pool agreement at December 31, 2004 was $365.2 million.LG&E Energy maintains a revolving credit facility totaling $150 millionwith an affiliate to ensure funding availability for the money pool.  The outstanding balance under LG&E Energy’sfacility as of December 31, 2004 was $65.4 million, and availability of $84.6million remained. LG&E Energy increased the size of its revolving creditfacility to $200 million, effective January 24, 2005.

 

In addition, in 2003 KU began borrowinglong-term funds from Fidelia (see Note 9).

 

Intercompany agreements do not requireinterest payments for receivables related to services provided when settledwithin 30 days.  The only interest incomeor expense recorded by KU relates to LG&E’s receipt and payment of KU’sportion of off-system sales and purchases.

 

KU’s intercompany interest income and expense for the years endedDecember 31, 2004, 2003 and 2002 were as follows:

 
| **(in  thousands)**                    | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|----------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Interest on money pool loans           |       | $        | 397        |     | $          | 1,204    |       | $ | 1,071 |   |
| Interest on Fidelia loans              |       | 13,759   |       | 4,729    |       | —   |       |
| Interest expense paid to LG&E      |       | 2        |       | 6        |       | 5        |       |
| Interest income received from LG&E |       | 44       |       | 8        |       | 61       |       |
|                                        |            |          |            |          |            |          |            |  |  |  |

 

Other Intercompany Billings

 

LG&E Services provides KU with a variety of centralizedadministrative, management, and support services in accordance with agreementsapproved by the SEC under PUHCA. These charges include taxes paid by LG&EEnergy on behalf of KU, labor and burdens of LG&E Services employeesperforming services for KU, and vouchers paid by LG&E Services on behalf ofKU.  The cost of these services aredirectly charged to KU, or for general costs which cannot be directlyattributed, charged based on predetermined allocation factors, including thefollowing ratios: number of customers, total assets, revenues, number ofemployees, and other statistical information. These costs are charged on an actual cost basis.

 

In addition, KU and LG&E provide certain services to each other andto LG&E Services, in accordance with exceptions granted under PUHCA.Billings between LG&E and KU relate to labor and overheads associated withunion employees performing work for the other utility, charges related tojointly-owned combustion turbines, and other miscellaneous charges.  Billings from KU to LG&E Services relatedto information technology-related services provided by KU employees, cashreceived by LG&E Services on behalf of KU, and services provided by KU toother non-regulated businesses which are paid through LG&E Services.

 

Intercompany billings to and from KU for the years ended December 31,2004, 2003 and 2002 were as follows:

 
| **(in  thousands)**              | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|----------------------------------|------------|----------|------------|----------|------------|----------|------------|
| LG&E Services billings to KU |       | $        | 170,234    |     | $          | 201,283  |       | $ | 176,254 |   |
| KU billings to LG&E          |       | 7,188    |       | 16,636   |       | 11,921   |       |
| LG&E billings to KU          |       | 59,513   |       | 77,166   |       | 71,127   |       |
| KU billings to LG&E Services |       | 5,019    |       | 16,138   |       | 18,573   |       |
|                                  |            |          |            |          |            |          |            |  |  |  |

 

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**Note 14 – Accumulated Other ComprehensiveIncome**

 

Accumulated other comprehensive incomeconsisted of the following:

 

 
| **(in  thousands)**                                                                                  | ** ** | **Minimum Pension  Liability Adjustment** | ** ** | **Accumulated Derivative  Gain or Loss** | ** ** | **PreTax** | ** ** | **Income  Tax** | ** ** | **Net** | ** ** |
|------------------------------------------------------------------------------------------------------|------------|-------------------------------------------|------------|------------------------------------------|------------|------------|------------|-----------------|------------|---------|------------|
|                                                                                                 |       |                                      |       |                                     |       |       |       |            |       |    |       |
| Balance at December 31, 2001                                                                         |       | $                                         | —     |                                     | $          | 2,663      |       | $               | 2,663      |    | $          | 1,075 |   | $ | 1,588 |   |
| Minimum pension liability adjustment                                                                 |       | (17,543                                   | )          | —                                   |       | (17,543    | )          | (7,081          | )          | (10,462 | )          |
| Gains (losses) on derivative instruments  designated and qualifying as cash flow hedging instruments |       | —                                    |       | (2,663                                   | )          | (2,663     | )          | (1,075          | )          | (1,588  | )          |
| Balance at December 31, 2002                                                                         |       | (17,543                                   | )          | —                                   |       | (17,543    | )          | (7,081          | )          | (10,462 | )          |
|                                                                                                 |       |                                      |       |                                     |       |       |       |            |       |    |       |
| Minimum pension liability adjustment                                                                 |       | 7,676                                     |       | —                                   |       | 7,676      |       | 3,098           |       | 4,578   |       |
| Gains (losses) on derivative instruments  designated and qualifying as cash flow hedging instruments |       | —                                    |       | (246                                     | )          | (246       | )          | (99             | )          | (147    | )          |
| Balance at December 31, 2003                                                                         |       | (9,867                                    | )          | (246                                     | )          | (10,113    | )          | (4,082          | )          | (6,031  | )          |
|                                                                                                 |       |                                      |       |                                     |       |       |       |            |       |    |       |
| Minimum pension liability adjustment                                                                 |       | (12,363                                   | )          | —                                   |       | (12,363    | )          | (4,990          | )          | (7,373  | )          |
| Gains (losses) on derivative instruments  designated and qualifying as cash flow hedging instruments |       | —                                    |       | 246                                      |       | 246        |       | 100             |       | 146     |       |
| Balance at December 31, 2004                                                                         |       | $                                         | (22,230    | )                                        | $          | —     |       | $               | (22,230    | )       | $          | (8,972 | ) | $ | (13,258 | ) |

 

**Note 15 - Selected Quarterly Data (Unaudited)**

 

Selected financial data for the four quarters of 2004 and 2003 areshown below.  Because of seasonalfluctuations in temperature and other factors, results for quarters mayfluctuate throughout the year.

 
| ** **           | ** ** | **Quarters Ended** | ** ** |
|----------------------|------------|--------------------|------------|
| **(in  thousands)**  | ** ** | **March**          | ** ** | **June** | ** ** | **September** | ** ** | **December** | ** ** |
| 2004                 |       |               |       |   |   |   |   |   |   |
| Operating revenues   |       | $                  | 247,386    |   | $ | 232,369 |   | $ | 252,669 |   | $ | 262,938 |   |
| Net operating income |       | 56,355             |       | 50,282 |   | 57,951 |   | 63,259 |   |
| Net income           |       | 32,444             |       | 27,565 |   | 34,818 |   | 38,644 |   |
|                 |       |               |       |   |   |   |   |   |   |
| 2003                 |       |               |       |   |   |   |   |   |   |
| Operating revenues   |       | $                  | 224,983    |   | $ | 197,174 |   | $ | 235,426 |   | $ | 234,195 |   |
| Net operating income |       | 21,261             |       | 26,622 |   | 50,972 |   | 63,355 |   |
| Net income           |       | 11,861             |       | 14,159 |   | 30,310 |   | 35,072 |   |

 

Effective December 31, 2004, operating and non-operating income taxesare presented as “Federal and State Income Taxes” on KU’s ConsolidatedStatements of Income.  Prior to December31, 2004, the component of income taxes associated with operating income wasincluded in net operating income and the component of income taxes associatedwith non-operating income taxes was included in other income (expense) –net.  KU has applied this change inpresentation to all prior periods.

 

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| ** **                                                    | ** ** | **Quarters Ended** | ** ** |
|---------------------------------------------------------------|------------|--------------------|------------|
| **(in  thousands)**                                           | ** ** | **March**          | ** ** | **June** | ** ** | **September** | ** ** | **December** | ** ** |
| 2004                                                          |       |               |       |   |   |   |   |   |   |
| Net operating income as previously reported                   |       | $                  | 35,254     |   | $ | 32,821 |   | $ | 38,386 |   |   |   |
| Plus income taxes reclassified from total  operating expenses |       | 21,101             |       | 17,461 |   | 19,565 |   |   |   |
| Net operating income                                          |       | $                  | 56,355     |   | $ | 50,282 |   | $ | 57,951 |   |   |   |
|                                                          |       |               |       |   |   |   |   |   |   |
| 2003                                                          |       |               |       |   |   |   |   |   |   |
| Net operating income as previously reported                   |       | $                  | 14,660     |   | $ | 19,155 |   | $ | 32,776 |   | $ | 40,963 |   |
| Plus income taxes reclassified from total  operating expenses |       | 6,601              |       | 7,467 |   | 18,196 |   | 22,392 |   |
| Net operating income                                          |       | $                  | 21,261     |   | $ | 26,622 |   | $ | 50,972 |   | $ | 63,355 |   |

 

As the result of EITF No. 02-03, KU has netted the power purchasedexpense for trading activities against electric operating revenue.  KU applied this guidance to all prior periodsbeginning with the June 2003 10-Q filing, which had no impact on previouslyreported net income or common equity (See Note 1).

 
| **(in  thousands)**                              | ** ** | **Quarter Ended  March 30, 2003** | ** ** |
|--------------------------------------------------|------------|-----------------------------------|------------|
|                                             |       |                              |       |
| Gross operating revenues as previously  reported |       | $                                 | 234,147    |   |
| Less costs reclassified from power  purchased    |       | 9,164                             |       |
| Net operating revenues                           |       | $                                 | 224,983    |   |

 

# ** **

# **Note 16 – Subsequent Events**

 

In February2005, Kentucky’s Governor signed an executive order directing the KentuckyCommission, in conjunction with the Commerce Cabinet and the Environmental andPublic Protection Cabinet, to ‘develop a Strategic Blueprint for the continueduse and development of electric energy.’ This Strategic Blueprint will bedesigned to promote future investment in electric infrastructure for the Commonwealthof Kentucky, to protect Kentucky’s low-cost electric advantage, to maintainaffordable rates for all Kentuckians, and to preserve Kentucky’s commitment toenvironmental protection.  In March 2005,the Kentucky Commission established Administrative Case No. 2005-00090 tocollect information from all jurisdictional utilities in Kentucky, includingKU, pertaining to Kentucky electric generation, transmission and distributionsystems.  The Kentucky Commission mustprovide its Strategic Blueprint to the Governor in early August 2005.  KU must respond to the Kentucky Commission’sfirst set of data requests by the end of March 2005.

 

Kentucky House Bill 272, also known as Kentucky’s Tax ModernizationPlan, was signed into law in March 2005.  This bill contains a numberof changes in Kentucky’s tax system, including the reduction of the Corporateincome tax rate from 8.25% to 7% effective January 1, 2005, and a furtherreduction to 6% effective January 1, 2007. The impact of these reduced rates is expected to decrease KU’s incometax expense in future periods. Furthermore, these reduced rates will result in the reversal ofaccumulated temporary differences at lower rates than originally provided.  KU is presently evaluating the impact of thisand other changes to the Kentucky tax system, however, no material adverseimpacts on cash flows or results of operations are expected.

 

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Kentucky Utilities Company

REPORT OFMANAGEMENT

 

The management of Kentucky Utilities Company (“KU”) is responsible forthe preparation and integrity of the financial statements and relatedinformation included in this Annual Report. These statements have been prepared in accordance with accountingprinciples generally accepted in the United States applied on a consistentbasis and, necessarily, include amounts that reflect the best estimates andjudgment of management.

 

KU’s financial statements for the three years ended December 31, 2004 havebeen audited by PricewaterhouseCoopers LLP, an independent registered publicaccounting firm.  Management madeavailable to PricewaterhouseCoopers LLP all KU’s financial records and relateddata as well as the minutes of shareholders’ and directors’ meetings.

 

Management has established and maintains a system of internal controlsthat provide reasonable assurance that transactions are completed in accordancewith management’s authorization, that assets are safeguarded and that financialstatements are prepared in conformity with generally accepted accountingprinciples.  Management believes that anadequate system of internal controls is maintained through the selection andtraining of personnel, appropriate division of responsibility, establishmentand communication of policies and procedures and by regular reviews of internalaccounting controls by KU’s internal auditors. Management reviews and modifies its system of internal controls in lightof changes in conditions and operations, as well as in response torecommendations from the internal and external auditors.  These recommendations for the year endedDecember 31, 2004, did not identify any material weaknesses in the design andoperation of KU’s internal control structure.

 

KU is not anaccelerated filer under the Sarbanes-Oxley Act of 2002 and associated rules(the “Act”) and consequently anticipates issuing Management’s Certification onInternal Controls over Financial Reporting pursuant to Section 404 of the Actin its first periodic report covering the fiscal year ended December 31, 2006as permitted by SEC rulemaking.

 

In carrying out its oversight role for the financial reporting andinternal controls of KU, the Board of Directors meets regularly with KU’sindependent auditors, internal auditors and management.  The Board of Directors reviews the results ofthe independent auditors’ audit of the financial statements and their auditprocedures, and discusses the adequacy of internal accounting controls.  The Board of Directors also approves theannual internal auditing program, and reviews the activities and results of theinternal auditing function.  Both theindependent registered public accounting firm and the internal auditors haveaccess to the Board of Directors at any time.

 

KU maintains and internally communicates awritten code of business conduct and a senior financial officer code of ethicswhich address, among other items, potential conflicts of interest, compliancewith laws, including those relating to financial disclosure, and theconfidentiality of proprietary information.

 

S. Bradford Rives

Chief Financial Officer

 

 

Kentucky Utilities Company

Louisville, Kentucky

 

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Kentucky UtilitiesCompany and Subsidiary

REPORT OFINDEPENDENT REGISTERED PUBLICACCOUNTING FIRM

 

To the Shareholders of Kentucky Utilities Company and Subsidiary:

 

In our opinion, the accompanying consolidated balance sheets and therelated consolidated statements of capitalization, income, retained earnings,cash flows and comprehensive income present fairly, in all material respects,the financial position of Kentucky Utilities Company and Subsidiary at December31, 2004 and December 31, 2003, and the results of their operations and theircash flows for each of the three years in the period ended December 31, 2004 inconformity with accounting principles generally accepted in the United Statesof America.  In addition, in our opinion, based on our audits, the financial statement schedule as of and foreach of the three years in the period ended December 31, 2004, listed in theindex appearing under Item 15(a)(2), presents fairly in all material respects,the information set forth therein when read in conjunction with the relatedconsolidated****financial statements.  These financial statements are theresponsibility of the Company’s management. Our responsibility is to express anopinion on these financial statements based on our audits.  We conducted our audits of these statementsin accordance with the standards of the Public Company Accounting Oversight Board(United States).  Those standards requirethat we plan and perform the audit to obtain reasonable assurance about whetherthe financial statements are free of material misstatement.  An audit includes examining, on a test basis,evidence supporting the amounts and disclosures in the financial statements,assessing the accounting principles used and significant estimates made bymanagement, and evaluating the overall financial statement presentation.  We believe that our audits provide areasonable basis for our opinion.

 

As discussed in Note 1 to the consolidatedfinancial statements, effective January 1, 2003,  Kentucky Utilities Company and Subsidiaryadopted EITF No. 02-03*, Issues Involved inAccounting for Derivative Contracts Held for Trading Purposes and ContractsInvolved in Energy Trading and Risk Management Activities*.

 

As discussed in Note 1 to the consolidated financial statements,effective January 1, 2003, Kentucky Utilities Company and Subsidiary adoptedStatement of Financial Accounting Standards No. 143, *Accountingfor Asset Retirement Obligations.*

 
| /s/ PricewaterhouseCoopers LLP |   |
|--------------------------------|--------|
|                           |
|                           |
|                           |
| Louisville, Kentucky           |
| February 4, 2005               |

 

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# **ITEM9.** Changes in and Disagreements with Accountantson Accounting and Financial Disclosure.

# ** **

Not applicable.

 

ITEM 9A.  Controls and Procedures

 

Disclosure Controls

# ** **

LG&E and KU maintain a system of disclosure controls and proceduresdesigned to ensure that information required to be disclosed by the companiesin reports they file or submit under the Securities Exchange Act of 1934 isrecorded, processed, summarized and reported, within the time periods specifiedin the Securities and Exchange Commission rules and forms.  LG&E and KU conducted an evaluation ofsuch controls and procedures under the supervision and with the participationof the Companies’ Management, including the Chairman, President and ChiefExecutive Officer (“CEO”) and the Chief Financial Officer (“CFO”). Based uponthat evaluation, the CEO and CFO are of the conclusion that the Companies’disclosure controls and procedures are effective as of the end of the periodcovered by this report.

 

In preparation for required reporting under Section 404 of theSarbanes-Oxley Act of 2002, the Companies are conducting a thorough review oftheir internal control over financial reporting, including disclosure controlsand procedures. Based on this review, the Companies have made internal controlenhancements and will continue to make future enhancements to their internalcontrol over financial reporting. There has been no change in the Companies’internal control over financial reporting that occurred during the fiscalquarter ended December 31, 2004, that has materially affected, or is reasonablylikely to materially affect, the Companies’ internal control over financialreporting.

# ** **

LG&E andKU are not accelerated filers under the Sarbanes-Oxley Act of 2002 andassociated rules (the “Act”) and consequently anticipate issuing Management’s Reporton Internal Controls over Financial Reporting pursuant to Section 404 of theAct in its first periodic report covering the fiscal year ended December 31,2006 as permitted by SEC rulemaking.

 

# **PART III**

 

**ITEM 10.****Directorsand Executive Officers of LG&E and KU**.

 

Information regarding directors of who are standing for reelection isset forth in Exhibit 99.02 filed herewith, which information is incorporatedherein by reference.  Informationregarding executive officers of LG&E and KU has been included in Part I ofthis Form 10-K.

 

Audit Committee Independence and Financial Expert

 

As wholly-owned subsidiaries of a common parent, LG&E and KU eachhave a five-person board of directors. Due to the small size of this board, theboard as a whole performs the functions associated with audit committees.  The Boards of Directors of LG&E and KUhave determined that each of Victor A. Staffieri and S. Bradford Rives is anaudit committee financial expert as defined by Item 401(h) of Regulation S-K.  All of the members of the boards of LG&Eand KU are officers or employees of the companies, or their ultimate parent, 

 

165

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E.ON AG, and therefore are not independent within the meaning of Item7(d)(3)(iv) of Schedule 14A of the Exchange Act.   Nevertheless, LG&E and KU believe thestructure and composition of their boards of directors and the qualificationsand attributes of their members to be fully able and competent to perform theirduties in the areas associated with audit committees.

 

Code of Ethics

 

LG&E and KU have adopted a code of ethics for senior financialofficers (including principal executive officer, principal financial officer,principal accounting officer and controller or other employees performingsimilar functions). The Senior Financial Officer Code of Ethics is available ontheir corporate website at http://www.lgeenergy.com.  LG&E and KU intend to satisfy thedisclosure requirement under Item 5.05 of Form 8-K regarding an amendment to,or waiver from, a provision of the Code of Ethics by posting such informationon our website at the location specified above.

 

Section 16(a) Beneficial Ownership Reporting Compliance

 

Information regarding Section 16(a) beneficial ownership reportingcompliance is included in Exhibit 99.02 filed herewith, which information isincorporated herein by reference.

 

# **ITEM11.** ExecutiveCompensation.

 

Information regarding compensation of named executive officers and ofdirectors is set forth in Exhibit 99.02 filed herewith, which information isincorporated herein by reference.

 

# **ITEM12.** Security Ownershipof Certain Beneficial Owners and Management and Related Stockholder Matters.

 

Information regarding security ownership of certain beneficial owners,directors and executive officers is set forth in Exhibit 99.02 filed herewith,which information is incorporated herein by reference.

 

Information regarding equity compensation plans, includingnon-stockholder approved plans, is set forth in Exhibit 99.02 filed herewith,which information is incorporated herein by reference.

 

# **ITEM13.** CertainRelationships and Related Transactions.

 

Information regarding certain relationships and related transactions,if applicable, is set forth in Exhibit 99.02 filed herewith, which informationis incorporated herein by reference.

 

# **ITEM14.** Principal AccountantFees and Services.

 

Information regarding principal accountant fees and services is setforth in Exhibit 99.02 filed herewith, which information is incorporated hereinby reference.

 

PART IV

 

**ITEM 15****.  Exhibits** and FinancialStatement Schedules.

 

(a)        1.   Financial Statements (included in Item 8):

 

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| LG&E:                                                                                    |   |
|----------------------------------------------------------------------------------------------|--------|
| Consolidated Statements of Income for the  three years ended December 31, 2004               |   |
| Consolidated Statements of Retained  Earnings for the three years ended December 31, 2004    |   |
| Consolidated Statements of Comprehensive  Income for the three years ended December 31, 2004 |   |
| Consolidated Balance Sheets-December 31, 2004, and 2003                                      |   |
| Consolidated Statements of Cash Flows for  the three years ended December 31, 2004           |   |
| Consolidated Statements of Capitalization-December  31, 2004, and 2003                       |   |
| Notes to Consolidated Financial Statements                                                   |   |
| Report of Management                                                                         |   |
| Report of Independent Registered Public  Accounting Firm                                     |   |
|                                                                                         |   |
| KU:                                                                                          |   |
| Consolidated Statements of Income for the three  years ended December 31, 2004               |   |
| Consolidated Statements of Retained  Earnings for the three years ended December 31, 2004    |   |
| Consolidated Statements of Comprehensive  Income for the three years ended December 31, 2004 |   |
| Consolidated Balance Sheets-December 31, 2004, and 2003                                      |   |
| Consolidated Statements of Cash Flows for  the three years ended December 31, 2004           |   |
| Consolidated Statements of  Capitalization-December 31, 2004, and 2003                       |   |
| Notes to Consolidated Financial Statements                                                   |   |
| Report  of Management                                                                        |   |
| Report of Independent Registered Public  Accounting Firm                                     |   |

 

2.               Financial Statement Schedules (includedin Part IV):

 
|        |                                                                                                 |
|-------------|------------------------------------------------------------------------------------------------------|
| Schedule II | Valuation and Qualifying Accounts for the  three years ended December 31, 2004, for LG&E and KU. |   |
|             |                                                                                                      |  |

 

All other schedules have been omitted as notapplicable or not required or because the information required to be shown isincluded in the Financial Statements or the accompanying Notes to FinancialStatements.

 

3.               Exhibits:

 
| **Exhibit  No.** | ** **   | **Applicable  to  Form  10-K of** |   |       |
|------------------|--------------|-----------------------------------|--------|------------|
| ** **       | **LG&E** | ** **                        | **KU** | ** ** | **Description** |
|             |         |                              |   |       |   |   |
| 2.01             |         | X                                 |   | X          |   | Copy of  Agreement and Plan of Merger, dated as of February 27, 2000, by and  among Powergen plc, LG&E Energy Corp., US Subholdco2 and Merger Sub,  including certain exhibits thereto.  [Filed as Exhibit 1 to LG&E’s  and KU’s Current Report on Form 8-K filed February 29, 2000 and  incorporated by reference herein] |
|             |         |                              |   |       |   |   |
| 2.02             |         | X                                 |   | X          |   | Amendment  No. 1 to Agreement and Plan of Merger, dated as of December 8, 2000,  among LG&E Energy Corp., Powergen plc, Powergen US Investments Corp. and  Powergen Acquisition Corp. [Filed as Exhibit 2.01 to LG&E’s and KU’s Current  Report on Form 8-K filed December 11, 2000 and incorporated by reference  herein] |
|             |         |                              |   |       |   |   |
| 2.03             |         | X                                 |   | X          |   | Copy of  Agreement and Plan of Merger, dated as of May 20, 1997, by and between  LG&E Energy and KU Energy, including certain exhibits thereto.   [Filed as Exhibit 2 to LG&E’s and KU’s Current Report on Form 8-K filed  May 30, 1997 and incorporated by reference herein] |
|             |         |                              |   |       |   |   |
| 3.01             |         | X                                 |   |       |   | Copy of  Restated Articles of Incorporation of LG&E, dated November 6, 1996.  [Filed as Exhibit 3.06 to LG&E Quarterly Report on Form 10-Q for the  quarter ended September 30, 1996, and incorporated by reference herein] |
|             |         |                              |   |       |   |   |
| 3.02             |         | X                                 |   |       |   | Copy of  Amendment to Articles of Incorporation of LG&E, dated February 6,  2004. [Filed as Exhibit 3.02 to LG&E and KU’s Annual Report on Form 10-K  for the year ended December 31, 2004, and incorporated by reference herein] |

 

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|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                    |
|--------|--------|--------|--------|--------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 3.03   |   | X      |   |   |   | Copy of  By-Laws of LG&E, as amended through December 16, 2003. [Filed as  Exhibit 3.03 to LG&E and KU’s Annual Report on Form 10-K for the year  ended December 31, 2004, and incorporated by reference herein]                                                      |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                    |
| 3.04   |   |   |   | X      |   | Copy of  Amended and Restated Articles of Incorporation of KU [Filed as Exhibits 4.03  and 4.04 to Form 8-K Current Report of KU, dated December 10, 1993, and  incorporated by reference herein]                                                                                  |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                    |
| 3.05   |   |   |   | X      |   | Copy of  Amendment to Articles of Incorporation of KU, dated February 6, 2004.  [Filed as Exhibit 3.05 to LG&E’s and KU’s Annual Report on Form 10-K for  the year ended December 31, 2004, and incorporated by reference herein]                                    |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                    |
| 3.06   |   |   |   | X      |   | Copy of  By-Laws of KU, as amended through December 16, 2003. [Filed as Exhibit  3.06 to LG&E and KU’s Annual Report on Form 10-K for the year ended  December 31, 2004, and incorporated by reference herein]                                                            |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                    |
| 4.01   |   | X      |   |   |   | Copy of  Trust Indenture dated November 1, 1949, from LG&E to Harris Trust  and Savings Bank, Trustee.  [Filed as Exhibit 7.01 to LG&E’s  Registration Statement 2-8283 and incorporated by reference herein]                                               |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                    |
| 4.02   |   | X      |   |   |   | Copy of  Supplemental Indenture dated September 1, 1992, which is a supplemental  instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.32 to LG&E’s  Annual Report on Form 10-K for the year ended December 31, 1992, and  incorporated by reference herein] |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                    |
| 4.03   |   | X      |   |   |   | Copy of  Supplemental Indenture dated September 2, 1992, which is a supplemental  instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.33 to LG&E’s  Annual Report on Form 10-K for the year ended December 31, 1992, and  incorporated by reference herein] |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                    |
| 4.04   |   | X      |   |   |   | Copy of  Supplemental Indenture dated August 16, 1993, which is a supplemental  instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.35 to LG&E’s  Annual Report on Form 10-K for the year ended December 31, 1993, and  incorporated by reference herein]   |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                    |
| 4.05   |   | X      |   |   |   | Copy of  Supplemental Indenture dated October 15, 1993, which is a supplemental  instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.36 to LG&E’s  Annual Report on Form 10-K for the year ended December 31, 1993, and  incorporated by reference herein]  |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                    |
| 4.06   |   | X      |   |   |   | Copy of  Supplemental Indenture dated May 1, 2000, which is a supplemental instrument  to Exhibit 4.01 hereto.  [Filed as Exhibit 4.37 to LG&E’s Annual  Report on Form 10-K/A for the year ended December 31, 2000, and  incorporated by reference herein]          |

 

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|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
|--------|--------|--------|--------|--------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 4.07   |   | X      |   |   |   | Copy of  Supplemental Indenture dated August 1, 2000, which is a supplemental  instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.38 to LG&E’s  Annual Report on Form 10-K/A for the year ended December 31, 2000, and  incorporated by reference herein]                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
| 4.08   |   | X      |   |   |   | Copy of  Supplemental Indenture dated March 1, 2002, which is a supplemental  instrument to Exhibit 4.01 hereto.  (Filed as Exhibit 4.39 to LG&E’s  Annual Report on Form 10-K for the year ended December 31, 2002, and  incorporated by reference herein.)                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
| 4.09   |   | X      |   |   |   | Copy of  Supplemental Indenture dated March 15, 2002, which is a supplemental  instrument to Exhibit 4.01 hereto.  (Filed as Exhibit 4.40 to LG&E’s  Annual Report on Form 10-K for the year ended December 31, 2002, and  incorporated by reference herein.)                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
| 4.10   |   | X      |   |   |   | Copy of  Supplemental Indenture dated October 1, 2002, which is a supplemental  instrument to Exhibit 4.01 hereto.  (Filed as Exhibit 4.41 to LG&E’s  Annual Report on Form 10-K for the year ended December 31, 2002, and  incorporated by reference herein.)                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
| 4.11   |   |   |   | X      |   | Indenture of  Mortgage or Deed of Trust dated May 1, 1947, between KU and First Trust  National Association (successor Trustee) and a successor individual co-trustee,  as Trustees (the Trustees) (Amended Exhibit 7(a) in File No. 2-7061), and  Supplemental Indentures thereto dated, respectively, January 1, 1949  (Second Amended Exhibit 7.02 in File No. 2-7802), July 1, 1950 (Amended  Exhibit 7.02 in File No. 2-8499), June 15, 1951 (Exhibit 7.02(a) in File  No. 2-8499), June 1, 1952 (Amended Exhibit 4.02 in File No. 2-9658),  April 1, 1953 (Amended Exhibit 4.02 in File No. 2-10120), April 1,  1955 (Amended Exhibit 4.02 in File No. 2-11476), April 1, 1956 (Amended  Exhibit 2.02 in File No. 2-12322), May 1, 1969 (Amended Exhibit 2.02 in File  No. 2-32602), April 1, 1970 (Amended Exhibit 2.02 in File No. 2-36410),  September 1, 1971 (Amended Exhibit 2.02 in File No. 2-41467),  December 1, 1972 (Amended Exhibit 2.02 in File No. 2-46161),  April 1, 1974 (Amended Exhibit 2.02 in File No. 2-50344),  September 1, 1974 (Exhibit 2.04 in File No. 2-59328), July 1, 1975  (Exhibit 2.05 in File No. 2-59328), May 15, 1976 (Amended Exhibit 2.02 in  File No. 2-56126), April 15, 1977 (Exhibit 2.06 in File No. 2-59328),  August 1, 1979 (Exhibit 2.04 in File No. 2-64969), May 1, 1980 (Exhibit  2 to Form 10-Q Quarterly Report of KU for the quarter ended June 30,  1980), September 15, 1982 (Exhibit 4.04 in File No. 2-79891),  August 1, 1984 (Exhibit 4B to Form 10-K Annual Report of KU for the year  ended December 31, 1984), June 1, 1985 (Exhibit 4 to Form 10-Q  Quarterly Report of KU for the quarter ended June 30, 1985), May 1, 1990  (Exhibit 4 to Form 10-Q Quarterly Report of KU for the quarter ended  June 30, 1990), May 1, 1991 (Exhibit 4 to Form 10-Q Quarterly Report of  KU for the quarter ended June 30, 1991), May 15, 1992 (Exhibit 4.02 to  Form 8-K of KU dated May 14, 1992), August 1, 1992 (Exhibit 4 to Form  10-Q Quarterly Report of KU for the quarter ended September 30, 1992),  June 15, 1993 (Exhibit 4.02 to Form 8-K of KU dated June 15, 1993)  and December 1, 1993 (Exhibit 4.01 to Form 8-K of KU dated  December 10, 1993), November 1, 1994 |

 

 

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|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                        |
|--------|--------|--------|--------|--------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |   |   |   |   | (Exhibit 4.C  to Form 10-K Annual Report of KU for the year ended December 31, 1994),  June 1, 1995 (Exhibit 4 to Form 10-Q Quarterly Report of KU for the  quarter ended June 30, 1995) and January 15, 1996 [Filed as Exhibit  4.E to Form 10-K Annual Report of KU for the year ended December 31,  1995, and incorporated by reference herein] |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                        |
| 4.12   |   |   |   | X      |   | Copy of  Supplemental Indenture dated March 1, 1992 between KU and the Trustees,  providing for the conveyance of properties formerly held by Old Dominion  Power Company  [Filed as Exhibit 4B to Form 10-K Annual Report of KU for  the year ended December 31, 1992, and incorporated by reference herein]                                                |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                        |
| 4.13   |   |   |   | X      |   | Copy of  Supplemental Indenture dated May 1, 2000, which is a supplemental instrument  to Exhibit 4.12 hereto.  [Filed as Exhibit 4.41 to KU’s Annual Report on  Form 10-K for the year ended December 31, 2000, and incorporated by  reference herein]                                                                                                      |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                        |
| 4.14   |   |   |   | X      |   | Copy of  Supplemental Indenture dated September 1, 2001, which is a supplemental  instrument to Exhibit 4.12 hereto. [Filed as Exhibit 4.42 to KU’s Annual  Report on Form 10-K for the year ended December 31, 2001, and  incorporated by reference herein]                                                                                                 |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                        |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                        |
| 4.15   |   |   |   | X      |   | Copy of  Supplemental Indenture dated May 1, 2002, which is a supplemental instrument  to Exhibit 4.12 hereto.  [Filed as Exhibit 4.50 to KU’s Annual Report on  Form 10-K for the year ended December 31, 2002, and incorporated by  reference herein]                                                                                                      |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                        |
| 4.16   |   |   |   | X      |   | Copy of  Supplemental Indenture dated September 1, 2002, which is a supplemental  instrument to Exhibit 4.12 hereto.  [Filed as Exhibit 4.51 to KU’s  Annual Report on Form 10-K for the year ended December 31, 2002, and  incorporated by reference herein]                                                                                           |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                        |
| 4.17   |   | X      |   |   |   | Copy of  Supplemental Indenture dated October 1, 2003, which is a supplemental  instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.22 to LG&E’s  Annual Report on Form 10-K for the year ended December 31, 2004, and incorporated  by reference herein]                                                                                                  |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                        |
| 4.18   |   |   |   | X      |   | Copy of Loan  Agreement between KU and Fidelia Corporation, dated April 30, 2003.                                                                                                                                                                                                                                                                                      |
|   |   |   |   |   |   |  [Filed  as Exhibit 4.23 to KU’s Annual Report on Form 10-K for the year ended  December 31, 2004, and incorporated by reference herein]

                                                                                                                                                                                                                   |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                        |
| 4.19   |   | X      |   |   |   | Copy of Loan  Agreement between LG&E and Fidelia Corporation, dated April 30,  2003. [Filed as Exhibit 4.24 to LG&E’s Annual Report on Form 10-K for the  year ended December 31, 2004, and incorporated by reference herein]                                                                                                                             |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                        |
| 4.20   |   |   |   | X      |   | Copy of Loan  Agreement between KU and Fidelia Corporation, dated January 15,  2004.  [Filed as Exhibit 4.25 to KU’s  Annual Report on Form 10-K for the year ended December 31, 2004, and  incorporated by reference herein]                                                                                                                                |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                        |
| 4.21   |   |   |   | X      |   | Copy of Loan  and Security Agreement between KU and Fidelia Corporation, dated as of  August 15, 2003. [Filed as Exhibit 4.26 to KU’s Annual Report on Form  10-K for                                                                                                                                                                                             |

 

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|        |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |
|-------------|--------|--------|--------|--------|--------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|        |   |   |   |   |   | the year  ended December 31, 2004, and incorporated by reference herein]                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
|        |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |
| 4.22        |   | X      |   | X      |   | Copy of Loan  and Security Agreement between LG&E and Fidelia Corporation, dated as of  August 15, 2003.  [Filed as  Exhibit 4.27 to LG&E’s Annual Report on Form 10-K for the year ended  December 31, 2004, and incorporated by reference herein]                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
|        |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |
|        |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |
| 4.23        |   |   |   | X      |   | Copy of  Promissory Note from KU to Fidelia Corporation, dated as of November 24,  2003, in the amount of $33 million.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
|        |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |
|        |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |
| 4.24        |   |   |   | X      |   | Copy of  Promissory Note from KU to Fidelia Corporation, dated as of December 18,  2003, in the amount of $75 million.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
|        |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |
|        |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |
| 4.25        |   |   |   | X      |   | Copy of Loan  Agreement between KU and Fidelia Corporation, dated as of January 15, 2004                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
|        |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |
| 4.26        |   |   |   | X      |   | Supplemental  Indenture dated as of October 1, 2004 from Kentucky Utilities Company to U.S.  Bank National Association and Richard Prokosch, as Trustees  [Filed as Exhibit 4.1 to KU’s Form 8-K  filed on October 22, 2004, and incorporated by reference herein].                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
|        |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |
| 4.27        |   | X      |   |   |   | Copy of  Promissory Note from LG&E to Fidelia Corporation, dated as of January 15,  2004, in the amount of $25 million.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                |
|        |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |
|        |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |
|        |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |
|        |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |
| 10.01       |   | X      |   | X      |   | Copies of  (i) Inter-Company Power Agreement, dated July 10, 1953, between Ohio  Valley Electric Corporation and Sponsoring Companies (which Agreement  includes as Exhibit A the Power Agreement, dated July 10, 1953, between  Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation);  (ii) First Supplementary Transmission Agreement, dated July 10, 1953,  between Ohio Valley Electric Corporation and Sponsoring Companies; (iii)  Inter-Company Bond Agreement, dated July 10, 1953, between Ohio Valley  Electric Corporation and Sponsoring Companies; (iv) Inter-Company Bank Credit  Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation  and Sponsoring Companies.  [Filed as Exhibit 5.02f to LG&E’s  Registration Statement 2-61607 and incorporated by reference herein] |
|        |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |
|        |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |
|  10.02 |   | X      |   | X      |   | Copy of  Modification No. 1 and No. 2 dated June 3, 1966 and January 7,  1967, respectively, to Inter-Company Power Agreement dated July 10,  1953.  [Filed as Exhibits 4(a)(8) and 4(a)(10) to LG&E’s  Registration Statement 2-26063 and incorporated by reference herein]                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |
|        |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |
| 10.03       |   | X      |   | X      |   | Copies of  Amendments to Agreements (iii) and (iv) referred to under 10.06 above as  follows:  (i) Amendment to Inter-Company Bond Agreement and (ii)  Amendment to Inter-Company Bank Credit Agreement.  [Filed as Exhibit  5.02h to LG&E’s Registration Statement 2-61607 and incorporated by  reference herein]                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
|        |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |
| 10.04       |   | X      |   | X      |   | Copy of  Modification No. 1, dated August 20, 1958, to First Supplementary  Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric  Corporation and the Sponsoring Companies.  [Filed as Exhibit 5.02i to  LG&E’s Registration Statement 2-61607 and incorporated by reference  herein]                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |

 

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|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                          |
|--------|--------|--------|--------|--------|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.05  |   | X      |   | X      |   | Copy of  Modification No. 2, dated April 1, 1965, to the First Supplementary  Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric  Corporation and the Sponsoring Companies.  [Filed as Exhibit 5.02j to  LG&E’s Registration Statement 2-61607 and incorporated by reference  herein]                            |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                          |
| 10.06  |   | X      |   | X      |   | Copy of  Modification No. 3, dated January 20, 1967, to First Supplementary  Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric  Corporation and the Sponsoring Companies.  [Filed as Exhibit 4(a)(7) to  LG&E’s Registration Statement 2-26063 and incorporated by reference  herein]                           |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                          |
| 10.07  |   | X      |   | X      |   | Copy of  Modification No. 3 dated November 15, 1967, to the Inter-Company Power  Agreement dated July 10, 1953.  [Filed as Exhibit 4.02m to  LG&E’s Registration Statement 2-37368 and incorporated by reference  herein]                                                                                                             |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                          |
| 10.08  |   | X      |   | X      |   | Copy of  Modification No. 4 dated November 5, 1975, to the Inter-Company Power  Agreement dated July 10, 1953.  [Filed as Exhibit 5.02o to  LG&E’s Registration Statement 2-56357 and incorporated by reference  herein]                                                                                                         |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                          |
| 10.09  |   | X      |   | X      |   | Copy of  Modification No. 4 dated April 30, 1976, to First Supplementary  Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric  Corporation and the Sponsoring Companies.  [Filed as Exhibit 5.02p  to LG&E’s Registration Statement 2-61607 and incorporated by reference  herein]                           |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                          |
| 10.10  |   | X      |   | X      |   | Copy of  Modification No. 5 dated September 1, 1979, to Inter-Company Power  Agreement dated July 5, 1953, among Ohio Valley Electric Corporation and  Sponsoring Companies.  [Filed as Exhibit 4 to LG&E’s Annual Report  on Form 10-K for the year ended December 31, 1979, and incorporated by  reference herein]             |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                          |
| 10.11  |   | X      |   | X      |   | Copy of  Modification No. 6 dated August 1, 1981, to Inter-Company Power  Agreement dated July 5, 1953, among Ohio Valley Electric Corporation and  Sponsoring Companies.  [Filed as Exhibit 10.26 to LG&E’s Annual  Report on Form 10-K for the year ended December 31, 1981, and  incorporated by reference herein]            |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                          |
| 10.12  |   | X      |   |   |   | * Copy of  Non-Qualified Savings Plan covering officers of the Company, effective  January 1, 1992.  [Filed as Exhibit 10.43 to the Company’s Annual  Report on Form 10-K for the year ended December 31, 1992, and  incorporated by reference herein]                                                                                    |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                          |
| 10.13  |   | X      |   | X      |   | Copy of  Modification No. 7 dated January 15, 1992, to Inter-Company Power  Agreement dated July 10, 1953, among Ohio Valley Electric Corporation  and Sponsoring Companies.  [Filed as Exhibit 10.44 to LG&E’s Annual  Report on Form 10-K for the year ended December 31, 1993, and  incorporated by reference herein]         |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                          |
| 10.14  |   | X      |   | X      |   | Copy of  Modification No. 8 dated January 19, 1994, to Inter-Company Power  Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation  and the Sponsoring Companies.  [Filed as Exhibit 10.43 to LG&E’s  Annual Report on Form 10-K for the year ended December 31, 1995, and  incorporated by reference herein]    |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                          |
| 10.15  |   | X      |   | X      |   | Copy of  Modification No. 9, dated August 17, 1995, to the Inter-Company Power  Agreement dated July 10, 1953, among Ohio Valley Electric Corporation  and the Sponsoring Companies.  [Filed as Exhibit 10.39 to LG&E’s  Annual Report on Form 10-K for the year ended December 31, 1996, and  incorporated by reference herein] |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                          |
| 10.16  |   | X      |   | X      |   | *  Copy  of Amendment to the Non-Qualified Savings Plan, effective January 1,  1992.  [Filed as Exhibit 10.55 to LG&E’s Annual Report on Form 10-K  for the year ended                                                                                                                                                                |

 

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|          |   |      |   |      |   |                                                                                                                                                                                                                                                                                                                                                                          |
|---------------|--------|-----------|--------|-----------|--------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|          |   |      |   |      |   | December 31,  1995, and incorporated by reference herein]                                                                                                                                                                                                                                                                                                                |
|          |   |      |   |      |   |                                                                                                                                                                                                                                                                                                                                                                          |
| 10.17         |   | X         |   | X         |   | *  Copy  of Amendment to the Non-Qualified Savings Plan, effective January 1,  1995.  [Filed as Exhibit 10.56 to LG&E’s Annual Report on Form 10-K  for the year ended December 31, 1995, and incorporated by reference  herein]                                                                                                                 |
|          |   |      |   |      |   |                                                                                                                                                                                                                                                                                                                                                                          |
| 10.18         |   | X         |   | X         |   | *  Copy  of Amendment to the Non-Qualified Savings Plan, effective January 1,  1995.  [Filed as Exhibit 10.57 to LG&E’s Annual Report on Form 10-K  for the year ended December 31, 1995, and incorporated by reference  herein]                                                                                                                 |
|          |   |      |   |      |   |                                                                                                                                                                                                                                                                                                                                                                          |
| 10.19         |   | X         |   | X         |   | *  Copy  of Supplemental Executive Retirement Plan as amended through January 1,  1998, covering officers of LG&E Energy.  [Filed as Exhibit 10.74 to  LG&E Energy’s Annual Report on Form 10-K for the year ended  December 31, 1997, and incorporated by reference herein]                                                                 |
|          |   |      |   |      |   |                                                                                                                                                                                                                                                                                                                                                                          |
| 10.20         |   | X         |   | X         |   | *  Copy  of Amendment to LG&E Energy’s Supplemental Executive Retirement Plan,  effective September 2, 1998. [Filed as Exhibit 10.90 to LG&E  Energy’s Annual Report on Form 10-K for the year ended December 31, 1998  and incorporated by reference herein]                                                                                |
|          |   |      |   |      |   |                                                                                                                                                                                                                                                                                                                                                                          |
| 10.21         |   | X         |   | X         |   | * Copy of  Employment and Severance Agreement, dated as of February 25, 2000, by  and among LG&E Energy, Powergen plc and an executive officer of the  Company.  [Filed as Exhibit 10.54 to LG&E’s Annual Report on Form  10-K for the year ended December 31, 2002, and incorporated by reference  herein.]                                      |
|          |   |      |   |      |   |                                                                                                                                                                                                                                                                                                                                                                          |
| 10.22         |   | X         |   | X         |   | * Copy of  Amendment, effective October 1, 1999, to LG&E Energy’s Non-Qualified  Savings Plan. [Filed as Exhibit 10.96 to LG&E’s and KU’s Annual Report on  Form 10-K for the year ended December 31, 1999, and incorporated by  reference herein]                                                                                           |
|          |   |      |   |      |   |                                                                                                                                                                                                                                                                                                                                                                          |
| 10.23         |   | X         |   | X         |   | * Copy of  Amendment, effective December 1, 1999, to LG&E Energy’s  Non-Qualified Savings Plan. [Filed as Exhibit 10.97 to LG&E’s and KU’s  Annual Report on Form 10-K for the year ended December 31, 1999, and  incorporated by reference herein]                                                                                          |
|          |   |      |   |      |   |                                                                                                                                                                                                                                                                                                                                                                          |
| 10.24         |   | X         |   | X         |   | Copy of  Modification No. 10, dated January 1, 1998, to the Inter-Company Power  Agreement dated July 10, 1953, among Ohio Valley Electric Corporation  and the Sponsoring Companies. [Filed as Exhibit 10.102 to LG&E’s and KU’s  Annual Report on Form 10-K for the year ended December 31, 1999, and  incorporated by reference herein]       |
|          |   |      |   |      |   |                                                                                                                                                                                                                                                                                                                                                                          |
|  

10.25 |   |  

X |   |  

X |   |  

Copy of  Modification No. 11, dated April 1, 1999, to the Inter-Company Power  Agreement dated July 10, 1953, among Ohio Valley Electric Corporation  and the Sponsoring Companies. [Filed as Exhibit 10.103 to LG&E’s and KU’s  Annual Report on Form 10-K for the year ended December 31, 1999, and  incorporated by reference herein] |
|          |   |      |   |      |   |                                                                                                                                                                                                                                                                                                                                                                          |
|          |   |      |   |      |   |                                                                                                                                                                                                                                                                                                                                                                          |
| 10.26         |   | X         |   | X         |   | * Copy of  Powergen Short-Term Incentive Plan, effective January 1, 2001,  applicable to certain employees of LG&E Energy Corp. and its  subsidiaries. [Filed as Exhibit 10.109 to LG&E’s Annual Report on Form  10-K for the year ended December 31, 2000, and incorporated herein by  reference]                                                     |
|          |   |      |   |      |   |                                                                                                                                                                                                                                                                                                                                                                          |
| 10.27         |   | X         |   | X         |   | * Copy of  two forms of Change-In-Control Agreement applicable to certain employees of  LG&E Energy Corp. and its subsidiaries. [Filed as Exhibit 10.110 to  LG&E’s Annual Report on Form 10-K for the year ended December 31, 2000,  and incorporated by reference herein]                                                                                      |

 

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|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                          |
|--------|--------|--------|--------|--------|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.28  |   | X      |   | X      |   | * Copy of  Employment and Severance Agreement, dated as of February 25, 2000, and  amendments thereto dated December 8, 2000 and April 30, 2001, by  and among LG&E Energy, Powergen plc and Victor A. Staffieri. [Filed as  Exhibit 10.74 to LG&E’s and KU’s Annual Report on Form 10-K/A for the  year ended December 31, 2001, and incorporated by reference herein] |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                          |
| 10.29  |   | X      |   | X      |   | * Copy of  Amendment, dated as of December 8, 2000, to Employment and Severance  Agreement dated as of February 25, 2000, by and among LG&E Energy,  Powergen plc and an executive officer of the Company. [Filed as Exhibit 10.63  to LG&E’s and KU’s Annual Report on Form 10-K for the year ended  December 31, 2002, and incorporated by reference herein]               |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                          |
| 10.30  |   | X      |   | X      |   | *Copy of  Third Amendment, dated July 1, 2002, to Employment and Severance  Agreement dated as of February 25, 2000 by and among E.ON AG, LG&E  Energy, Powergen and Victor A. Staffieri.  [Filed as Exhibit 10.74 to  LG&E’s and KU’s Annual Report on Form 10-K for the year ended December 31,  2002, and incorporated by reference herein]                          |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                          |
| 10.31  |   | X      |   | X      |   | *Copy of  form of Retention and Severance Agreement dated April/May, 2002 by and among  LG&E Energy, E.ON AG and certain executive officers of the  Companies.  [Filed as Exhibit 10.75 to LG&E’s and KU’s Annual Report  on Form 10-K for the year ended December 31, 2002, and incorporated by  reference herein]                                                               |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                          |
| 10.32  |   | X      |   | X      |   | *Copy of  Second Amendment, dated May 20, 2002, to Employment and Severance Agreement,  dated February 25, 2000, by and among E.ON AG, LG&E Energy Corp.,  Powergen plc and an executive of the Companies.  [Filed as Exhibit 10.76  to LG&E’s and KU’s Annual Report on Form 10-K for the year ended  December 31, 2002, and incorporated by reference herein]              |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                          |
| 10.33  |   | X      |   | X      |   | *Copy of  Terms and Conditions for Stock Options Issued as part of E.ON Group’s Stock  Option Programs, applicable to certain executive officers of the  Companies.  [Filed as Exhibit 10.79 to LG&E’s and KU’s Annual Report  on Form 10-K for the year ended December 31, 2002, and incorporated by  reference herein]                                                         |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                          |
| 10.34  |   | X      |   | X      |   | *Copy of  LG&E Energy Corp. Long-Term Performance Unit Plan, adopted April 25,  2003, effective January 1, 2003. [Filed as Exhibit 10.65 to LG&E and KU’s  Annual Report on Form 10-K for the year ended December 31, 2004, and  incorporated by reference herein]                                                                                                                               |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                          |
| 10.35  |   | X      |   | X      |   | Copy of  Modification No. 12 dated as of November 1, 1999, to Inter-Company Power  Agreement dated July 10, 1953 among Ohio Valley Electric Corporation and  Sponsoring Companies. [Filed as Exhibit 10.69 to LG&E and KU’s Annual  Report on Form 10-K for the year ended December 31, 2004, and incorporated by  reference herein]                                                       |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                          |
| 10.36  |   | X      |   | X      |   | Copy of  Modification No. 13 dated as of May 24, 2000, to Inter-Company Power  Agreement dated July 10, 1953 among Ohio Valley Electric Corporation and  Sponsoring Companies. [Filed as Exhibit 10.70 to LG&E and KU’s Annual  Report on Form 10-K for the year ended December 31, 2004, and incorporated by  reference herein]                                                                |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                          |
| 10.37  |   | X      |   | X      |   | Copy of  Modification No. 14 dated as of April 1, 2001, to Inter-Company Power  Agreement dated July 10, 1953 among Ohio Valley Electric Corporation and  Sponsoring Companies. [Filed as Exhibit 10.71 to LG&E and KU’s Annual  Report on Form 10-K for the year ended December 31, 2004, and incorporated by  reference                                                                  |

 

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|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                         |
|--------|--------|--------|--------|--------|--------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |   |   |   |   | herein]                                                                                                                                                                                                                                                                                                                                      |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                         |
| 10.38  |   |   |   | X      |   | Loan  Agreement dated October 1, 2004 between Kentucky Utilities Company and the  County of Carroll, Kentucky [Filed as Exhibit 10.1 to KU’s Form 8-K filed on  October 22, 2004 and incorporated by reference herein]                                                                                                                  |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                         |
| 10.39  |   | X      |   | X      |   | Copy of  Amended and Restated Inter-company Power Agreement dated as of March 13,  2006, among Ohio Valley Electric Corporation and sponsoring companies,  including LG&E and KU [Filed as Exhibit 10.1 to LG&E and KU’s Form  10-Q for the period ended June 30, 2004 and incorporated by reference herein]                    |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                         |
| 10.40  |   | X      |   | X      |   | *Copy of  Fourth Amendment dated as of February 1, 2004 to Employment and Severance  Agreement dated as of February 25, 2000 by and among E.ON AG, LG&E  Energy, Powergen and Victor A. Staffieri [Filed as Exhibit 10.02 to LG&E  and KU’s Form 10-Q for the period ended June 30, 2004 and incorporated by  reference herein] |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                         |
| 10.41  |   | X      |   | X      |   | Copy of  Modification No. 15, dated as of April 30, 2004, to Inter-Company Power  Agreement dated July 10, 1953 among Ohio Valley Electric Corporation and  Sponsoring Companies [Filed as Exhibit 10.03 to LG&E and KU’s Form 10-Q  for the period ended June 30, 2004 and incorporated by reference herein]                       |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                         |
| 10.42  |   | X      |   |   |   | Participation  Agreement between LG&E and Illinois Municipal Electric Agency, dated as  of September 24, 1990.                                                                                                                                                                                                                           |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                         |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                         |
| 10.43  |   | X      |   |   |   | Participation  Agreement between LG&E and Indiana Municipal Power Agency, dated as of  February 1, 1993.                                                                                                                                                                                                                                 |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                         |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                         |
| 10.44  |   | X      |   | X      |   | Participation  Agreement by and among LG&E and KU and Indiana Municipal Electric Agency  and Indiana Municipal Power Agency, dated as of February 9, 2004.                                                                                                                                                                               |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                         |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                         |
| 10.45  |   | X      |   | X      |   | Copy of  Barge Transportation Agreement  between  LG&E, effective January 1, 2002, and KU, effective July 1, 2002, and  Crounse Corporation.                                                                                                                                                                                        |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                         |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                         |
| 10.46  |   | X      |   | X      |   | * Executive  Officer Salary Information.                                                                                                                                                                                                                                                                                                     |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                         |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                         |
| 10.47  |   | X      |   | X      |   | * Form of  Specimen Award under LG&E Energy Long-Term Performance Unit Plan                                                                                                                                                                                                                                                              |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                         |
| 10.48  |   | X      |   | X      |   | * Form of  Specimen Award under E.ON Group Stock Option Program                                                                                                                                                                                                                                                                              |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                         |
| 12     |   | X      |   | X      |   | Computation  of Ratio of Earnings to Fixed Charges for LG&E and KU.                                                                                                                                                                                                                                                                      |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                         |
| 21     |   | X      |   | X      |   | Subsidiaries  of the Registrants.                                                                                                                                                                                                                                                                                                            |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                         |
| 24     |   | X      |   | X      |   | Powers of  Attorney.                                                                                                                                                                                                                                                                                                                         |

 

175

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|   |   |   |   |   |   |                                                                                                                                   |
|--------|--------|--------|--------|--------|--------|----------------------------------------------------------------------------------------------------------------------------------------|
| 31.1   |   | X      |   |   |   | Certification  of Chief Executive Officer, Pursuant to Section 302 of Sarbanes-Oxley  Act of 2002.                                |
|   |   |   |   |   |   |                                                                                                                                   |
| 31.2   |   | X      |   |   |   | Certification  of Chief Financial Officer, Pursuant to Section 302 of Sarbanes-Oxley  Act of 2002.                                |
|   |   |   |   |   |   |                                                                                                                                   |
| 31.3   |   |   |   | X      |   | Certification  of Chief Executive Officer, Pursuant to Section 302 of Sarbanes-Oxley  Act of 2002.                                |
|   |   |   |   |   |   |                                                                                                                                   |
| 31.4   |   |   |   | X      |   | Certification  of Chief Financial Officer, Pursuant to Section 302 of Sarbanes-Oxley  Act of 2002.                                |
|   |   |   |   |   |   |                                                                                                                                   |
| 32     |   | X      |   | X      |   | Certifications  pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.                                                        |
|   |   |   |   |   |   |                                                                                                                                   |
| 99.01  |   | X      |   | X      |   | Cautionary  Statement for purposes of the “Safe Harbor” provisions of the Private  Securities Litigation Reform Act of 1995. |
|   |   |   |   |   |   |                                                                                                                                   |
| 99.02  |   | X      |   | X      |   | LG&E and  KU Director and Officer Information.                                                                                     |
|        |        |        |        |        |        |                                                                                                                                        |  |  |

 

 

 

        Executive Compensation Plans and Arrangements:

 

Exhibitspreceded by an asterisk (“*”) above are management contracts, compensationplans or arrangements required to be identified pursuant to Item 15(a)(3) ofForm 10-K.

 

        Certain Available Instruments

 

        The followinginstruments defining the rights of holders of certain long-term debt of KU havenot been filed with the Securities and Exchange Commission but will befurnished to the Commission upon request.

 

1.    Loan Agreement dated as of November 1, 1994, between KU and theCounty of Carroll, Kentucky, in connection with $54,000,000 County of Carroll,Kentucky, Collateralized Solid Waste Disposal Facilities Revenue Bonds (KUProject) 1994 Series A, due November 1,  2024.

 

 

 

 

176

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| Louisville Gas and Electric Company              |   | Schedule II |
|--------------------------------------------------|--------|-------------|
| Schedule II - Valuation and Qualifying  Accounts |   |        |
| For the Three Years Ended December 31, 2004      |   |        |
| (Thousands of $)                                 |   |        |

 
| ** **                                             | ** ** | **Other  Property  and  Investments** | ** ** | **Accounts  Receivable  (Uncollectible  Accounts)** | ** ** |
|--------------------------------------------------------|------------|---------------------------------------|------------|-----------------------------------------------------|------------|
|                                                   |       |                                  |       |                                                |       |
| Balance December 31, 2001                              |       | $                                     | 63         |                                                | $          | 1,575 |   |
|                                                   |       |                                  |       |                                                |       |
| Additions:                                             |       |                                  |       |                                                |       |
| Charged to costs and expenses                          |       | —                                |       | 4,459                                               |       |
|                                                   |       |                                  |       |                                                |       |
| Deductions:                                            |       |                                  |       |                                                |       |
| Net charges of nature for which reserves  were created |       | —                                |       | 3,909                                               |       |
|                                                   |       |                                  |       |                                                |       |
| Balance December 31, 2002                              |       | 63                                    |       | 2,125                                               |       |
|                                                   |       |                                  |       |                                                |       |
| Additions:                                             |       |                                  |       |                                                |       |
| Charged to costs and expenses                          |       | —                                |       | 5,477                                               |       |
|                                                   |       |                                  |       |                                                |       |
| Deductions:                                            |       |                                  |       |                                                |       |
| Net charges of nature for which reserves  were created |       | —                                |       | 4,087                                               |       |
|                                                   |       |                                  |       |                                                |       |
| Balance December 31, 2003                              |       | 63                                    |       | 3,515                                               |       |
|                                                   |       |                                  |       |                                                |       |
| Additions:                                             |       |                                  |       |                                                |       |
| Charged to costs and expenses                          |       | —                                |       | 1,908                                               |       |
|                                                   |       |                                  |       |                                                |       |
| Deductions:                                            |       |                                  |       |                                                |       |
| Net charges of nature for which reserves  were created |       | —                                |       | 4,638                                               |       |
|                                                   |       |                                  |       |                                                |       |
| Balance December 31, 2004                              |       | $                                     | 63         |                                                | $          | 785 |   |

 

177

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| Kentucky Utilities Company                       |   | Schedule II |
|--------------------------------------------------|--------|-------------|
| Schedule II - Valuation and Qualifying  Accounts |   |        |
| For the Three Years Ended December 31, 2004      |   |        |
| (Thousands of $)                                 |   |        |

 
| ** **                                             | ** ** | **Other  Property  and  Investments** | ** ** | **Accounts  Receivable  (Uncollectible  Accounts)** | ** ** |
|--------------------------------------------------------|------------|---------------------------------------|------------|-----------------------------------------------------|------------|
|                                                   |       |                                  |       |                                                |       |
| Balance December 31, 2001                              |       | $                                     | 130        |                                                | $          | 800 |   |
|                                                   |       |                                  |       |                                                |       |
| Additions:                                             |       |                                  |       |                                                |       |
| Charged to costs and expenses                          |       | —                                |       | 1,314                                               |       |
| Deductions:                                            |       |                                  |       |                                                |       |
| Net charges of nature for which reserves  were created |       | —                                |       | 1,314                                               |       |
|                                                   |       |                                  |       |                                                |       |
| Balance December 31, 2002                              |       | 130                                   |       | 800                                                 |       |
|                                                   |       |                                  |       |                                                |       |
| Additions:                                             |       |                                  |       |                                                |       |
| Charged to costs and expenses                          |       | —                                |       | 1,492                                               |       |
|                                                   |       |                                  |       |                                                |       |
| Deductions:                                            |       |                                  |       |                                                |       |
| Net charges of nature for which reserves  were created |       | —                                |       | 1,620                                               |       |
|                                                   |       |                                  |       |                                                |       |
| Balance December 31, 2003                              |       | 130                                   |       | 672                                                 |       |
|                                                   |       |                                  |       |                                                |       |
| Additions:                                             |       |                                  |       |                                                |       |
| Charged to costs and expenses                          |       | 1                                     |       | 1,247                                               |       |
|                                                   |       |                                  |       |                                                |       |
| Deductions:                                            |       |                                  |       |                                                |       |
| Net charges of nature for which reserves  were created |       | —                                |       | 1,296                                               |       |
|                                                   |       |                                  |       |                                                |       |
| Balance December 31, 2004                              |       | $                                     | 131        |                                                | $          | 623 |   |

 

178

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**SIGNATURES**– LOUISVILLE GAS AND ELECTRIC COMPANY

 

Pursuant to the requirements of Section 13 or15(d) of the Securities Exchange Act of 1934, the registrant has duly causedthis report to be signed on its behalf by the undersigned, thereunto dulyauthorized.

 
|           |   | LOUISVILLE GAS AND ELECTRIC COMPANY |
|----------------|--------|-------------------------------------|
|           |   | Registrant                          |
|           |   |                                |
| March 30, 2005 |   | /s/ S. Bradford Rives               |   |
| (Date)         |   | S. Bradford Rives                   |
|           |   | Chief Financial Officer             |

 

 

Pursuant to the requirements of theSecurities Exchange Act of 1934, this report has been signed below by thefollowing persons on behalf of the registrant and in the capacities and on thedate indicated.

 
| **Signature**       | ** ** | **Title**                                                       | ** ** | **Date** |
|---------------------|------------|-----------------------------------------------------------------|------------|----------|
|                |       |                                                            |       |     |
| Victor A. Staffieri |       | Chairman of the Board,                                          |       |     |
|                |       | President and Chief Executive Officer                           |       |     |
|                |       | (Principal Executive Officer);                                  |       |     |
|                |       |                                                            |       |     |
| S. Bradford Rives   |       | Director and Chief Financial Officer                            |       |     |
|                |       | (Principal Financial Officer and Principal Accounting Officer); |       |     |
|                |       |                                                            |       |     |
| John R. McCall      |       | Director and Executive Vice President,                          |       |     |
|                |       | General Counsel and Corporate Secretary                         |       |     |
|                |       |                                                            |       |     |
| Chris Hermann       |       | Director and Senior Vice President, Energy Delivery             |       |     |
|                |       |                                                            |       |     |
| Paul W. Thompson    |       | Director and Senior Vice President, Energy Services             |       |     |

 

 
| By     | /s/ S. Bradford Rives |   | March 30, 2005 |
|--------|-----------------------|--------|----------------|
|   | (Attorney-In-Fact)    |   |

 

179

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SIGNATURES –KENTUCKY UTILITIES COMPANY

 

Pursuant to the requirements of Section 13 or15(d) of the Securities Exchange Act of 1934, the registrant has duly causedthis report to be signed on its behalf by the undersigned, thereunto dulyauthorized.

 
|                | KENTUCKY UTILITIES COMPANY |
|---------------------|----------------------------|
|                | Registrant                 |
|                |                       |
| March 30, 2005 | /s/ S. Bradford Rives      |   |
| (Date)              | S. Bradford Rives          |
|                | Chief Financial Officer    |

 

 

Pursuant to the requirements of theSecurities Exchange Act of 1934, this report has been signed below by thefollowing persons on behalf of the registrant and in the capacities and on thedate indicated.

 
| **Signature**       | ** ** | **Title**                                                       | ** ** | **Date** |
|---------------------|------------|-----------------------------------------------------------------|------------|----------|
|                |       |                                                            |       |     |
| Victor A. Staffieri |       | Chairman of the Board,                                          |       |     |
|                |       | President and Chief Executive Officer                           |       |     |
|                |       | (Principal Executive Officer);                                  |       |     |
|                |       |                                                            |       |     |
| S. Bradford Rives   |       | Director and Chief Financial Officer                            |       |     |
|                |       | (Principal Financial Officer and Principal Accounting Officer); |       |     |
|                |       |                                                            |       |     |
| John R. McCall      |       | Director and Executive Vice President,                          |       |     |
|                |       | General Counsel and Corporate Secretary                         |       |     |
|                |       |                                                            |       |     |
| Chris Hermann       |       | Director and Senior Vice President, Energy Delivery             |       |     |
|                |       |                                                            |       |     |
| Paul W. Thompson    |       | Director and Senior Vice President, Energy Services             |       |     |

 

 
| By     | /s/ S. Bradford Rives |   | March 30, 2005 |
|--------|-----------------------|--------|---------------------|
|   | (Attorney-In-Fact)    |   |

 

180

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