**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

**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, 2005** |
|                                                  |   |   |
| **OR**                                                |
|                                                  |   |   |
| **o**                                                 | ** ** | **TRANSITION REPORT PURSUANT TO SECTION 13 OR  15(d) OF THE** |
| ** **                                            | ** ** | **SECURITIES EXCHANGE ACT OF 1934 (NO FEE  REQUIRED)** |

 
| **Commission**  | ** ** | **Registrant, State of Incorporation,**                                | ** ** | **IRS Employer**          |
|-----------------|------------|------------------------------------------------------------------------|------------|---------------------------|
| **File Number** | ** ** | **Address, and Telephone Number**                                      | ** ** | **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** |
|                                                               |
| **Kentucky  Utilities Company**                                    |
| **none**                                                           |

 

Indicate by check mark if the registrant is a well-known seasonedissuer, as defined in Rule 405 of the Securities Act. Yes  o    No  ý

 

Indicate by check mark if the registrant is not required to filereports pursuant to Section 13 or Section 15(d) of the Act. Yes  o    No  ý

 

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) havebeen subject 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 orany amendment to this Form 10-K. ý

 

Indicate by check mark whether the registrant is a large acceleratedfiler, an accelerated filer, or a non-accelerated filer. See definition of “acceleratedfiler and large accelerated filer” in Rule 12-b2 of the Exchange Act. (Checkone):

 
| Large accelerated filer  o | Accelerated filer  o | Non-accelerated filer   ý |
|--------------------------------------|--------------------------------|------------------------------------------|

 

Indicate by check mark whether the registrant is a shell company (asdefined in Exchange Act Rule 12b-2). Yes  o    No  ý

 

As of June 30, 2005, 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, 2006, LouisvilleGas and Electric Company had 21,294,223 shares of common stock outstanding, allheld by E.ON U.S. LLC. Kentucky Utilities Company had 37,817,878 shares ofcommon stock outstanding, all held by E.ON U.S. LLC.

 

This combined Form 10-K is separately filed by Louisville Gas andElectric Company and Kentucky Utilities Company. Information contained hereinrelated to any individual registrant is filed by such registrant on its ownbehalf. Each registrant makes no representation as to information relating tothe other registrant.

 

DOCUMENTSINCORPORATED BY REFERENCE

 

Not applicable.

 

 

----

 

**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                                                                                          |   |
|          | Executive Officers of the Companies                                                                                    |   |
| Item 1A.      | Risk Factors                                                                                                           |   |
| Item 1B.      | Unresolved Staff Comments                                                                                              |   |
| 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  LG&E and KU                                                                   |   |
| Item 11.      | Executive Compensation                                                                                                 |   |
| Item 12.      | Security Ownership of Certain Beneficial  Owners and Management and Related Stockholder Matters                        |   |
| Item 13.      | Certain Relationships and Related Transactions                                                                         |   |
| Item 14.      | Principal Accountant Fees and Services                                                                                 |   |
|          |                                                                                                                   |   |
| PART IV  |                                                                                                                   |
|          |                                                                                                                   |   |
| Item 15.      | Exhibits and Financial Statement Schedules                                                                             |   |
| Signatures    |                                                                                                                   |

 

----

 

INDEX OF ABBREVIATIONS

 
| AEP                 |   | American Electric Power Company, Inc.                               |
|---------------------|--------|--------------------------------------------------------------------------|
| AFUDC               |   | Allowance for Funds Used During  Construction                            |
| AG                  |   | Attorney General of Kentucky                                             |
| APBO                |   | Accumulated Postretirement  Benefit Obligation                           |
| ARO                 |   | Asset Retirement Obligation                                              |
| CAIR                |   | Clean Air Interstate Rule                                                |
| CAMR                |   | Clean Air Mercury Rule                                                   |
| Capital Corp.       |   | E.ON U.S. Capital Corp.  (formerly LG&E Capital Corp.)               |
| CAVR                |   | Clean Air Visibility Rule                                                |
| Clean Air Act       |   | The Clean Air Act, as amended  in 1990                                   |
| CCN                 |   | Certificate of Public  Convenience and Necessity                         |
| CO2                 |   | Carbon Dioxide                                                           |
| Company             |   | LG&E or KU, as applicable                                            |
| Companies           |   | LG&E and KU                                                          |
| CT                  |   | Combustion Turbines                                                      |
| CWIP                |   | Construction Work in Progress                                            |
| DOE                 |   | Department of Energy                                                     |
| DOJ                 |   | Department of Justice                                                    |
| 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                                                                  |
| E.ON U.S.           |   | E.ON U.S. LLC. (formerly  LG&E Energy LLC and LG&E Energy Corp.) |
| E.ON U.S. Services  |   | E.ON U.S. Services Inc.  (formerly LG&E Energy Services Inc.)        |
| EPA                 |   | U.S. Environmental Protection  Agency                                    |
| EPAct 2005          |   | Energy Policy Act of 2005                                                |
| ERISA               |   | Employee Retirement Income  Security Act of 1974, as amended             |
| ESM                 |   | Earnings Sharing Mechanism                                               |
| Fidelia             |   | Fidelia Corporation (an E.ON  affiliate)                                 |
| FAC                 |   | Fuel Adjustment Clause                                                   |
| FASB                |   | Financial Accounting Standards  Board                                    |
| FERC                |   | Federal Energy Regulatory  Commission                                    |
| FGD                 |   | Flue Gas Desulfurization                                                 |
| FIN                 |   | FASB Interpretation                                                      |
| FPA                 |   | Federal Power Act                                                        |
| FGD                 |   | Flue Gas Desulfurization                                                 |
| FIN                 |   | FASB Interpretation                                                      |
| FPA                 |   | Federal Power Act                                                        |
| FSP                 |   | FASB Staff Position                                                      |
| FT and FT-A         |   | Firm Transportation                                                      |
| FTR                 |   | Financial Transmission Right                                             |
| GSC                 |   | Gas Supply Clause                                                        |
| GFA                 |   | Grandfathered Transmission  Agreement                                    |
| IBEW                |   | International Brotherhood of  Electrical Workers                         |
| IMEA                |   | Illinois Municipal Electric  Agency                                      |
| IMPA                |   | Indiana Municipal Power Agency                                           |
| IRC                 |   | Internal Revenue Code of 1986,  as amended                               |
| IRP                 |   | Integrated Resource Plan                                                 |
| ITP                 |   | Independent Transmission Provider                                        |
| 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                                                                |
| 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 (now E.ON  U.S. LLC)                     |
|---------------------|--------|--------------------------------------------------------------|
| LG&E R          |   | LG&E Receivables LLC                                     |
| LG&E Services   |   | LG&E Energy Services Inc.  (now E.ON U.S. Services Inc.) |
| LMP                 |   | Locational Marginal Pricing                                  |
| LNG                 |   | Liquefied Natural Gas                                        |
| Mcf                 |   | Thousand Cubic Feet                                          |
| MGP                 |   | Manufactured Gas Plant                                       |
| MISO                |   | Midwest Independent  Transmission System Operator, Inc. |
| MMBtu               |   | Million British thermal units                                |
| Moody’s        |   | Moody’s Investor Services, Inc.                    |
| Mva                 |   | Megavolt-ampere                                              |
| 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 1935          |   | Public Utility Holding Company Act of 1935                   |
| PUHCA 2005          |   | Public Utility Holding Company Act of 2005                   |
| ROE                 |   | Return on Equity                                             |
| RTO                 |   | Regional Transmission  Organization                          |
| RTOR                |   | Regional Through and Out Rates                               |
| 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                                               |
| SPP                 |   | Southwest Power Pool, Inc.                              |
| TEMT                |   | Transmission and Energy Markets  Tariff                      |
| Tennessee Gas       |   | Tennessee Gas Pipeline Company                               |
| Texas Gas           |   | Texas Gas Transmission LLC                                   |
| Trimble County      |   | LG&E’s Trimble County Unit  1                       |
| TVA                 |   | Tennessee Valley Authority                                   |
| 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                            |

 

----

 

# **PART I**

 

## Item 1. Business.

 

LG&E andKU are each subsidiaries of E.ON U.S. LLC (E.ON U.S.). Prior to December 1,2005, E.ON U.S. LLC was known as LG&E Energy LLC. Previously, effective December 30,2003, LG&E Energy LLC had become the successor, by assignment andsubsequent merger, to all the assets and liabilities of LG&E Energy Corp.E.ON U.S. is a subsidiary of E.ON AG (E.ON), a German corporation. E.ONacquired LG&E Energy through its July 1, 2002 acquisition of Powergenplc, now Powergen Limited (Powergen), a United Kingdom company and holdingcompany for E.ON UK plc, E.ON’s United Kingdom market unit operating parent. Ascontemplated in their regulatory filings in connection with the E.ONacquisition, E.ON, Powergen and E.ON U.S. completed an administrative reorganizationto move the E.ON U.S. group from an indirect Powergen subsidiary to an indirectE.ON subsidiary. This reorganization was effective in March 2003. In early2004, E.ON U.S. began direct reporting arrangements to E.ON.

 

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

 

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

 

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

 

The utility operations (LG&E and KU) of E.ON U.S. have continuedtheir separate identities as LG&E and KU. The preferred stock and debtsecurities of LG&E and KU were not affected by these transactions.

 

1

----

 

LOUISVILLE GAS AND ELECTRIC COMPANY

 

General

 

LG&E, incorporated in 1913 in Kentucky, is a regulated publicutility that supplies natural gas to approximately 321,000 customers andelectricity to approximately 394,000 customers in Louisville and adjacent areasin Kentucky. LG&E’s service area covers approximately 700 square miles in17 counties and has an estimated population of one million. Included in thisarea is the Fort Knox Military Reservation, to which LG&E transportsnatural gas and provides electric service, but does not provide anydistribution services. LG&E also provides natural gas service in limitedadditional areas. LG&E’s coal-fired electric generating plants, allequipped with systems to reduce SO2 emissions, produce most ofLG&E’s electricity. The remainder is generated by a hydroelectric powerplant and combustion turbines. Underground natural gas storage fields helpLG&E provide economical and reliable natural gas service to customers. SeeItem 2, Properties.

 

Operating Revenues

 

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

 
| **(in millions)**   | ** ** | **Electric** | ** ** | **Gas** | ** ** | **Combined** | ** ** | **% Combined** | ** ** |
|---------------------|------------|--------------|------------|---------|------------|--------------|------------|----------------|------------|
| Residential         |       | $            | 276        |    | $          | 265          |       | $              | 541        |   | 49 | % |
| Commercial          |       | 221          |       | 108     |       | 329          |       | 30             | %          |
| Industrial          |       | 128          |       | 19      |       | 147          |       | 13             | %          |
| Public  authorities |       | 66           |       | 19      |       | 85           |       | 8              | %          |
| Total retail        |       | 691          |       | 411     |       | 1,102        |       | 100            | %          |
| Wholesale  sales    |       | 259          |       | 19      |       | 278          |       |           |       |
| Gas  transported    |       | —       |       | 5       |       | 5            |       |           |       |
| Miscellaneous       |       | 37           |       | 2       |       | 39           |       |           |       |
| Total               |       | $            | 987        |    | $          | 437          |       | $              | 1,424      |   |   |   |

 

See Note 12 of LG&E’s Notes to Financial Statements under Item 8for financial information concerning segments of business for the three yearsended December 31, 2005.

 

Electric Operations

 

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

 
| **(in millions)**                         | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|-------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| ELECTRIC OPERATING  REVENUES              |       |     |       |     |       |     |       |
| Residential                               |       | $        | 276        |     | $          | 241      |       | $ | 223 |   |
| Commercial                                |       | 221      |       | 202      |       | 188      |       |
| Industrial                                |       | 128      |       | 120      |       | 112      |       |
| Public  authorities                       |       | 66       |       | 62       |       | 58       |       |
| Total retail                              |       | 691      |       | 625      |       | 581      |       |
| Wholesale  sales                          |       | 259      |       | 185      |       | 170      |       |
| Provision  for rate collections (refunds) |       | —   |       | (11      | )          | (1       | )          |
| Miscellaneous                             |       | 37       |       | 17       |       | 18       |       |
| Total                                     |       | $        | 987        |     | $          | 816      |       | $ | 768 |   |

 

2

----

 
| **(Thousands of Mwh)** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
|------------------------|------------|------------|------------|------------|------------|------------|------------|
| ELECTRIC  SALES        |       |       |       |       |       |       |       |
| Residential            |       | 4,265      |       | 3,923      |       | 3,835      |       |
| Commercial             |       | 3,682      |       | 3,534      |       | 3,482      |       |
| Industrial             |       | 3,077      |       | 3,019      |       | 2,936      |       |
| Public  authorities    |       | 1,268      |       | 1,248      |       | 1,251      |       |
| Total retail           |       | 12,292     |       | 11,724     |       | 11,504     |       |
| Wholesale  sales       |       | 8,704      |       | 7,819      |       | 7,678      |       |
| Total                  |       | 20,996     |       | 19,543     |       | 19,182     |       |

 

LG&E set an annual peak load of 2,754 Mw on July 25, 2005,when the temperature reached 98 degrees Fahrenheit in Louisville. This was thehighest hourly customer demand in LG&E’s history.

 

The electric utility business is affected by seasonal weather patterns.As a result, operating revenues (and associated operating expenses) are notgenerated evenly throughout the year. See LG&E’s Results of Operationsunder Item 7.

 

LG&E and KU currently maintain a 12% - 14% reserve margin range. AtDecember 31, 2005, LG&E owned steam and combustion turbine generatingfacilities with a net summer capability of 3,105 Mw and an 80 Mwnameplate-rated hydroelectric facility on the Ohio River with a net summercapability of 48 Mw. See Item 2, Properties. LG&E also obtains power fromother utilities under bulk power purchase and interchange contracts. At December 31,2005, LG&E’s system net summer capability, including purchases from othersand excluding the hydroelectric facility, was 3,259 Mw.

 

LG&E uses efficient coal-fired boilers, fully equipped with SO2 removal systems,to generate most of its electricity. LG&E’s weighted-average system-wideemission rate for SO2 in 2005 was approximately 0.54 lbs./MMBtu ofheat input, with every generating unit below its emission limit established bythe Kentucky Division for Air Quality.

 

LG&E and11 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 owns 5.63% of OVEC’s common stock. Through March 2006,LG&E is entitled to receive 7% of OVEC’s output, and thereafter is entitledto receive 5.63%, representing approximately 124 Mw. In April 2004, OVECand its shareholders, including LG&E and KU, entered into an Amended andRestated Inter-Company Power Agreement, to be effective beginning March 2006,upon the expiration of the current power contract among the parties. Theparties received SEC approval under PUHCA 1935 of the Amended and RestatedInter-Company Power Agreement in February 2005.

 

LG&E is a member of the MISO, a non-profit independent transmissionsystem operator that serves the electrical transmission needs of much of theMidwest. Membership was obtained when the MISO was formed in 1998 in responseto and consistent with federal energy policy initiatives at that time. The MISObegan commercial operations in February 2002. As a result, LG&E turnedover operational control of its 100 Kv and above transmission facilities, butcontinues to control and operate the lower voltage transmission system subjectto the terms and conditions of the MISO. As a transmission-owning member of theMISO, LG&E incurs costs under the MISO OATT. In April 2005, the MISOimplemented its day-ahead real-time market (MISO Day 2), including a congestionmanagement system. At the present time, LG&E is involved in regulatoryproceedings at the Kentucky Commission and the FERC seeking authority to exitthe MISO. On March 17, 2006, the FERC issued an order conditionally approvingthe request of LG&E and KU to exit the MISO. For further discussion, seeNote 16 of LG&E’s Notes to Financial Statements under Item 8.

 

3

----

 

Gas Operations

 

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

 
| **(in millions)**         | ** ** | **2005**   | ** ** | **2004**   | ** ** | **2003**   | ** ** |
|---------------------------|------------|------------|------------|------------|------------|------------|------------|
| GAS  OPERATING REVENUES   |       |       |       |       |       |       |       |
| Residential               |       | $          | 265        |       | $          | 223        |       | $ | 199 |   |
| Commercial                |       | 108        |       | 89         |       | 78         |       |
| Industrial                |       | 19         |       | 15         |       | 14         |       |
| Public  authorities       |       | 19         |       | 15         |       | 14         |       |
| Total retail              |       | 411        |       | 342        |       | 305        |       |
| Wholesale  sales          |       | 19         |       | 7          |       | 12         |       |
| Gas  transported          |       | 5          |       | 6          |       | 6          |       |
| Miscellaneous             |       | 2          |       | 2          |       | 2          |       |
| Total                     |       | $          | 437        |       | $          | 357        |       | $ | 325 |   |
|                      |       |       |       |       |       |       |       |
| **(Millions of cu. ft.)** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| GAS SALES                 |       |       |       |       |       |       |       |
| Residential               |       | 20,801     |       | 21,402     |       | 23,192     |       |
| Commercial                |       | 9,131      |       | 9,144      |       | 9,652      |       |
| Industrial                |       | 1,711      |       | 1,736      |       | 1,880      |       |
| Public  authorities       |       | 1,574      |       | 1,646      |       | 1,746      |       |
| Total retail              |       | 33,217     |       | 33,928     |       | 36,470     |       |
| Wholesale  sales          |       | 2,652      |       | 1,221      |       | 2,119      |       |
| Gas  transported          |       | 12,549     |       | 13,692     |       | 13,683     |       |
| Total                     |       | 48,418     |       | 48,841     |       | 52,272     |       |

 

The natural gas utility business is affected by seasonal weatherpatterns. As a result, operating revenues (and associated operating expenses)are not generated evenly throughout the year. While natural gas usage patternsare seasonal, LG&E received approval from the Kentucky Commission for a WNAmechanism. The WNA mechanism adjusts the distribution cost recovery componentof the natural gas billings of residential and commercial customers to normaltemperatures during the heating season months of November through April,somewhat mitigating the effect of weather extremes. LG&E requested, and theKentucky Commission approved, an extension of the current WNA mechanism throughApril 30, 2006. LG&E expects to file for another extension of the WNAbefore the next heating season begins in November 2006. See LG&E’sResults of Operations under Item 7.

 

LG&E has five underground natural gas storage fields that helpprovide economical and reliable natural gas service to ultimate consumers. Byusing natural gas storage facilities, LG&E avoids the costs associated withtypically more expensive pipeline transportation capacity to serve peak winterspace-heating loads. LG&E stores natural gas in the summer season forwithdrawal in the subsequent winter heating season. Without its storagecapacity, LG&E would be forced to buy additional natural gas and pipelinetransportation services during the winter months when customer demand increasesand when the prices for natural gas supply and transportation services aretypically at their highest. Currently, LG&E buys competitively pricednatural gas from several large suppliers under contracts of varying duration. LG&E’sunderground storage facilities, in combination with its purchasing practices,enable it to offer natural gas sales service at rates generally lower thanstate and national averages. At December 31, 2005, LG&E had aninventory balance of gas stored underground of approximately 12.1 million Mcfof working gas valued at approximately $124.9 million.

 

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A number of industrial customers purchase their natural gasrequirements directly from alternate suppliers for delivery through LG&E’sdistribution system. These large industrial customers account for approximatelyone-fourth of LG&E’s annual throughput.

 

During 2005, the maximum daily gas sendout was approximately 444,000Mcf, occurring on January 17, 2005, when the average temperature for theday was 16 degrees Fahrenheit. Supply on that day consisted of approximately221,000 Mcf from purchases, approximately 166,000 Mcf delivered fromunderground storage, and approximately 57,000 Mcf transported for industrialcustomers. For a further discussion, see Gas Supply under Item 1.

 

Rates and Regulation

 

Historically, E.ON, LG&E’s ultimate parent, has been a registeredholding company under PUHCA 1935, and anticipates registering under PUHCA 2005.As a registered holding company, E.ON, its utility subsidiaries, includingLG&E, and certain of its non-utility subsidiaries have been subject toextensive regulation by the SEC and the FERC with respect to numerous matters,including: electric utility facilities and operations, wholesale sales of powerand related transactions, accounting practices, issuances and sales ofsecurities, acquisitions and sales of utility properties, payments of dividendsout of capital and surplus, financial matters and inter-system sales ofnon-power goods and services. In addition, PUHCA 2005 generally limited 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 believes that it has adequateauthority (including financing authority) under existing FERC orders andregulations to conduct its business and will seek additional authorization whennecessary.

 

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

 

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

 

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 to examine the rates LG&E chargesits retail customers at any time.

 

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 thisservice territory, each such supplier has the exclusive right to render retailelectric service.

 

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LG&E’s retail electric rates contain an FAC, whereby increases anddecreases in the cost of fuel for electric generation are reflected in therates charged to retail electric customers. The Kentucky Commission requirespublic hearings 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. TheKentucky Commission also requires that electric utilities, including LG&E,file documents relating to fuel procurement and the purchase of power andenergy from other utilities.

 

Prior to 2004, LG&E’s retail electric rates were subject to an ESM.LG&E and the Kentucky Commission agreed to a termination of the ESMrelating to all periods after 2003. The ESM, initially in place for three yearsbeginning in 2000, set an upper (12.5%) and lower (10.5%) limit for rate ofreturn on equity. If earnings were above the upper limit, the excess earningswere shared 40% with ratepayers and 60% with shareholders; if earnings werebelow the lower limit, the earnings deficiency was recovered 40% fromratepayers 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. For discussion of currentESM matters, see Note 3 of LG&E’s Notes to Financial Statements under Item8.

 

In June 2001, LG&E filed an application (“VDT case”) with theKentucky Commission to create a regulatory asset relating to first quarter 2001charges for a workforce reduction program. In December 2001, the KentuckyCommission approved a settlement in the VDT case and allowed LG&E to set upa regulatory asset of $141 million for the workforce reduction costs and beginamortizing these costs over a five year period starting in April 2001. Thesettlement reduced revenues by approximately $26 million through a surcredit onbills to ratepayers over the same five-year period. The surcredit representednet savings stipulated by LG&E. For discussion of current VDT matters, seeNote 3 and Note 16 of LG&E’s Notes to Financial Statements under Item 8.

 

LG&E’s retail rates contain an ECR surcharge which recovers costsincurred by LG&E that are required to comply with the Clean Air Act andother environmental regulations. See Note 3 of LG&E’s Notes toFinancial Statements under Item 8.

 

LG&E’s natural gas rates contain a GSC, whereby increases ordecreases in the cost of natural gas supply are reflected in LG&E’s rates,subject to approval by the Kentucky Commission. The GSC procedure prescribed byorder of the Kentucky Commission provides for quarterly rate adjustments toreflect the expected cost of natural gas supply in that quarter. In addition,the GSC contains a mechanism whereby any over- or under-recoveries of naturalgas supply cost from prior quarters is to be refunded to or recovered fromcustomers through the adjustment factor determined for subsequent quarters. Inlate 2005, as wholesale natural gas prices began to decrease, a monthlyadjustment in the GSC was requested by LG&E and approved by the KentuckyCommission to pass the lower natural gas costs to the customers on a moretimely basis.

 

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,capacity margins and demand-side management techniques. LG&E filed its mostrecent IRP in April 2005. The AG and KIUC were granted intervention in theIRP proceeding. The Kentucky Commission issued its staff report on February 15,2006, with no substantive issues noted and closed the case by Order dated February 24,2006.

 

In December 2003, LG&E filed an application with the KentuckyCommission requesting adjustments in LG&E’s electric and natural gas rates.LG&E asked for general adjustments in electric and natural gas rates basedon the twelve month test period ended September 30, 2003. The revenueincreases requested were

 

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approximately $64 million for electric and $19 million for gas. In June 2004,the Kentucky Commission issued an order approving increases in LG&E’sannual electric base rates of approximately $43 million (7.7%) and annual gasbase rates of approximately $12 million (3.4%). The rate increases took effecton July 1, 2004.

 

Subsequentlyduring 2004 and 2005, the AG conducted an investigation regarding theproceedings resulting in the rate increases. The AG requested information fromLG&E and the Kentucky Commission and its staff regarding alleged impropercommunications between LG&E and the Kentucky Commission related to the rateproceedings. The AG also requested rehearing of the rate increase orders on thebasis of these allegations, as well as calculational aspects of the increasedrates. In February 2005, the AG submitted a confidential report on itsinvestigation with the Kentucky Commission and filed a motion summarizing thereport as containing evidence of improper communications and record-keepingerrors by LG&E in respect of its activities with state governmentalagencies, including the Kentucky Commission.

 

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

 

For a further discussion of regulatory matters, see Note 3 of LG&E’sNotes to Financial 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 natural gas needsof its service area. These needs are continually being reassessed andappropriate revisions are made, when necessary, in construction schedules. LG&E’sestimates of its construction expenditures can vary substantially due tonumerous items beyond LG&E’s control, such as changes in interest rates,economic conditions, construction costs, and new environmental or othergovernmental laws and regulations.

 

During the five years ended December 31, 2005, gross propertyadditions amounted to approximately $1 billion. Internally generated funds andexternal financings for the five-year period were utilized to provide for thesegross additions. The gross additions during this period amounted toapproximately 24% of total utility plant at December 31, 2005, andconsisted of $807 million for electric properties and $164 million for naturalgas properties. Gross retirements during the same period were $108 million,consisting of $81 million for electric properties and $27 million for naturalgas properties.

 

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

 

Coal Supply

 

Coal-fired generating units provided approximately 97% of LG&E’snet kilowatt-hour generation for 2005.

 

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The remaining net generation for 2005 was provided by natural gas andoil-fueled combustion turbine peaking units  and a hydroelectric plant. Coal is expected tobe the predominant fuel used by LG&E in the foreseeable future, withnatural gas and oil being used for peaking capacity and flame stabilization incoal-fired boilers or in emergencies. LG&E has no nuclear generating unitsand has 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 generating units. Reliabilityof coal deliveries can be affected from time to time by a number of factors,including fluctuations in demand, coal mine production issues and othersupplier or transporter operating difficulties.

 

LG&E has entered into coal supply agreements with various suppliersfor coal deliveries for 2006 and beyond and normally augments its coal supplyagreements with spot market purchases. LG&E has a coal inventory policywhich it believes provides adequate protection under most contingencies. It hada coal inventory of approximately 1.1 million tons, or a 50-day supply, on handat December 31, 2005.

 

LG&E expects to continue purchasing most of its coal, which has asulfur content in the 2% - 4.5% range, from western Kentucky, southern Indiana,southern Illinois, Ohio and West Virginia for the foreseeable future. Thissupply is relatively low-priced coal, and in combination with its sulfurdioxide removal systems, is expected to enable LG&E to continue to provideelectric 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:

 
| ** **                          | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|-------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Per ton                             |       | $        | 30.37      |     | $          | 26.25    |       | $ | 25.56 |   |
| Per MMBtu                           |       | $        | 1.32       |     | $          | 1.15     |       | $ | 1.12 |   |
| Spot  purchases as % of all sources |       | 14       | %          | 7        | %          | 1        | %          |

 

The delivered cost of coal is expected to increase in 2006 due to thestart of new contracts for 2006 and market conditions. LG&E increased spotpurchases in 2005 and 2004 due to supply and transportation issues in themarket.

 

Gas Supply

 

LG&E purchases natural gas supplies from multiple sources undercontracts for varying periods of time, while transportation services arepurchased from Texas Gas and Tennessee Gas.

 

LG&E transports natural gas on the Texas Gas system under RateSchedules NNS and FT service. Effective November 1, 2005, LG&E’swinter season NNS levels are 184,900 MMBtu/day and its winter season FT levelsare 36,000 MMBtu/day. LG&E’s summer season NNS levels are 60,000 MMBtu/dayand its summer season FT levels are 36,000 MMBtu/day. LG&E provided TexasGas with notice to terminate a portion of its FT agreement in the amount of8,000 MMBtu/day effective November 1, 2006. As a result, LG&E willhave FT service in the amount of 28,000 MMBtu/day, effective November 1,2006. Each of the NNS agreements with Texas Gas is subject to termination byLG&E in equal portions during 2008, 2010 and 2011. Each of the FT

 

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agreements with Texas Gas is subject to termination by LG&E during2008 and 2011. LG&E also transports on the Tennessee Gas system underTennessee Gas’ Rate Schedule FT-A. LG&E’s contract levels withTennessee Gas are 51,000 MMBtu/day throughout the year. The FT-A agreement withTennessee Gas is subject to termination by LG&E during 2007.

 

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

 

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

 

LG&E owns and operates five underground natural gas storage fieldswith a current working gas capacity of approximately 15.1 million Mcf. Naturalgas 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 under Item 1.

 

The estimated maximum deliverability from storage during the early part ofthe heating season is expected to be in excess of 370,000 Mcf/day. Undermid-winter design conditions, LG&E expects to be able to withdraw in excessof 350,000 Mcf/day from its storage facilities. The deliverability of naturalgas from LG&E’s storage facilities decreases as storage inventory levelsare reduced by seasonal withdrawals.

 

LG&E relies upon its significant underground storage to mitigatethe price volatility to which customers might otherwise be exposed. In 2000,the Kentucky Commission issued an order establishing Administrative Case No. 384– “An Investigation of Increasing Wholesale Natural Gas Prices and the Impactsof such Increase on the Retail Customers Served by Kentucky’s JurisdictionalNatural Gas Distribution Companies”. Subsequent to this investigation, theKentucky Commission issued an order on July 17, 2001, encouraging thenatural gas distribution companies in Kentucky to take various actions, amongthem to propose a natural gas hedge plan. LG&E currently operates under ahedge plan proposed by LG&E beginning with the 2004/2005 winter heatingseason. This hedge plan relies upon LG&E’s underground natural gas storageto mitigate customer exposure to price volatility. In 2004, the Kentucky Commissionapproved LG&E’s proposed hedge plan, validating the effectiveness ofstorage to mitigate potential volatility associated with high winter naturalgas prices by approving this natural gas hedge plan. The Kentucky Commissionalso ordered that LG&E need not file hedge plans in the future unless itintended to utilize financial hedging instruments.

 

The average cost per Mcf of natural gas purchased by LG&E was$10.23 in 2005, $7.18 in 2004, and $6.30 in 2003. Natural gas prices in theunregulated wholesale market generally have increased significantly over thelast few years beginning in 2000. For further discussion of wholesale naturalgas prices, see Note 3 of LG&E’s Notes to Financial Statements under Item8.

 

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Environmental Matters

 

Protection of the environment is a major priority for LG&E. Federal,state, and local regulatory agencies have issued LG&E permits for variousactivities subject to air quality, water quality, and waste management laws andregulations. For the five-year period ending with 2005, expenditures forpollution control facilities represented $233 million or 24% of totalconstruction expenditures. LG&E estimates that construction expendituresfor environmental protection equipment from 2006 through 2008 will beapproximately $40 million. For a discussion of environmental matters, see Note10 of LG&E’s Notes to Financial Statements under Item 8.

 

Competition

 

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. The nature or timing of the ultimatelegislative or regulatory actions regarding industry restructuring and theirimpact on LG&E, which may be significant, cannot currently bepredicted. Some states that have already deregulated have begun discussionsthat could lead to re-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 is 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 Commissionestablished Administrative Case No. 2005-00090 to collect information fromall jurisdictional utilities in Kentucky, including LG&E, pertaining toKentucky electric generation, transmission and distribution systems. LG&Eresponded to the Kentucky Commission’s first set of data requests at the end ofMarch 2005 and to a second set of data requests in May 2005. TheCommission held a Technical Conference in June 2005, in which all partiesparticipated in a panel discussion. A final report was provided in August 2005from the Kentucky Commission to the Governor. The Kentucky Commission issued anorder and closed this proceeding on September 15, 2005. Some of the keyfindings from the report are:

 

•                  Kentucky’selectric utilities currently have adequate infrastructure as well as adequateplanning to serve the needs of customers through 2025;

•                  Kentucky willneed 7,000 megawatts of additional generating capacity by 2025;

•                  Kentucky’selectric transmission is reliable but intrastate power transfers are limited;

•                  Additionalincentives to use renewable energy and educate the public on the benefits ofrenewables are needed;

•                  Financialincentives should be available for coal purification and other clean airtechnologies;

•                  A cautiousapproach should be taken toward deregulation; and

•                  Kentucky must beinvolved in federal decisions that impact its status as a low cost energyprovider.

 

Over the last several years, LG&E has taken many steps to keep itsrates low while maintaining high levels of customer satisfaction, including: anincrease in focus on commercial, industrial and residential customers; anincrease in employee involvement and training; and continuous modifications ofits organizational structure. LG&E also strives to control costs through competitivebidding and process improvements. LG&E’s performance in national customersatisfaction surveys continues to be high.

 

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KENTUCKYUTILITIES COMPANY

 

General

 

KU, incorporated in Kentucky in 1912 and incorporated in Virginia in1991, is a regulated public utility that provides electricity to approximately495,000 customers in over 600 communities and adjacent suburban and rural areasin 77 counties in central, southeastern and western Kentucky, to approximately30,000 customers in 5****counties insouthwestern Virginia and 5 customers in Tennessee. KU’s coal-fired electricgenerating plants produce most of KU’s electricity, the remainder is generatedby hydroelectric power plants and combustion turbines. In Virginia, KU operatesunder the name Old Dominion Power Company. KU operates under appropriatefranchises in substantially all of the 160 Kentucky incorporated municipalitiesserved. No franchises are required in unincorporated Kentucky or Virginia communities.The lack of franchises is not expected to have a material adverse effect on KU’soperations**.**KU also sells wholesale electricenergy to 12 municipalities. See Item 2, Properties.

 

Electric Operations

 

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

 
| **(in millions)**                         | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|-------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| ELECTRIC  OPERATING REVENUES              |       |     |       |     |       |     |       |
| Residential                               |       | $        | 364        |     | $          | 304      |       | $ | 278 |   |
| Commercial                                |       | 241      |       | 207      |       | 189      |       |
| Industrial                                |       | 220      |       | 190      |       | 176      |       |
| Mine power                                |       | 38       |       | 32       |       | 30       |       |
| Public  authorities                       |       | 83       |       | 72       |       | 66       |       |
| Total retail                              |       | 946      |       | 805      |       | 739      |       |
| Wholesale  sales                          |       | 210      |       | 160      |       | 138      |       |
| Provision  for rate collections (refunds) |       | —   |       | 5        |       | (8       | )          |
| Miscellaneous                             |       | 51       |       | 25       |       | 23       |       |
| Total                                     |       | $        | 1,207      |     | $          | 995      |       | $ | 892 |   |

 
| **(Thousands of Mwh)** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
|------------------------|------------|------------|------------|------------|------------|------------|------------|
| ELECTRIC  SALES        |       |       |       |       |       |       |       |
| Residential            |       | 6,599      |       | 6,160      |       | 6,001      |       |
| Commercial             |       | 4,466      |       | 4,323      |       | 4,210      |       |
| Industrial             |       | 5,459      |       | 5,400      |       | 5,110      |       |
| Mine power             |       | 803        |       | 732        |       | 722        |       |
| Public  authorities    |       | 1,649      |       | 1,597      |       | 1,551      |       |
| Total retail           |       | 18,976     |       | 18,212     |       | 17,594     |       |
| Wholesale  sales       |       | 5,781      |       | 5,707      |       | 5,591      |       |
| Total                  |       | 24,757     |       | 23,919     |       | 23,185     |       |

 

KU set an annual peak load of 4,079 Mw on July 25, 2005, when thetemperature reached 94 degrees Fahrenheit. This was the highest hourly customerdemand in KU’s history.

 

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The electric utility business is affected by seasonal weather patterns.As a result, operating revenues (and associated operating expenses) are notgenerated evenly throughout the year. See KU’s Results of Operations under Item7.

 

KU and LG&E currently maintain a 12% - 14% reserve margin range. AtDecember 31, 2005, KU owned steam and combustion turbine generatingfacilities with a net summer capability of 4,433 Mw and a 28 Mw nameplate-ratedhydroelectric facility with a summer capability of 24 Mw. See Item 2,Properties. KU also obtains power from other utilities under bulk powerpurchase and interchange contracts. At December 31, 2005, KU’s system netsummer capability, including purchases from others and excluding the hydroelectricfacility, was 4,678 Mw.

 

KU’s weighted-average system-wide emission rate for SO2 in2005 was approximately****1.25****lbs./MMBtu****of heat input,with every generating unit below its emission limit established by the KentuckyDivision for Air Quality.

 

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 the contract are made under a contractualformula resulting in costs which are expected to be comparable to the cost ofother power purchased or generated by KU. Such power equated to approximately8% of KU’s net generation system output during 2005. See Note 10 of KU’s Notes to FinancialStatements under Item 8.

 

KU owns 20% of the common stock of EEI, which owns and operates a1,000-Mw generating station in southern Illinois. Previously, KU was entitledto take 20% of the available capacity of the station under a pricing formulacomparable to the cost of other power generated by KU. Such power equated toapproximately 9% of KU’s net generation system output in 2005. The contractgoverning the purchases from EEI terminated on December 31, 2005.Subsequent to December 31, 2005, EEI has sold power under generalmarket-based pricing and terms. KU has not contracted with EEI for power underthe new arrangements, but maintains its 20% ownership in the common stock ofEEI. Replacement power for the EEI capacity has been largely provided by KUgeneration.

 

KU and 11other electric utilities are participating owners of OVEC, located in Piketon,Ohio. OVEC owns and operates two power plants that burn coal to generateelectricity, Kyger Creek Station in Ohio and Clifty Creek Station in Indiana.KU owns 2.5% of OVEC’s common stock. KU’s share of OVEC’s output is 2.5%,approximately 55 Mw of generation capacity. In April 2004, OVEC and itsshareholders, including KU and LG&E, entered into an Amended and RestatedInter-Company Power Agreement, to be effective beginning March 2006, uponthe expiration of the current power contract among the parties. The partiesreceived SEC approval under PUHCA 1935 of the Amended and RestatedInter-Company Power Agreement in February 2005.

 

KU is a member of the MISO, a non-profit independent transmissionsystem operator that serves the electrical transmission needs of much of theMidwest. Membership was obtained when the MISO was formed in 1998 in responseto and consistent with federal energy policy initiatives at that time. The MISObegan commercial operations in February 2002. As a result, KU turned overoperational control of its 100 Kv and above transmission facilities, butcontinues to control and operate the lower voltage transmission system subjectto the terms and conditions of the MISO. As a transmission-owning member of theMISO, KU incurs costs under the MISO OATT. In April 2005, the MISOimplemented its day-ahead real-time market (MISO Day 2), including a congestionmanagement system. At the present time, KU is involved in regulatoryproceedings at the Kentucky Commission and the FERC seeking authority to exitthe MISO. On March 17, 2006, the FERC issued an order conditionally approvingthe request of KU and LG&E to exit the MISO. For further discussion, see

 

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Note 15 of KU’s Notes to Financial Statements under Item 8.

 

Rates and Regulation

 

Historically, E.ON, KU’s ultimate parent, has been a registered holdingcompany under PUHCA 1935, and anticipates registering under PUHCA 2005. As aregistered holding company, E.ON, its utility subsidiaries, including KU, andcertain of its non-utility subsidiaries have been subject to extensiveregulation by the SEC and the FERC with respect to numerous matters, including:electric utility facilities and operations, wholesale sales of power andrelated transactions, accounting practices, issuances and sales of securities,acquisitions and sales of utility properties, payments of dividends out ofcapital and surplus, financial matters and inter-system sales of non-powergoods and services. In addition, PUHCA 1935 generally limited the ability ofregistered holding companies to acquire additional public utility systems andto acquire and retain businesses unrelated to the utility operations of theholding company. KU believes that it has adequate authority (includingfinancing authority) under existing FERC orders and regulations to conduct itsbusiness and will seek additional authorization when necessary.

 

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

 

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

 

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 of owning and operating a small amount ofelectric utility property in one county in Tennessee (having a gross book valueof approximately $0.3 million) from which KU served 5 customers at December 31,2005, KU is subject to the jurisdiction of the Tennessee Regulatory Authority.The Kentucky Commission, the Virginia Commission and the Tennessee RegulatoryAuthority have the ability to examine the rates KU charges its retail customersat any time.

 

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 serviceterritory each such supplier has the exclusive right to render retail electricservice.

 

KU’s Kentucky retail electric rates contain an FAC, whereby increasesand decreases in the cost of fuel for electric generation are reflected in therates charged to retail electric customers. The Kentucky Commission

 

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requires public hearings at six-month intervals to examine past fueladjustments, and at two-year intervals to review past operations of the fuelclause and transfer of the then current fuel adjustment charge or credit to thebase charges. The Kentucky Commission also requires that electric utilities,including KU, file documents relating to fuel procurement and the purchase ofpower and energy from other utilities. The FAC mechanism for Virginia customersuses an average fuel cost factor based primarily on projected fuel costs. Thefuel cost factor may be adjusted annually for over or under collections offuel costs from the previous year.

 

Prior to 2004, KU’s Kentucky retail electric rates were subject to anESM. KU and the Kentucky Commission agreed to a termination of the ESM relatingto all periods after 2003. The ESM, initially in place for three yearsbeginning in 2000, set an upper (12.5%) and lower (10.5%) limit for rate ofreturn on equity. If earnings were above the upper limit, the excess earningswere shared 40% with ratepayers and 60% with shareholders; if earnings werebelow the lower limit, the earnings deficiency was recovered 40% fromratepayers and 60% from shareholders.****By order ofthe Kentucky Commission, rate changes prompted by the ESM filing went intoeffect in April of each year subject to a balancing adjustment insuccessive periods. There is no ESM for Virginia retail electric rates. Fordiscussion of current ESM matters, see Note 3 of KU’s Notes to FinancialStatements under Item 8.

 

In June 2001, KU filed an application (“VDT case”) with theKentucky Commission to create a regulatory asset relating to first quarter 2001charges for a workforce reduction program. In December 2001, the KentuckyCommission approved a settlement in the VDT and allowed KU to set up aregulatory asset of $54 million for the workforce reduction costs and beginamortizing these costs over a five year period starting in April 2001. Thesettlement reduced revenues by approximately $11 million through a surcredit onbills to ratepayers over the same five-year period. The surcredit representednet savings stipulated by KU. For discussion of current VDT matters, see Note 3and Note 15 of KU’s Notes to Financial Statements under Item 8.

 

KU’s Kentucky retail rates contain an ECR surcharge which recoverscosts incurred by KU that are required to comply with the Clean Air Act andother environmental regulations. See Note 3 of KU’s Notes to FinancialStatements 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 April 2005.The AG and KIUC were granted intervention in the IRP proceeding. The KentuckyCommission issued its staff report on February 15, 2006, with nosubstantive issues noted and closed the case by Order dated February 24,2006.

 

The Commonwealth of Virginia passed the Virginia Electric UtilityRestructuring Act in 1999. This act gave Virginia customers the ability tochoose their electric supplier. Rates are capped at current levels through December 2010.The Virginia Commission will continue to require each Virginia utility to makeannual filings of either a base rate change or an Annual Informational Filingconsisting of a set of standard financial schedules. The Virginia Staff willissue a Staff Report regarding the individual utility’s financial performanceduring the historic 12-month period. The Staff Report can lead to an adjustmentin rates, but through December 2010 rates are subject to the capped rateperiod and essentially “frozen”. However, KU may petition the VirginiaCommission for a one-time adjustment in rates during the capped rate period. EffectiveJuly 1, 2003, the General Assembly ofVirginia amended and reenacted Section 56-580 of the Code of Virginia withlanguage that effectively exempts all KU Virginia service territory from retailchoice until such time as retail choice is offered to customers in KU’s otherservice territories.

 

14

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In December 2003, KU filed an application with the KentuckyCommission requesting an adjustment in KU’s electric rates. KU asked for ageneral adjustment in electric rates based on the twelve month test periodended September 30, 2003. The revenue increase requested was approximately$58 million. In June 2004, the Kentucky Commission issued an orderapproving an increase in KU’s annual electric base rates of approximately $46million (6.8%). The rate increase took effect on July 1, 2004.

 

Subsequentlyduring 2004 and 2005, the AG conducted an investigation regarding theproceedings resulting in the rate increase. The AG requested information from KUand the Kentucky Commission and its staff regarding alleged improper communicationsbetween KU and the Kentucky Commission related to the rate proceeding. The AGalso requested rehearing of the rate increase order on the basis of theseallegations, as well as calculational aspects of the increased rates. InFebruary, 2005 the AG submitted a confidential report on its investigation withthe Kentucky Commission and filed a motion summarizing the report as containingevidence of improper communications and record-keeping errors by KU in respectof its activities with state governmental agencies, including the KentuckyCommission.

 

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

 

For a further discussion of regulatory matters, see Note 3 of KU’sNotes to the Financial Statements 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 being reassessed and appropriate revisionsare made, when necessary, in construction schedules. 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, 2005, gross propertyadditions amounted to approximately $1 billion. Internally generated funds andexternal financings for the five-year period were utilized to provide for thesegross additions. The gross additions during this period amounted toapproximately 26% of total utility plant at December 31, 2005. Gross retirementsduring the same period were $106 million.

 

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

 

Coal Supply

 

Coal-fired generating units provided approximately 97% of KU’s netkilowatt-hour generation for 2005. The remaining net generation for 2005 wasprovided by natural gas and oil-fueled combustion turbine peaking units

 

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and hydroelectric plants. Coal is expected to be the predominant fuelused by KU in the foreseeable future, with natural gas and oil being used forpeaking capacity and flame stabilization in coal-fired boilers or in emergencies.KU has no nuclear generating units and has no plans to build any in the foreseeablefuture.

 

KU maintains its fuel inventory at levels estimated to be necessary toavoid operational disruptions at its coal-fired generating units. Reliabilityof coal deliveries can be affected from time to time by a number of factors,including fluctuations in demand, coal mine production issues and othersupplier or transporter operating difficulties.

 

KU has entered into coal supply agreements with various suppliers forcoal deliveries for 2006 and beyond and normally augments its coal supplyagreements with spot market purchases. KU has a coal inventory policy which itbelieves provides adequate protection under most contingencies. It had a coalinventory of approximately 1.1 million tons, or a 51-day supply, on hand at December 31,2005.

 

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, southern Illinois, Ohio, Wyoming and Colorado forthe foreseeable future.

 

Coal is delivered to KU’s Ghent plant by barge, Tyrone and Green Riverplants by truck, and E.W. Brown plant by rail and truck.

 

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

 
| ** **                         | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|------------------------------------|------------|----------|------------|----------|------------|----------|------------|
|                               |       |     |       |     |       |     |       |
| Per ton                            |       | $        | 42.45      |     | $          | 37.69    |       | $ | 34.57 |   |
| Per MMBtu                          |       | $        | 1.78       |     | $          | 1.56     |       | $ | 1.47 |   |
| Spot purchases as % of all sources |       | 15       | %          | 14       | %          | 11       | %          |

 

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 deliveredcost of coal for 2006 is expected to increase due to the start of new contractsand market conditions.

 

Environmental Matters

 

Protection of the environment is a major priority for KU. Federal,state, and local regulatory agencies have issued KU permits for variousactivities subject to air quality, water quality, and waste management laws andregulations. For the five-year period ending with 2005, expenditures forpollution control facilities represented $269 million or 26% of totalconstruction expenditures. KU estimates that construction expenditures forenvironmental control equipment from 2006 through 2008, will be approximately$680 million, of which approximately $560 million is related to theinstallation of FGDs at Ghent and Brown. For a discussion of environmentalmatters, see Note 10 of KU’s Notes to Financial Statements under Item 8.

 

Competition

 

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. The nature or timing of the ultimate

 

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legislative or regulatory actions regarding industry restructuring andtheir impact on KU, which may be significant, cannot currently bepredicted. Some states that have already deregulated have begun discussionsthat could lead to re-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 is designedto promote 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 Commissionestablished Administrative Case No. 2005-00090 to collect information fromall jurisdictional utilities in Kentucky, including KU, pertaining to Kentuckyelectric generation, transmission and distribution systems. KU responded to theKentucky Commission’s first set of data requests at the end of March 2005and to a second set of data requests in May 2005. The Commission held aTechnical Conference in June 2005, in which all parties participated in apanel discussion. A final report was provided in August 2005 from theKentucky Commission to the Governor. The Kentucky Commission issued an orderand closed this proceeding on September 15, 2005. Some of the key findingsfrom the report are:

 

•                  Kentucky’selectric utilities currently have adequate infrastructure as well as adequateplanning to serve the needs of customers through 2025;

•                  Kentucky willneed 7,000 megawatts of additional generating capacity by 2025;

•                  Kentucky’selectric transmission is reliable but intrastate power transfers are limited;

•                  Additional incentivesto use renewable energy and educate the public on the benefits of renewablesare needed;

•                  Financialincentives should be available for coal purification and other clean air technologies;

•                  A cautiousapproach should be taken toward deregulation; and

•                  Kentucky must beinvolved in federal decisions that impact its status as a low cost energyprovider.

 

Virginia has enacted a phase-in of customer choice through the VirginiaElectric Restructuring Act, however, KU’s service territory has been effectively exempted from retail choice untilsuch time as retail choice is offered to customers in KU’s other serviceterritories.

 

Over the last several years, KU has taken many steps to keep its rateslow while maintaining high levels of customer satisfaction, including: anincrease in focus on commercial, industrial and residential customers; anincrease in employee involvement and training; and continuous modifications ofits organizational structure. KU also strives to control costs throughcompetitive bidding and process improvements. KU’s performance in nationalcustomer satisfaction surveys continues to be high.

 

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EMPLOYEES ANDLABOR RELATIONS

 

LG&E had approximately 895 full-time regular employees and KU hadapproximately 925 full-time regular employees at February 28, 2006. Of theLG&E total, 621 operating, maintenance, and construction employees wererepresented by IBEW Local 2100. LG&E and employees represented by IBEWLocal 2100 signed a three-year collective bargaining agreement in November 2005with annual benefits re-openers. Of the KU total, approximately 150 operating,maintenance, and construction employees were represented by IBEW Local 2100 andUSWA Local 9447-01. In August 2003, KU and employees represented by IBEWLocal 2100 entered into a three-year collective bargaining agreement. KUand employees represented by USWA Local 9447-01 entered into a three-yearcollective bargaining agreement in August 2005 with authorized annual wagere-openers.

 

E.ON U.S. Services provides services to affiliated entities, includingLG&E and KU, at cost as permitted under PUHCA 2005. On February 28,2006, approximately 1,022 employees worked for E.ON U.S. Services.

 

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**Executive Officers of LG&E and KU**at February 28, 2006:

 
| ** **          | ** ** | ** ** | ** ** | ** **                | ** ** | **Effective Date of**   | ** ** |
|---------------------|------------|------------|------------|---------------------------|------------|-------------------------|------------|
| ** **          | ** ** | ** ** | ** ** | ** **                | ** ** | **Election to Present** | ** ** |
| **Name**            | ** ** | **Age**    | ** ** | **Position**              | ** ** | **Position**            | ** ** |
|                |       |       |       |                      |       |                    |       |
| Victor A. Staffieri |       | 50         |       | Chairman of the Board,    |       | May 1, 2001        |       |
|                |       |       |       | President and Chief       |       |                    |       |
|                |       |       |       | Executive Officer         |       |                    |       |
|                |       |       |       |                      |       |                    |       |
| John R. McCall      |       | 62         |       | Executive Vice President, |       | July 1, 1994       |       |
|                |       |       |       | General Counsel and       |       |                    |       |
|                |       |       |       | Corporate Secretary       |       |                    |       |
|                |       |       |       |                      |       |                    |       |
| S. Bradford Rives   |       | 47         |       | Chief Financial Officer   |       | September 15, 2003 |       |
|                |       |       |       |                      |       |                    |       |
| Paul W. Thompson    |       | 49         |       | Senior Vice President -   |       | June 7, 2000       |       |
|                |       |       |       | Energy Services           |       |                    |       |
|                |       |       |       |                      |       |                    |       |
| Chris Hermann       |       | 58         |       | Senior Vice President -   |       | February 14, 2003  |       |
|                |       |       |       | Energy Delivery           |       |                    |       |
|                |       |       |       |                      |       |                    |       |
| Wendy C. Welsh      |       | 52         |       | Senior Vice President -   |       | December 11, 2000  |       |
|                |       |       |       | Information Technology    |       |                    |       |
|                |       |       |       |                      |       |                    |       |
| Martyn Gallus       |       | 41         |       | Senior Vice President -   |       | December 11, 2000  |       |
|                |       |       |       | Energy Marketing          |       |                    |       |
|                |       |       |       |                      |       |                    |       |
| Paula H. Pottinger  |       | 49         |       | Senior Vice President -   |       | January 2, 2006    |       |
|                |       |       |       | Human Resources           |       |                    |       |

 

Other Officers of LG&E and KU at February 28,2006:

 
| David A. Vogel            |   | 40     |   | Vice  President - Retail       |   | March 1,  2003      |   |
|---------------------------|--------|--------|--------|--------------------------------|--------|--------------------------|--------|
|                      |   |   |   | and Gas  Storage Operations    |   |                     |   |
|                      |   |   |   |                           |   |                     |   |
| Daniel K.  Arbough        |   | 44     |   | Treasurer                      |   | December 11,  2000  |   |
|                      |   |   |   |                           |   |                     |   |
| Michael S.  Beer          |   | 47     |   | Vice  President                |   | September 27,  2004 |   |
|                      |   |   |   | Federal  Regulation and Policy |   |                     |   |
|                      |   |   |   |                           |   |                     |   |
| George R.  Siemens        |   | 56     |   | Vice  President - External     |   | January 11,  2001   |   |
|                      |   |   |   | Affairs                        |   |                     |   |
|                      |   |   |   |                           |   |                     |   |
| D. Ralph  Bowling         |   | 48     |   | Vice  President -              |   | August 1,  2002     |   |
|                      |   |   |   | Power Operations  WKE          |   |                     |   |
|                      |   |   |   |                           |   |                     |   |
| R. W. Chip  Keeling       |   | 49     |   | Vice  President -              |   | March 18,  2002     |   |
|                      |   |   |   | Communications                 |   |                     |   |
|                      |   |   |   |                           |   |                     |   |
| John N.  Voyles, Jr. |   | 51     |   | Vice  President -              |   | June 16,  2003      |   |
|                      |   |   |   | Regulated  Generation          |   |                     |   |
|                      |   |   |   |                           |   |                     |   |
| Valerie L.  Scott         |   | 49     |   | Controller                     |   | January 1,  2005    |   |

 

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The present term of office of each of the above executive and otherofficers extends to the meeting of the Board of Directors following the 2006Annual Meeting of Shareholders.

 

There are no family relationships between or among executive and otherofficers of LG&E and KU. The above tables indicate officers serving asexecutive officers of both LG&E and KU at February 28, 2006. Each ofthe above officers serves in the same capacity for LG&E and KU.

 

Before he was elected to his current positions, Mr. Staffieri wasChief Financial Officer of LG&E Energy (now E.ON U.S.) and LG&E from May 1997to February 1999 (including Chief Financial Officer of KU from May 1998to February 1999) and President and Chief Operating Officer of LG&EEnergy (now E.ON U.S.) from March 1999 to April 2001 (includingPresident of LG&E and KU from June 2000 to April 2001).

 

Mr. McCall has been Executive Vice President, General Counsel andCorporate Secretary of LG&E Energy (now E.ON U.S.) and LG&E since July 1994.He became Executive Vice President, General Counsel and Corporate Secretary ofKU in May 1998.

 

Before he was elected to his current positions, Mr. Rives wasSenior Vice President - Finance and Business Development from February 1999to December 2000 and Senior Vice President - Finance and Controller ofLG&E Energy (now E.ON U.S.), LG&E and KU from December 2000 to September 2003.

 

Before he was elected to his current positions, Mr. Thompson wasGroup Vice President for LG&E Energy Marketing, Inc. from June 1998to August 1999; Vice President, Retail Electric Business for LG&E fromDecember 1998 to August 1999; and Senior Vice President - EnergyServices for LG&E Energy (now E.ON U.S.) from August 1999 to June 2000.

 

Before he was elected to his current positions, Mr. Hermann wasVice President, 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 wasVice President - Information Technology from February 1998 to December 2000for LG&E Energy (now E.ON U.S.).

 

Before he was elected to his current positions, Mr. Gallus wasVice President, Energy Marketing from August 1998 to December 2000for LG&E Energy (now E.ON U.S.).

 

Before she was elected to her current positions, Ms. Pottinger wasDirector, Human Resources from June 1997 to June 2002; and VicePresident - Human Resources from June 2002 to January 2006.

 

Before he was elected to his current positions, Mr. Vogel was VicePresident - Retail Services from December 2000 to March 2003.

 

In addition to being elected to his current positions, Mr. Arboughhas held the positions of Director, Corporate Finance of LG&E Energy (nowE.ON U.S.), LG&E and KU from May 1998 to present.

 

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Before he was elected to his current positions, Mr. Beer was SeniorCounsel Specialist, Regulatory from February 2000 to February 2001, and VicePresident – 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 (now E.ON U.S.)from August 1982 to January 2001.

 

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

 

Before he was elected to his current positions, Mr. Keeling wasDirector, Corporate Communications for LG&E Energy (now E.ON U.S.) fromFebruary 2000 to March 2002.

 

Before he was elected to his current positions, Mr. Voyles was GeneralManager, Cane Run, Ohio Falls and Combustion Turbines, November 1998 toFebruary 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 – UtilityOperations from September 2002 to December 2004.

 

## Item 1A. Risk Factors

##  

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

 

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

**** ****

The rates that the Companies are allowed to charge for their servicesare a primary item influencing the results of operations, financial position,and liquidity of the Companies. The regulation of the rates that are collectedfrom customers is determined, in large part, by governmental organizationsoutside the Companies’ control, including the Kentucky Commission, and for KU,the Virginia Commission and the Tennessee Regulatory Authority. These commissionsregulate many aspects of utility operations, including financial and capitalstructure matters, siting and construction of facilities, terms and conditionsof service, safety and operations, accounting and cost allocation methodologiesand other matters. While rate regulation is premised on recovery of prudentlyincurred costs and reasonable rate of return on capital, such cannot be assured.R****egulatory proceedingsregarding all matters of operations can thus significantly affect the earnings,liquidity and business activities of the Companies.****

 

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

 

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are also the subject ofon-going proceedings. 

 

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

 

The Companies’ businesses are subject to regulation under the FERCcovering matters including rates charged to transmission users and wholesalecustomers, interstate market structure and design, construction and operationof transmission facilities, acquisition and disposal of utility assets andsecurities, standards of conduct, cost allocations and financial matters.Existing FERC regulation, changes thereto or issuance of new rules in theseareas, can affect the earnings, operations and other activities of theCompanies.

 

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

 

LG&E and KU are members of the MISO and have transferred functionalcontrol of their transmission systems to the MISO. The Companies must incurMISO membership-related costs and charges established by the MISO and can berequired to incur other expenses or make transmission and generation operatingdecisions as directed by the MISO. The MISO Day 2 markets, which beganoperation in April 2005, have represented a significant change in the wholesalepower market structure and operation. Until the market matures, the effects onresults of operations, financial position, or liquidity will remain difficultto predict.

 

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

 

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

 

In the ordinary course of business, the Companies are continuallydeveloping, permitting and constructing new generation and transmissionfacilities, as well as maintaining and improving existing facilities. Thecompletion of these facilities without delays or cost overruns is subject torisks in many areas, including approval and licensing, permitting, constructionproblems or delays, contractor performance, weather and geological issues, andpolitical, labor and regulatory developments. Delays, additional costs orunsatisfactory regulatory treatment can result in reduced earnings. Further, ifconstruction projects are not completed according to specifications, theCompanies may incur reduced plant efficiency, higher operating costs orcontinued capital costs.

 

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

 

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

 

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

 

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

 

**LG&E’s and KU’s operating results areaffected by weather conditions, including storms and seasonal temperaturevariations, as well as by significant man-made or accidental disturbances.**

 

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

 

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

 

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

 

**LG&E and KU are subject to operationalrisks relating to their generating plants, transmission facilities anddistribution equipment.**

** **

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

 

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adversely affected byunexpected or uncontrollable events occurring on the systems of such thirdparties. Operation of the Companies’ power plants below expected capacitylevels could result in lost revenues or increased expenses, including highermaintenance costs that may not be recovered from customers. Unplanned outagesmay result in significant replacement power costs. While LG&E and KUbelieve appropriate prevention or mitigation measures are in place, wherepossible, with respect to these potential business disruptions, no assurancescan be given that such events will not occur in the future or will notnegatively affect their financial condition or results of operations.

 

**LG&E and KU could be negatively affected by downgrades to creditratings or other negative developments in their ability to access capitalmarkets.**

** **

In the ordinary course of business, the Companies have significantlong-term and short-term financing requirements to fund their capitalexpenditures, debt interest or maturities and operating needs. If ratingagencies were to downgrade the Companies’ credit ratings, particularly belowinvestment grade, or withdraw such ratings, it could significantly limit accessto the capital market and the Companies’ borrowing costs could increase. Inaddition, the Companies’ financing costs can also be affected by financialmatters involving their parent holding company, including its overall creditrating, its provision of intra-company financing and the terms and rates ofsuch financing. 

 

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

** **

LG&E and KU are exposed to purchase and sales market operating andfinancial risks common to utility operations. Although the Companies operatelargely in regulated markets, increases in the cost of power and fuel, such ascoal or natural gas, as well as other major inputs and supplies, can affecttheir margins because authorized rate structures and pass-through costmechanisms may include timing lags or regulatory discretion which do not leadto full cost recovery. Changes in the wholesale market price for electricitycan impact LG&E’s and KU’s financial results by altering the revenues fromoff-system sales of excess power from period to period. LG&E and KU arealso exposed to risk that counterparties could fail to perform theirobligations to provide energy, fuel, goods, services or payments resulting inpotential increased costs to the Companies.

 

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

 

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

 

## Item 1B. Unresolved StaffComments. 

##  

None.

 

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## **ITEM2. Properties**.

##  

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

 
| ** **                                             | ** ** | **Summer Capability****Rating (Kw)** | ** ** |
|--------------------------------------------------------|------------|------------------------------------------------|------------|
| Steam Stations:                                        |       |                                           |       |
| Mill Creek –  Jefferson County, 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 –  Jefferson County, KY                  |       |                                           |       |
| Unit 4                                                 |       | 155,000                                        |       |
| Unit 5                                                 |       | 168,000                                        |       |
| Unit 6                                                 |       | 240,000                                        |       |
| Total Cane Run                                         |       | 563,000                                        |       |
|                                                   |       |                                           |       |
| Trimble County – Trimble County, KY (a)           |       |                                           |       |
| Unit 1                                                 |       | 383,000                                        |       |
|                                                   |       |                                           |       |
| Combustion Turbine Generators (Peaking  capability):   |       |                                           |       |
| Zorn Run – Jefferson County, KY                   |       | 14,000                                         |       |
| Paddy’s Run – Jefferson County, KY (b)       |       | 119,000                                        |       |
| Cane Run – Jefferson County, KY                   |       | 14,000                                         |       |
| Waterside – Jefferson County, KY                  |       | 22,000                                         |       |
| E.W. Brown – Mercer County, KY (Units  5,6,7) (c) |       | 190,000                                        |       |
| Trimble County – Trimble County, KY (d)           |       | 328,000                                        |       |
| Total combustion turbine generators                    |       | 687,000                                        |       |
|                                                   |       |                                           |       |
| Total capability rating                                |       | 3,105,000                                      |       |

 

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(a)          Amount shown represents LG&E’s 75%interest in Trimble County 1. See Notes 10 and 11 of LG&E’s Notes toFinancial Statements under Item 8 for further discussion on ownership.

(b)         Amount shown represents LG&E’s 53%interest in Paddy’s Run Unit 13 and 100% ownership of Paddy’s Run Units 11 and12. See Notes 10 and 11 of LG&E’s Notes to Financial Statement, under Item8 for further discussion on ownership.

(c)          Amount shown represents LG&E’s 53%interest in Unit 5, 38% interest in Units 6 and 7 at E.W. Brown and 10% of theInlet Air Cooling system, attributable to Brown Unit 5. See Notes 10 and 11 ofLG&E’s Notes to Financial Statements, under Item 8 for further discussionon ownership. KU operates these units on behalf of LG&E.

(d)         Amount shown represents LG&E’s 29%interest in Units 5 and 6 and LG&E’s 37% interest in Units 7, 8, 9 and 10at Trimble County. See Notes 10 and 11 of LG&E’s Notes to FinancialStatements, under Item 8 for further discussion on ownership.

 

LG&E also owns an 80 Mw nameplate-rated hydroelectric generatingstation located in Jefferson County, Kentucky (Ohio Falls), with an expectedsummer capability rating of 48 Mw, operated under a license issued by the FERC.

 

25

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At December 31, 2005, LG&E’s electric transmission system included21 substations dedicated solely to transmission and an additional 20substations shared with the distribution system with a total capacity ofapproximately 12,000 Mva and approximately 899 miles of lines. The electricdistribution system included 93 substations (20 of which are shared by thetransmission system) with a total capacity of approximately 4,865 Mva, 3,934miles of overhead lines and 2,035 miles of underground conduit.

 

LG&E’s natural gas transmission system includes 257 miles oftransmission mains, and the natural gas distribution system includes 4,133miles of distribution mains.

 

LG&E operates underground natural gas storage facilities with acurrent working 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 wasrenegotiated in 2002 and is scheduled 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, Fidelia has a second secured lien on the propertysubject to the first mortgage bond lien.

 

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

 
| ** **                                            | ** ** | **Summer Capability  Rating (Kw)** | ** ** |
|-------------------------------------------------------|------------|----------------------------------------------|------------|
| Steam Stations:                                       |       |                                         |       |
| Tyrone –  Woodford County, KY                    |       |                                         |       |
| Unit 1                                                |       | 27,000                                       |       |
| Unit 2                                                |       | 31,000                                       |       |
| Unit 3                                                |       | 71,000                                       |       |
| Total Tyrone                                          |       | 129,000                                      |       |
|                                                  |       |                                         |       |
| Green River  – Muhlenberg County, KY             |       |                                         |       |
| Unit 3                                                |       | 68,000                                       |       |
| Unit 4                                                |       | 95,000                                       |       |
| Total Green River                                     |       | 163,000                                      |       |
|                                                  |       |                                         |       |
| E.W. Brown –  Mercer County, KY                  |       |                                         |       |
| Unit 1                                                |       | 101,000                                      |       |
| Unit 2                                                |       | 167,000                                      |       |
| Unit 3                                                |       | 429,000                                      |       |
| Total E.W. Brown                                      |       | 697,000                                      |       |
|                                                  |       |                                         |       |
| Ghent –  Carroll County, 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 – Mercer County, KY (Units 5-11)  (a) |       | 757,000                                      |       |
| Haefling – Fayette County, KY                    |       | 36,000                                       |       |
| Paddy’s Run – Jefferson County, KY (b)      |       | 74,000                                       |       |
| Trimble County – Trimble County, KY (c)          |       | 632,000                                      |       |
| Total combustion turbine generators                   |       | 1,499,000                                    |       |
|                                                  |       |                                         |       |
| Total capability rating                               |       | 4,433,000                                    |       |

 

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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 Cooling system, attributable to E.W. Brown CT Unit 5 andUnits 8 to 11. See Notes 10 and 11 of KU’s Notes to Financial Statements, underItem 8 for further discussion on ownership.

(b)         Amount shown represents KU’s 47% interestin Unit 13 at Paddy’s Run. See Notes 10 and 11 of KU’s Notes to FinancialStatements, under Item 8 for further discussion on ownership. LG&E operatesthis 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 10 and 11 of KU’s Notes to Financial Statements, under Item 8for further discussion on ownership. LG&E operates these units on behalf ofKU.

 

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

 

At December 31, 2005, KU’s electric transmission system included 110substations with a total capacity of

 

27

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approximately 16,978 Mva and approximately 4,031 miles of lines. Theelectric distribution system included 492 substations with a total capacity ofapproximately 6,322 Mva, 13,746 miles of overhead lines and 1,704 miles ofunderground conduit.

 

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 secured lien on the property subject to the first mortgagebond lien.

 

# **ITEM 3. Legal Proceedings.**

# ** **

Rates and Regulatory Matters

 

For adiscussion of current rate and regulatory matters, including electric andnatural gas base rate increase proceedings, the Kentucky attorney generalinvestigation, VDT proceedings, Trimble County Unit 2 proceedings,  Kentucky Commission, FERC and MISO proceedings,and other rate or regulatory matters affecting LG&E and KU, see Rates andRegulation for LG&E and KU under Item 1 and Note 3 of LG&E’s and KU’sNotes to Financial Statements under Item 8.

 

Environmental

 

For adiscussion of environmental matters including additional reductions in SO2,NOx and other emissions mandated by recent regulations; items regardingLG&E’s Mill Creek generating plant, KU’s E.W. Brown plant and LG&E’sand KU’s manufactured gas plant sites; and other environmental items affectingLG&E and KU, see Executive Summary (Environmental Matters) and Note 10 ofLG&E’s and KU’s Notes to Financial Statements under Item 8.

 

LG&E Employment Discrimination Case

 

In October2001, approximately 30 employees or former employees filed a complaint againstLG&E claiming past and current instances of employment discriminationagainst LG&E. LG&E has removed the case to the U.S. District Court forthe Western District of Kentucky and filed an answer denying all plaintiffs’claims. To date, the U.S. Equal Employment Opportunity Commission has declinedto proceed to litigation on any claims reviewed. Through continuing mediation,settlements have been reached with the majority of plaintiffs, including thelead plaintiff. Negotiations continue with six plaintiffs. The complaintcontains a claimed damage amount of $100 million as well as requests forinjunctive relief, however, all 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”), commenced a suit now removed to the U.S. District Court for the WesternDistrict of Kentucky, against KU concerning a long-term power supply contract(the “OMU Agreement”) with KU. The dispute involves interpretationaldifferences regarding issues under the OMU Agreement, including variouspayments or charges

 

28

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between KU and OMU and rights concerningexcess power, termination and emissions allowances, respectively. The complaintseeks approximately $6 million in damages for periods prior to 2004 and OMU isexpected to claim further amounts for later-occurring periods. OMU hasadditionally requested injunctive and other relief, including a declarationthat KU is in material breach of the contract. KU has filed an answer in thatcourt denying the OMU claims and presenting counterclaims. During 2005, theFERC declined KU’s application to exercise exclusive jurisdiction on matters.In July 2005, the district court resolved a summary judgment motion of KU inOMU’s favor, ruling that a contractual provision grants OMU the ability toterminate the contract without cause upon four years’ prior notice, whichruling is not yet final. At this time, the district court case is in thediscovery stage and a trial schedule has not yet been established.

 

Other

 

In the normalcourse of business, other lawsuits, claims, environmental actions, and othergovernmental proceedings arise against LG&E and KU. To the extent thatdamages are assessed in any of these lawsuits, LG&E and KU believe thattheir insurance coverage is adequate. Management, after consultation with legalcounsel, does not anticipate that liabilities arising out of other currentlypending or threatened lawsuits and claims will have a material adverse effecton LG&E’s or KU’s financial position or results of operations,respectively.

 

ITEM 4.Submission of Matters to a Vote of Security Holders. 

** **

None.

 

PART II.

 

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

 

LG&E:

 

All LG&E common stock, 21,294,223 shares, is held by E.ON U.S.Therefore, there is no public market for LG&E’s common stock.

 

The following table sets forth LG&E’s cash distributions on commonstock paid to E.ON U.S. during 2005:

 
| **(in millions)** | ** ** | ** ** | ** ** |
|------------------------|------------|------------|------------|
| First quarter          |       | $          | 29         |   |
| Second quarter         |       | 10         |       |
| Third quarter          |       | —     |       |
| Fourth quarter         |       | —     |       |
|                        |            |            |            |  |

 

LG&E paidcash distributions on common stock to E.ON U.S. in the amount of $57 million in2004 and $0 in 2003.

 

KU:

 

All KU common stock, 37,817,878 shares, is held by E.ON U.S. Therefore,there is no public market for KU’s common stock.

 

The following table sets forth KU’s cash distributions on common stockpaid to E.ON U.S. during 2005:

 

29

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| **(in millions)** | ** ** | ** ** | ** ** |
|------------------------|------------|------------|------------|
| First quarter          |       | $          | 30         |   |
| Second quarter         |       | 10         |       |
| Third quarter          |       | 10         |       |
| Fourth quarter         |       | —     |       |
|                        |            |            |            |  |

 

KU paid cash distributions on common stock to E.ON U.S. in the amountof $63 million in 2004 and $0 in 2003.

 

30

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# **ITEM 6. Selected Financial Data.**

 
| ** **                                                    | ** ** | **Years Ended December 31** | ** ** |
|---------------------------------------------------------------|------------|-----------------------------|------------|
| **(in millions)**                                             | ** ** | **2005**                    | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** | **2001** | ** ** |
| ** **                                                    |       |                        |       |   |   |   |   |   |   |   |   |
| LG&E:                                                     |       |                        |       |   |   |   |   |   |   |   |   |
| Operating revenues                                            |       | $                           | 1,424      |   | $ | 1,173 |   | $ | 1,094 |   | $ | 1,004 |   | $ | 965 |   |
|                                                          |       |                        |       |   |   |   |   |   |   |   |   |
| Net operating income                                          |       | $                           | 230        |   | $ | 185 |   | $ | 179 |   | $ | 173 |   | $ | 205 |   |
|                                                          |       |                        |       |   |   |   |   |   |   |   |   |
| Net income                                                    |       | $                           | 129        |   | $ | 96 |   | $ | 91 |   | $ | 89 |   | $ | 107 |   |
|                                                          |       |                        |       |   |   |   |   |   |   |   |   |
| Total assets                                                  |       | $                           | 3,146      |   | $ | 2,967 |   | $ | 2,882 |   | $ | 2,769 |   | $ | 2,448 |   |
|                                                          |       |                        |       |   |   |   |   |   |   |   |   |
| Long-term obligations(including amounts  due within one year) |       | $                           | 821        |   | $ | 872 |   | $ | 798 |   | $ | 617 |   | $ | 617 |   |

 

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

 
| ** **                                                    | ** ** | **Years  Ended December 31** | ** ** |
|---------------------------------------------------------------|------------|------------------------------|------------|
| **(in  millions)**                                            | ** ** | **2005**                     | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** | **2001** | ** ** |
|                                                          |       |                         |       |   |   |   |   |   |   |   |   |
| KU:                                                           |       |                         |       |   |   |   |   |   |   |   |   |
| Operating revenues                                            |       | $                            | 1,207      |   | $ | 995 |   | $ | 892 |   | $ | 862 |   | $ | 821 |   |
|                                                          |       |                         |       |   |   |   |   |   |   |   |   |
| Net operating income                                          |       | $                            | 202        |   | $ | 228 |   | $ | 162 |   | $ | 163 |   | $ | 179 |   |
|                                                          |       |                         |       |   |   |   |   |   |   |   |   |
| Net income                                                    |       | $                            | 112        |   | $ | 134 |   | $ | 91 |   | $ | 93 |   | $ | 96 |   |
|                                                          |       |                         |       |   |   |   |   |   |   |   |   |
| Total assets                                                  |       | $                            | 2,756      |   | $ | 2,610 |   | $ | 2,505 |   | $ | 2,252 |   | $ | 1,827 |   |
|                                                          |       |                         |       |   |   |   |   |   |   |   |   |
| Long-term obligations(including amounts  due within one year) |       | $                            | 747        |   | $ | 726 |   | $ | 688 |   | $ | 501 |   | $ | 489 |   |

 

KU’s Management’s Discussion and Analysis of Financial Condition andResults of Operation and KU’s Notes to Financial Statements should be read inconjunction with the above information.

 

31

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**ITEM 7.Management’s Discussion and Analysis of Financial Condition and Results ofOperations**. 

 

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 2005, 2004 and 2003 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 risks, uncertainties and assumptions. Such forward-lookingstatements are intended to be identified in this document by the words “anticipate,”“expect,” “estimate,” “objective,” “possible,” “potential” and similarexpressions. Actual results may materially vary. Factors that could causeactual results to materially differ include: general economic conditions;business and competitive conditions in the energy industry; changes in federalor state legislation; unusual weather; actions by state or federal regulatoryagencies; actions by credit rating agencies; and other factors described fromtime to time in LG&E’s and KU’s reports to the SEC, including Risk Factorsin Item 1A of this report on Form 10-K and in Exhibit No. 99.01 to this reporton Form 10-K. 

 

EXECUTIVE SUMMARY

 

Our Business

 

LG&E and KU are eachsubsidiaries of E.ON U.S., which is an indirect subsidiary ofE.ON, a Germancompany. LG&E and KU maintain separate corporate identities and servecustomers in Kentucky, Virginia and Tennessee under their respective names.

 

LG&E, incorporated in 1913 in Kentucky, is a regulated publicutility that supplies natural gas to approximately 321,000 customers andelectricity to approximately 394,000 customers in Louisville and adjacent areasin Kentucky. LG&E’s service area covers approximately 700 square miles in17 counties and has an estimated population of one million. LG&E alsoprovides natural gas service in limited additional areas. LG&E’s coal-firedelectric generating plants, all equipped with systems to reduce SO2emissions, produce most of LG&E’s electricity. The remainder is generatedby a hydroelectric power plant and combustion turbines. Underground natural gasstorage fields help LG&E provide economical and reliable natural gasservice to customers.

 

KU, incorporated in Kentucky in 1912 and incorporated in Virginia in1991, is a regulated public utility that provides electricity to approximately495,000 customers in over 600 communities and adjacent suburban and rural areasin 77 counties in central, southeastern and western Kentucky, to approximately30,000 customers in 5****counties insouthwestern Virginia and 5 customers in Tennessee. KU’s coal-fired electricgenerating plants produce most of KU’s electricity, the remainder is generatedby hydroelectric power plants and combustion turbines. In Virginia, KU operatesunder the name Old Dominion Power Company. KU also sells wholesale electricenergy to 12 municipalities.

 

32

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Our Customers

 

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

 

Customers (in thousands)

 
| ** **                         | ** ** | **LG&E** | ** ** | **KU**   | ** ** | **2005% Retail Revenues** | ** ** |
|------------------------------------|------------|--------------|------------|----------|------------|-------------------------------------|------------|
| ** **                         | ** ** | **Electric** | ** ** | **Gas**  | ** ** | **Electric**                        | ** ** | **LG&E** | ** ** | **KU** | ** ** |
| **Retail Customer Data** | ** ** | **2005**     | ** ** | **2004** | ** ** | **2003**                            | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** | **Electric** | ** ** | **Gas** | ** ** | **Electric** | ** ** |
|                               |       |         |       |     |       |                                |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Residential                        |       | 347          |       | 343      |       | 337                                 |       | 296 |   | 293 |   | 287 |   | 433 |   | 426 |   | 421 |   | 40 | % | 64 | % | 38 | % |
| Industrial & Commercial        |       | 41           |       | 41       |       | 41                                  |       | 24 |   | 24 |   | 24 |   | 82 |   | 82 |   | 82 |   | 50 | % | 31 | % | 49 | % |
| Other                              |       | 6            |       | 6        |       | 6                                   |       | 1 |   | 1 |   | 1 |   | 10 |   | 10 |   | 9 |   | 10 | % | 5 | % | 13 | % |
| Total Retail                       |       | 394          |       | 390      |       | 384                                 |       | 321 |   | 318 |   | 312 |   | 525 |   | 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’s and KU’s strategy focuses on the following: 

 

•                  Achieve scale asan integrated U.S. electric and gas business through organic growth; 

•                  Maintainexcellent customer satisfaction;

•                  Maintainbest-in-class cost position versus U.S. utility companies;

•                  Develop andtransfer best practices throughout the company;

•                  Invest ininfrastructure to meet expanding load and comply with increasing environmentalrequirements; 

•                  Achieveappropriate regulated returns on all investment;

•                  Attract, retainand develop the best people; and

•                  Act with a commitmentto corporate social responsibility that enhances the well being of ouremployees, demonstrates environmental stewardship, promotes quality of life inour communities and reflects the diversity of the society we serve.

 

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 first among all large Midwest utilities for the 6thtime in 7 years in the J.D. Power and Associates 2005 survey of residentialelectric customers. This excellent performance is balanced with cost control.The customer benefits of the LG&E and KU culture of cost management areevident in rate comparisons among U.S. utilities. The following chart comparesthe total residential average rate per thousand Kwh of U.S. investor-ownedutilities as of July 1, 2005:

 

33

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Source:Edison Electric Institute, Summer 2005 Typical Bills and Average Rates Report;Residential rates in effect July 1, 2005, based on 1,000 kWh monthly usage.

 

LG&Eand KU 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, produced approximately $55 million of revenue forLG&E and approximately $46 million of revenue for KU for a full year. Underthe settlement agreements, the LG&E utility base electric rates haveincreased approximately $43 million (7.7%) and base natural gas rates haveincreased approximately $12 million (3.4%) annually. Base electric rates at KUhave increased approximately 6.8% annually. The 2004 increases were the firstincreases in electric base rates for LG&E and KU in 13 and 20 years,respectively; the last natural gas rate increase for the LG&E natural gasutility took effect in September 2000. Competitors also face these same costpressures that caused LG&E and KU to initiate rate cases (e.g., pensions, benefitsand reliability expenditures) and many other utility companies already haverate cases in process. Despite these increases, LG&E and KU ratesremain significantly lower than the national average.

 

### CommodityPrices: Fuel and Electricity

###  

Natural gas prices have risen dramatically in2005, averaging over $8/MMBtu and spiking as high as $15/MMBtu in lateSeptember following the hurricanes that interrupted natural gas productionactivities in the Gulf of Mexico. Although the supply problems created by thehurricanes have improved significantly, the underlying and fundamental U.S.supply-demand imbalance shows no sign of easing. While U.S. natural gasreserves are in structural decline, natural gas demand is increasing. Thenatural gas outlook is projected to maintain this pattern until significant newsupply, in the form of LNG or new discoveries, enters the marketplace.

 

Coal price increases continued during 2005,up nearly 60% overall since the beginning of 2004, with modest increasesprojected over the near term. The rise in oil and natural gas prices, combinedwith the supply of coal not keeping pace with demand, have resulted insubstantially higher coal prices over the last two years.

 

34

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The graph displays theLG&E, KU and combined utility average utility natural gas and coal purchaseprices.

 
|  |   |  |
|--|--------|--|

 

Actualnatural gas costs are recovered from customers through the GSC. The GSC alsocontains an incentive component, the PBR component, which is determined for each12-month period ending October 31.

 

Actualfuel costs associated with retail electric sales are recovered from customersthrough the FAC. The Utilities’ base rates contain an embedded fuel costcomponent. The FAC reconciles the difference between this fuel cost componentand the actual fuel cost, including transportation costs. Refunds to customersoccur if the actual costs are below the embedded cost component. Additionalcharges to customers occur if the actual costs exceed the embedded costcomponent.

 

Withrespect to wholesale electricity prices, generation over-capacity in theMidwest United States is forecasted to persist, with reserve margins over 23%for ECAR in 2006. However, theover-capacity results largely from the construction of natural gas-fired units.High natural gas prices have supported higher wholesale electricity prices,providing advantages to coal-fired generation. While the regional reservemargin is expected to decline over time as new capacity construction slows anddemand grows, natural gas-fired generation is expected to set prices,particularly during times of higher loads. This expectation, combined with theexpectation that natural gas prices will remain high, indicates that peakelectricity prices are expected to remain high.

 

GenerationReliability 

 

Generationreliability also remains a key aspect to meeting the Companies’ strategy.LG&E and KU believe that they have maintained good performance andreliability in the key area of utility generation operation. While maintaininglow cost levels, LG&E and KU have also been able to generate increasingvolumes and expect to continue high levels of availability and low outagelevels. This performance is also important to maintaining margins fromoff-system sales. 

** **

GenerationCapacity

 

Theinstallation of Trimble County Units 7-10, completed in 2004, increased totalsystem capability by 9%. However, the IRP submitted by LG&E and KU to theKentucky Commission in 2005, outlining the least cost alternative to meetKentucky’s needs, indicated the requirement for additional base-load capacityby 2010. Consequently, LG&E and KU have begun development efforts foranother base-load coal-fired unit at the Trimble County site. LG&E and KUbelieve this is the least cost alternative to meet the future needs of

 

35

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customers.Trimble County Unit 2, with a 750 MW capacity rating, is expected to be jointlyowned by LG&E and KU (75% owners of the unit) and IMEA and IMPA (25%owners). Trimble County Unit 2 is expected to cost $1.1 billion and becompleted by 2010. LG&E’s and KU’s aggregate 75% share of the total TrimbleCounty Unit 2 capital cost is approximately $885 million and is estimated to beapproximately $120 million and $510 million, respectively, through 2008.

 

Anapplication for a construction CCN was filed with the Kentucky Commission inDecember 2004 and initial CCN applications for three transmission lines werefiled in early 2005, with further applications submitted in December 2005. Theproposed air permit was filed with the Kentucky Division for Air Quality inDecember 2004. In November 2005, the Kentucky Commission approved theapplication of LG&E and KU to expand the Trimble County generating plant.Kentucky Commission approval for one transmission line CCN was granted inSeptember 2005 and a ruling that a second transmission line was not subject tothe CCN process was received in February 2006. LG&E and KU hope to obtainapproval for the remaining transmission line CCN during 2006. The transmissionlines are also subject to routine regulatory filings and the right-of-wayacquisition process. In November 2005, the Kentucky Division for Air Qualityissued the final air permit, which was challenged in December 2005 by anenvironmental advocacy group. Administrative proceedings with respect to thechallenge are expected to commence during the first quarter of 2006.

 

InOctober 2005, LG&E received from the FERC a new license to upgrade, operateand maintain the Ohio Falls Hydroelectric Project. The license is for a periodof 40 years, effective November 2005. LG&E intends to spend approximately$76 million to refurbish the facility and add approximately 20 Mw of generatingcapacity over the next seven years.

 

Environmental Matters

 

In addition to the Trimble County Unit 2 project, the second major areaof utility investment is environmental expenditures. LG&E and KU aresubject to SO2 and NOx emission limits on their electric generatingunits pursuant to the Clean Air Act. LG&E and KU placed into operationsignificant NOx controls for their generating units prior to the 2004 summerozone season. As of December 31, 2005, LG&E and KU have incurred totalcapital costs of approximately $188 million and $217 million, respectively,since 2000 to reduce their NOx emissions below required levels. In addition,LG&E and KU have incurred additional operating and maintenance costs inoperating the new NOx controls.

 

In March 2005, the EPA issued the final CAIR which requires substantialadditional reductions in SO2 and NOx emissions from electric generatingunits. The CAIR provides for a two-phased reduction program with Phase Ireductions in NOx and SO2 emissions in 2009 and 2010, respectively,and Phase II reductions in 2015. On March 15, 2005, the EPA issued a relatedregulation, the final CAMR, which requires substantial mercury reductions fromelectric generating units. CAMR also provides for a two-phased reduction, withthe Phase I target in 2010 achieved as a “co-benefit” of the controls installedto meet CAIR. Additional control measures will be required to meet the Phase IItarget in 2018. Both CAIR and CAMR establish a cap and trade framework, inwhich limits are set on total emissions and allowances can be bought or sold onthe open market, to be used for compliance, unless the state chooses anotherapproach.

 

In order to meet these new regulatory requirements,KU has implemented a plan for adding significant additional SO2controls to its generating units. Installation of additional SO2controls will proceed on a phased basis, with construction of controls (i.e.,FGDs) having commenced in September 2005, and continuing through the final installationand operation in 2009. KU estimates that it will incur approximately $560million in capital costs related to the construction of the FGDs over the nextthree years to achieve compliance with current emission limits on acompany-wide basis. In addition, KU will incur additional operating andmaintenance costs

 

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in operating the new SO2 controls.LG&E currently has FGDs on all its units but will continue to evaluateimprovements to further reduce SO2 emissions.

 

Kentucky law permits LG&E and KU to recover the costs ofcomplying with the Federal Clean Air Act, including a return of operatingexpenses, and a return of and on capital invested, through the ECR mechanism.Approximately 80% of the applicable environmental costs, including investmentand operating costs, are recoverable through the ECR. The remaining 20%,attributable to off-system and non-Kentucky jurisdictional sales, are notrecoverable through the ECR. 

 

COMPANY STRUCTURE

 

Ascontemplated in their regulatory filings in connection with the E.ONacquisition of Powergen in 2002, E.ON, Powergen and E.ON U.S. completed anadministrative reorganization to move the LG&E Energy Corp. group from anindirect Powergen subsidiary to an indirect E.ON subsidiary. Thisreorganization was effective in March 2003. In early 2004, E.ON U.S. begandirect reporting arrangements to E.ON.

 

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. 

 

Effective December 1, 2005, LG&E Energy LLC was renamed E.ON U.S.LLC. 

 

The utilityoperations of E.ON U.S. have continued their separate identities as LG&Eand KU. The preferred stock and debt securities of LG&E and KU were notaffected by these transactions.

 

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RESULTS OFOPERATIONS

 

LG&E

 

NetIncome

 

LG&E’s net income in 2005 increased $33.3million (34.8%) compared to 2004. The increase resulted primarily from higherelectric revenues due to increased retail sales volumes resulting from warmersummer weather and increased base rates implemented for service rendered on andafter July 1, 2004. Wholesale revenues also increased due to higher volumes andhigher prices. These increases were partially offset by increased fuel andpower purchased costs largely due to MISO Day 2 costs.

 

LG&E’s net income in 2005 related to theelectric business increased $32.2 million (36.9%) compared to 2004. Electricoperating revenues increased $171.7 million (21.0%), partially offset by higherfuel for electric generation and power purchased of $122.6 million (40.8%).Income tax and depreciation expense increased $11.7 million (24.2%) and $6.2million (6.2%), respectively. 

 

LG&E’s net income in 2005 related to thenatural gas business increased $1.1 million (13.1%) compared to 2004. Naturalgas operating revenues increased $79.8 million (22.3%) offset by higher naturalgas supply expenses of $73.4 million (27.6%). Other natural gas operations andmaintenance expenses increased $3.6 million (7.2%) and depreciation expenseincreased $1.3 million (7.8%). 

 

During 2005, LG&E made out-of-period adjustments for estimatedover/under collection of ECR revenues to be billed in subsequent periods. Theadjustments related to the reporting periods of March 2003 through December2004. As a result, LG&E revenues for 2005 increased by $5.3 million and netincome for 2005 increased by $3.2 million. LG&E revenues for 2004 and 2003were understated by $2.4 million and $2.9 million, respectively, and net incomewas understated by $1.4 million and $1.8 million, respectively. 

 

LG&E’s net income in 2004 increased $4.8million (5.3%) compared to 2003. The increase resulted primarily from higherelectric revenues due to increased base rates implemented for service renderedon and after July 1, 2004, following the electric rate case order and higherwholesale revenues, somewhat offset by higher maintenance expenses related tostorm restoration costs. Operating expenses for 2004 reflect $12.7 million inexpenses 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. Electricoperating revenues increased $47.5 million (6.2%), offset by higher fuel forelectric generation and power purchased of $22.8 million (8.2%). Other electricoperations and maintenance expenses increased $11.1 million (4.9%). Electricdepreciation expense increased $3.5 million (3.6%). Interest expense increased$1.6 million (6.2%).

 

LG&E’s net income in 2004 related to thenatural gas business decreased $1.8 million (17.6%) compared to 2003. Naturalgas operating revenues increased $31.8 million (9.8%) offset by higher naturalgas supply expenses of $32.4 million (13.9%). Other natural gas operations andmaintenance expenses increased $2.0 million (4.2%).

 

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Revenues

 

The following table presents a comparison ofoperating revenues for the years 2005 and 2004 with the immediately precedingyear.

 
| (in millions)                    | ** ** | ** **                                                    | ** ** |
|---------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                            | ** ** | ** **                                                    | ** ** |
| ** **                            | ** ** | **Increase (Decrease) From Prior Period** | ** ** |
| ** **                            | ** ** | **Electric Revenues**                                    | ** ** | **Gas Revenues** | ** ** |
| **Cause**                             | ** ** | **2005**                                                      | ** ** | **2004** | ** ** | **2005** | ** ** | **2004** | ** ** |
| Retail sales:                         |       |                                                          |       |   |   |   |   |   |   |
| Fuel and gas supply adjustments       |       | $                                                             | 23.3       |   | $ | 5.8 |   | $ | 66.6 |   | $ | 33.6 |   |
| LG&E/KU Merger surcredit          |       | (1.0                                                          | )          | (2.3 | ) | — |   | — |   |
| Environmental cost recovery surcharge |       | 10.0                                                          |       | 7.3 |   | — |   | — |   |
| Earnings sharing mechanism            |       | (5.6                                                          | )          | (5.8 | ) | — |   | — |   |
| Demand side management                |       | (0.3                                                          | )          | 0.4 |   | — |   | (0.6 | ) |
| VDT surcredit                         |       | (0.9                                                          | )          | (1.1 | ) | (0.6 | ) | 0.1 |   |
| Weather normalization adjustment      |       | —                                                        |       | — |   | (2.7 | ) | 3.2 |   |
| Rate changes                          |       | 24.8                                                          |       | 16.8 |   | 4.9 |   | 7.0 |   |
| Variation in sales volumes and other  |       | 27.5                                                          |       | 11.8 |   | (0.1 | ) | (5.8 | ) |
| Total retail sales                    |       | 77.8                                                          |       | 32.9 |   | 68.1 |   | 37.5 |   |
| Wholesale                             |       | 73.7                                                          |       | 15.8 |   | 11.8 |   | (5.1 | ) |
| MISO Day 2                            |       | 18.2                                                          |       | — |   | — |   | — |   |
| Gas transportation-net                |       | —                                                        |       | — |   | (0.7 | ) | 0.1 |   |
| Other                                 |       | 2.0                                                           |       | (1.2 | ) | 0.6 |   | (0.7 | ) |
| Total                                 |       | $                                                             | 171.7      |   | $ | 47.5 |   | $ | 79.8 |   | $ | 31.8 |   |

 

Electric revenues increased in 2005 primarily due to higher wholesalesales and MISO related revenues, higher fuel costs billed to the customerthrough the fuel adjustment clause and new rates implemented in July 2004.These increases were partially offset by the discontinuation of the ESM in thesecond quarter of 2005. Retail revenues increased 5.4% due to higher salesvolume, primarily due to warmer summer weather than experienced in 2004.Cooling degree days increased 13% compared to 2004 and were 14% higher than the20-year average. Wholesale revenues increased due to the combination of a 29%increase in prices and 11% higher volumes. The price increase was largely dueto higher fuel prices and the volume increase was primarily due to increaseddemand for LG&E generation in the region.

 

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 daysincreased 21% compared to 2003 and were 2% higher than the 20-year average.

 

Natural gas revenues in2005 increased due to higher gas supply cost billed to customers through thegas supply clause and increased natural gas rates. New natural gas rates tookeffect in July 2004 increasing revenues by 1.3% in 2005. Despite remaining 1%lower than the 20-year average, the number of heating degree days in 2005increased 6% as compared to 2004. This increase in heating degree days wasoffset by the effect of higher natural gas prices which curtailed natural gasusage and resulted in slightly lower natural gas sales volumes. 

 

Natural gas revenues in2004 increased due to higher gas supply cost billed to customers through thegas supply clause and increased gas rates. New natural gas rates took effect inJuly 2004 increasing revenues by 2.3% in 2004. These increases were partiallyoffset by lower retail sales due to warmer winter weather and lower wholesalesales. Heating degree days decreased 8% as compared to 2003 and were 8% lowerthan the 20-year average. 

 

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Expenses

 

Fuel for electric generation and natural gas supply expenses comprise alarge component of LG&E’s total operating costs. The retail electric ratescontain an FAC and natural gas rates contain a GSC, whereby increases ordecreases in the cost of fuel and natural gas supply are reflected in the FACand GSC factors, subject to approval by the Kentucky Commission, and passedthrough to LG&E’s retail customers.

 

Fuel for electric generation increased $74.1 million (35.6%) in 2005primarily due to: 

•      Increased cost of fuelburned ($61.8 million) due to the MISO’s dispatch of natural gas-fired unitsand higher coal and natural gas prices

•      Increased generation ($12.3million) due to increased demand and the dispatch of units for MISO Day 2

 

Fuel for electric generation increased $10.3 million (5.2%) in 2004primarily due to:

•      Increased cost of fuelburned ($6.4 million) due to higher fuel prices 

•      Increased generation ($3.7million) due to increased demand

 

Power purchased increased $48.5 million (52.7%) in 2005 primarily dueto:

•      Increased unit cost per Mwhof purchases ($40.7 million) due to higher fuel prices

•      Increased volumes purchased($7.7 million) due to increased demand and unit outages

•                  Purchased powercosts from the MISO due to unit outages totaled $9.8 million

 

Power purchased increased $12.5 million (15.7%) in 2004 primarily dueto:

•      Increased unit cost per Mwhof purchases ($9.0 million) due to higher fuel prices

•      Increased volumes purchased($3.4 million) due to increased demand and unit outages

 

Gas supply expenses increased $73.4 million (27.6%) in 2005 primarilydue to:

•      Increased cost of net gassupply ($61.7 million) due to the increase in natural gas prices in 2005

•      Increased volumes of naturalgas delivered to the distribution system ($11.7 million)

 

Gas supply expenses increased $32.4 million (13.9%) in 2004 primarilydue to: 

•      Increased cost of net gassupply ($52.2 million) due to the increase in natural gas prices in 2004

•      Decreased volumes of naturalgas delivered to the distribution system ($19.8 million) 

 

Other operation and maintenance expenses increased $3.1 million (1.0%)in 2005 primarily due to higher other operation expense ($10.6 million) andhigher property taxes ($1.7 million), partially offset by lower maintenanceexpense ($9.2 million).

 

Other operation expenses increased $10.6 million (4.9%) in 2005primarily due to:

•      Increased other power supplycosts ($17.2 million) due largely to MISO Day 2 costs ($18.2 million) foradministrative and allocated charges from the MISO for Day 2 operations

•      Increased steam generationexpenses ($3.5 million) primarily for scrubber reactant and waste disposal 

•      Increased employee benefitcosts ($3.3 million)

•      Increased customer serviceand collection expenses ($2.0 million)

•      Decreased transmission costs($10.5 million), due largely to MISO Day 2 ($13.4 million). Prior to the MISODay 2 market, most bilateral transactions required the purchase oftransmission; however, with the Day 2 market, most transactions are handleddirectly with the MISO and no additional transmission is necessary

•      Decreased distributionoperating costs ($5.0 million) due to fewer storms in 2005

 

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Maintenance expenses decreased $9.2 million (12.7%) in 2005 primarilydue to:

•      Decreased distributionmaintenance ($8.5 million) due to fewer storms in 2005

•      Decreased steam generationexpense ($2.1 million)

•      Increased administrative andgeneral maintenance expenses ($1.3 million)

 

Other operation and maintenance expenses increased $14.6 million (5.0%)in 2004 primarily due to higher maintenance expenses ($15.6 million) and higherproperty and other taxes ($1.6 million), partially offset by lower operationexpenses ($2.5 million).

 

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

•      Increased distributionmaintenance expense ($10.0 million) primarily due to restoration costs relatedto severe May and July storms

•      Increased natural gas systemmaintenance and administrative and general expenses ($2.6 million)

•      Increased steam generationexpense due to timing of scheduled maintenance ($1.4 million)

•      Increased combustion turbineand hydro generation maintenance ($1.6 million)

 

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

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

•      Decreased benefits expense($1.7 million), primarily due to lower pension expense ($2.1 million) as aresult of the $34.5 million pension funding in January 2004, partially offsetby higher medical insurance expense

•      Decreased steam generationexpense ($1.2 million)

•      Increased operations expensedue to storm restoration costs related to severe storms in May and July 2004($3.1 million)

 

Depreciation and amortization increased $7.5 million (6.4%) in 2005 and$3.3 million (2.9%) in 2004 due to additional plant in service. 

 

Other income (expense) - net increased $4.0million (121.2%) in 2005 primarily due to:

•      Increased non-operatingincome ($2.3 million)

•      Decreased income deductions($1.3 million)

•      Increased interest income($0.3 million)

 

Other income (expense) - net increased $3.9 million (54.2%) in 2004primarily due to:

•      Decreased income deductions($3.0 million) primarily for 2003 write-offs of terminated projects 

•      Increased other income ($0.9million)

 

Interest expense increased $4.0 million (12.2%) in 2005 primarily dueto:

•      Increased interest rates onvariable-rate debt ($6.4 million)

•      Increased borrowing from themoney pool ($1.5 million) 

•      Decreased cost of interestrate swaps ($3.2 million) 

•      Decreased costs due torefinancing fixed rate debt with variable rate debt ($0.8 million) 

 

Interest expense increased $2.1 million (6.8%) in 2004 primarily dueto: 

•      Increased borrowing fromFidelia ($6.9 million)

 

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•      Increased cost of interestrate swaps ($3.0 million)

•      Increased cost ofvariable-rate debt ($0.8 million) 

•      Decreased cost due to lowerfirst mortgage debt ($7.2 million)

•      Decreased borrowing from themoney pool ($1.4 million)

 

Details of LG&E’s exposure to variable interest rates on long-termdebt are shown in the table below:

 
| ** **                                                                                                                   | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|------------------------------------------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Unswapped variable rate debt ($ in  millions)                                                                           |       | $        | 363.0      |     | $          | 306.0    |       | $ | 306.0 |   |
| Percentage of unswapped variable rate debt  to total long-term debt                                                          |       | 44.2     | %          | 35.1     | %          | 38.3     | %          |
| Weighted average interest rate on variable  rate debt for the year                                                           |       | 2.49     | %          | 1.28     | %          | 1.10     | %          |
| Weighted average interest rate on total  long-term debt at year-end, including expense amortization and interest rate  swaps |       | 4.13     | %          | 3.92     | %          | 3.58     | %          |
|                                                                                                                              |            |          |            |          |            |          |            |  |  |  |

 

See Note 8 of LG&E’s Notes to the Financial Statements under Item8.

 

Variations in income tax expenses are largely attributable to changesin pre-tax income. LG&E’s 2005 effective income tax rate decreased to 33.5%from the 35.8% rate in 2004 primarily due to the reduction in tax accrualsafter the conclusion of IRS audits. See Note 7 of LG&E’s Notes to FinancialStatements 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 of these policies necessarily involvesjudgments regarding future events, including legal and regulatory challengesand 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 andoperating environment also may have a significant effect, not only on theoperation of the business, but on the results reported through the applicationof accounting measures used in preparing the financial statements and relateddisclosures, even if the nature of the accounting policies applied has notchanged. Specific risks for these critical accounting policies are described inthe following paragraphs. Each of these has a higher likelihood of resulting inmaterially different reported amounts under different conditions or usingdifferent assumptions. Events rarely develop exactly as forecasted and the bestestimates routinely require adjustment. See also Note 1 of LG&E’s Notes toFinancial Statements under Item 8.

 

**Unbilled Revenue** – At each month end LG&E prepares a financialestimate that projects electric and natural gas usage by customers that has notbeen billed. The estimated usage is based on allocating the daily system netdeliveries between billed volumes and unbilled volumes. The allocation is basedon a daily ratio of the number of meter reading cycles remaining in the monthto the total number of meter reading cycles in each month. Each day’s ratio isthen multiplied by each day’s system net deliveries to determine an estimatedbilled and unbilled volume for each day of the accounting period. At December31, 2005, a 10% change in these estimated quantities would cause revenue andaccounts receivable to change by approximately $8.2 million, including $3.2million for electric usage and $5.0 million for natural gas usage. See alsoNote 1 of LG&E’s Notes to Financial Statements under Item 8.

 

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**Allowance for Doubtful Accounts** – At December31, 2005 and 2004, the LG&E allowance for doubtful accounts was $1.1million and $0.8 million, respectively. The allowance is based on the ratio ofthe amounts charged-off during the last twelve months to the retail revenuesbilled over the same period multiplied by the retail revenues billed over thelast four months. Accounts with no payment activity are charged-off after fourmonths, although collection efforts continue thereafter.

 

**Pension and Post-retirement Benefits** – LG&E has both funded and unfundednon-contributory defined benefit pension and post-retirement benefit plans thattogether cover substantially all of its employees. The plans are accounted forunder SFAS No. 87, *Employers’ Accounting forPensions,* and SFAS No. 106, *Employers’ Accounting forPostretirement Benefits Other than Pensions*.

 

The pension and other post-retirement benefit plancosts and liabilities are determined on an actuarial basis and are dependentupon numerous economic assumptions, such as discount rates, rates ofcompensation increases, estimates of the expected return on plan assets andhealth care cost trend rates and demographic and economic assumptions. Theactuarial assumptions used may differ materially from actual results due tochanging market and economic conditions, higher or lower health care costs orturnover, or longer or shorter life spans of participants. These differencesmay result in a significant impact on the amount of expenses recorded in futureperiods. The underlying assumptions and estimates related to the pension andpost-retirement benefit plan costs and liabilities are reviewed annually.

 

The assumed discount rate, expected return on assetsand rate of compensation increases generally have the most significant impacton the pension costs and liabilities. The discount rate is used to calculatethe actuarial present value of the benefits provided by the plans. LG&Ebases its discount rate assumption on Moody’s Aa Corporate Bond Rate rounded tothe nearest 25 basis points, which has a duration comparable to the weightedaverage duration of the plans.

 

The expected long-term rate of return on assets isused to calculate the net periodic pension costs for the plans. To develop theexpected long-term rate of return on assets assumption, consideration is givento the current level of expected returns on risk free investments (primarilygovernment bonds), the historical performance of the asset managers versustheir respective benchmarks, the historical level of the risk premiumassociated with the other asset classes in which the portfolio is invested andthe expectations for future returns of each asset class. The expected returnfor each asset class is then weighted based on a target asset allocation. For2005, the actual return on pension assets was comparable to the assumedexpected rate of return.

 

The following describes the effects on pensionbenefits by changing the major actuarial assumptions discussed above:

 

•                  A 1% change in the assumed discount rate could have an approximate$48.8 million positive or negative impact to the 2005 accumulated benefitobligation of LG&E.

•                  A 25 basis point change in the expected rate of return on assets wouldhave an approximate $0.8 million positive or negative impact on 2005 pensionexpense.

 

Compensation rate increases are used to calculateservice costs and the projected benefit obligation. Such rates are based on areview of LG&E’s actual historical salaries, promotion and bonus increases.For 2005 net periodic pension benefit costs, LG&E used an assumption of4.50%. Based on plan experience, the rate was increased to 5.25% for theprojected benefit obligation at December 31, 2005.

 

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When the plan experience differs from the actuarialassumptions, a portion of the difference may be deferred and is subject toamortization at rates based on the estimated average years of participants’future service. LG&E’s deferred losses on these assumptions were $24.4million (35%) higher in 2005 than 2004 and $14.0 million (25%) higher in 2004than 2003, primarily due to declining discount rate assumptions during theseyears.

 

The assumptions related to the discount rate,retirement, turnover and healthcare cost trends, which represent expected ratesof increase in health care claim payments, generally have the most significantimpact on LG&E’s post-retirement benefit plan costs and liabilities. Unlikepensions, however, assumptions about per capita claims cost by age andparticipation rates also significantly impact post-retirement liability computations.A 1% change in the healthcare cost trend rates could have a positive ornegative impact on the 2005 post-retirement benefit obligation andpost-retirement expense of approximately $3.0 million and $0.3 million,respectively.

 

Additionally, demographic and other economicassumptions affect the pension and post-retirement computations. Beginning withthe December 31, 2005 liability, LG&E replaced the 1983 Group AnnuityMortality tables for males and females with the RP 2000 combined tables for malesand females projected to 2006. These updated healthy mortality tables will beused for the 2006 expense.

 

The benefit obligation is compared with the plan assetvalues to determine a net position. Asset values are increased primarily byactual rates of return on plan assets and by employer contributions. Forexplanation of the investment policy including targeted asset allocations, seeNote 6 of LG&E’s Notes to Financial Statements under Item 8.

 

The pension plans are funded in accordance with allapplicable requirements of the ERISA and the IRC. In accordance with the ERISAguidelines, LG&E made discretionary contributions to the pension plans of$89.1 million in 2003 and $34.5 million in 2004. No contributions were made in2005. LG&E made a discretionary contribution of $17.5 million during 2006and anticipates making additional contributions as deemed necessary.Additionally, LG&E made a contribution of $0.7 million to thepost-retirement plan in 2005, representing the maximum employer contribution underIRC Section 401(h) requirements for all plan years through 2004. LG&E maycontinue to make subsequent contributions in accordance with the maximumfunding limitation governed by tax laws.

 

As prescribed by SFAS No.87, LG&E was required to recognize an additional minimum pension liabilityof $19.2 million and $10.2 million during 2005 and 2004, respectively, sincethe fair value of the plan assets was less than the accumulated benefitobligation at that time. This additional minimum pension liability was recordedas a reduction to other comprehensive income and did not affect net income.Historically low corporate bond rates, used to determine the discount rate,significantly increased the potential value of the pension liabilities abovethe actual value of the plan assets. If the fair value of the plan assetsexceeds the accumulated benefit obligation, the recorded liability will bereduced and other comprehensive income will be restored in the balance sheet.In 2003, LG&E recognized a reduction of the minimum pension liability of$3.1 million.

 

Should poor marketconditions return or should interest rates decline further, LG&E’s unfundedaccumulated benefit obligations and future pension expense could increase. TheCompany believes that such increases are recoverable in whole or in part underfuture rate proceedings or mechanisms.

 

See also Note 6 and Note 14 of LG&E’s Notes to Financial Statementsunder Item 8.

 

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**Regulatory Mechanisms**– Judgments and uncertainties include future regulatory decisions, the impactof deregulation and competition on ratemaking process, and external regulatorydecisions. Regulatory assets represent incurred costs that have been deferredbecause they are probable of future recovery in customer rates based uponKentucky 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, theexisting regulatory assets and liabilities are probable of recovery. Thisdetermination reflects the current regulatory climate in the state. If futurerecovery of costs ceases to be probable the assets and liabilities would berequired to be recognized in current period earnings.

 

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

 

**IncomeTaxes -**Income taxesare accounted for under SFAS No. 109, *Accounting for IncomeTaxes*.  In accordance with this statement, deferred taxassets and liabilities are recognized for the future tax consequencesattributable to differences between the financial statementcarrying amounts of existing assets and liabilities and their respectivetax bases, as measured by enacted tax rates that are expected to be in effectin the periods when the deferred tax assets and liabilities are expected to besettled or realized. Significant judgment is required in determiningthe provision for income taxes, and there are transactions for whichthe ultimate tax outcome is uncertain.

 

Toprovide for these uncertainties or exposures, an allowance is maintainedfor tax contingencies based on management’s best estimate of probableloss. Tax contingencies are analyzed periodically and adjustments aremade when events occur to warrant a change. On September 19, 2005,LG&E received notice from the Congressional Joint Committee on Taxationapproving the Internal Revenue Service’s audit of LG&E’s income tax returnsfor the periods December 1999 through December 2003. As a result of resolvingnumerous tax matters during these periods, LG&E reduced income tax accrualsby $3.8 million during 2005.

 

H. R. 4520, known as the “American Jobs Creation Act of 2004” allowselectric utilities to take a deduction of up to 3% of their qualifiedproduction activities income in 2005. This deduction reduced LG&E’s effectivetax rate by less than 1% for 2005.

 

Kentucky House Bill 272, also known as “Kentucky’s Tax ModernizationPlan,” was signed into law in March 2005. 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. As a result of the income tax ratechange, LG&E’s deferred tax reserve amount will exceed its actual deferredtax liability attributable to existing temporary differences since the newstatutory rates are lower than the rates were when the deferred tax liabilityoriginated. This excess amount is referred to as excess deferred income taxes.In June 2005, LG&E received approval from the Kentucky Commission toestablish and amortize a regulatory liability ($16.3 million) for its netexcess deferred income tax balances. Under this accounting treatment, LG&Ewill amortize its depreciation-related excess deferred income tax balancesunder the average rate assumption method. The average rate assumption methodmatches the amortization of the excess deferred income taxes with the life ofthe timing differences to which it relates. Excess deferred income tax balancesrelated to non-depreciation timing differences will be expensed in the currentyear due to their immaterial amount.

 

LG&E expects to have adequate levels of taxable income to realizeits recorded deferred taxes.

 

For further discussion of income tax issues, see Note 1 and Note 7 ofLG&E’s Notes to Financial Statements

 

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under Item 8.

 

NEW ACCOUNTINGPRONOUNCEMENTS

 

The following recent accounting pronouncements affected LG&E in2005 and 2004:

 

FIN 47

 

LG&E adopted Financial Accounting Standards Board InterpretationNo. 47, *Accounting for Conditional Asset RetirementObligations, an interpretation of FASB Statement No. 143*(FIN 47)effective December 31, 2005. FIN 47 expands the term “conditional assetretirement obligation” as used in SFAS No. 143, *Accountingfor Asset Retirement Obligations,* to refer to a legal obligation toperform an asset retirement activity in which the timing and/or method ofsettlement are conditional on a future event that may or may not be within thecontrol of the entity. The obligation to perform the asset retirement activityis unconditional even though uncertainty exists about the timing and/or methodof settlement. An entity is required to recognize a liability for the fairvalue of a conditional asset retirement obligation if the fair value of theliability can be reasonably estimated. The fair value of a liability for theconditional asset retirement obligation should be recognized when incurred;generally, upon acquisition, construction, or development and through thenormal operation of the asset.

 

As a result of the implementation of FIN 47, LG&E recordedadditional ARO net assets and liabilities during the fourth quarter of 2005 inthe amount of $1.0 million and $15.7 million, respectively. LG&E alsorecorded a cumulative effect adjustment in the amount of $12.3 million toreflect the accumulated depreciation and accretion of ARO assets at thetransition date less amounts previously accrued under regulatory depreciation.A $2.4 million reduction in the accumulated cost of removal regulatoryliability was also recorded for this previously accrued cost of removal.LG&E recorded offsetting regulatory assets of $12.3 million, pursuant toregulatory treatment prescribed under SFAS No. 71, *Accountingfor the Effects of Certain Types of Regulation,*as the costs ofremoval are allowed under Kentucky Commission ratemaking.

 

Had FIN 47 been in effect at the beginning of the 2004 reportingperiod, LG&E would have established asset retirement obligations asdescribed in the following table (in millions):

 
| ** **                         | ** ** | **2005** | ** ** | **2004** | ** ** |
|------------------------------------|------------|----------|------------|----------|------------|
| Provision at beginning of the year |       | $        | 14.8       |     | $          | 14.0 |   |
| Accretion expense                  |       | 0.9      |       | 0.8      |       |
| Provision at end of the year       |       | $        | 15.7       |     | $          | 14.8 |   |

 

See Note 1 of LG&E’s Notes to Financial Statements under Item 8 forfurther discussion of FIN 47.

 

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 sourcesof funds will be sufficient to meet the needs of its business in the foreseeablefuture.

 

As of December 31, 2005, LG&E is in a negative working capitalposition in part because of the classification of certain variable-ratepollution control bonds totaling $246.2 million that are subject to tender forpurchase at the option of the holder as current portion of long-term debt.Backup credit facilities totaling $185 million are in place to fund suchtenders if necessary. LG&E has never needed to access these facilities. LG&Eexpects to cover any working capital deficiencies with cash flow fromoperations, money pool borrowings and borrowings

 

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from Fidelia.

 

Operating Activities

 

Cash provided by operations was $150.4 million, $171.6 million and$163.3 million in 2005, 2004 and 2003, respectively.

 

The 2005 decrease of $21.2 million was primarily the result of changesin:

•                  Inventory ($60.6million) largely the result of increased coal and gas prices

•                  Deferred incometaxes ($19.8 million)

•                  Accountsreceivable ($18.1 million) primarily due to colder December weather

•                  Gas supplyrecovery ($13.5 million) primarily due to higher natural gas prices

•                  Prepayments andother ($9.3 million)

•                  ESM recovery($8.1 million) due to termination of the ESM program

These decreases were partially offset by changes in:

•                  Accounts payable($48.8 million) primarily from the increase in natural gas prices

•                  Earnings ($33.3million)

•                  Pension funding($24.7 million)

 

The 2004 increase of $8.3 million was primarily the result of changesin:

•                  Pension funding($54.6 million)

•                  Gas supply costrecovery ($15.0 million)

•                  ESM ($10.1million)

•                  Prepayments andother ($5.9 million)

•                  Receipt of alitigation settlement ($7.0 million)

These increases were partially offset by changes in:

•                  Accountsreceivable ($66.3 million) including the termination of the accounts receivablesecuritization program

•                  Accrued incometaxes ($22.4 million)

 

See Note 4 of LG&E’s Notes to Financial Statements under Item 8 fora discussion of accounts receivable securitization.

 

Investing Activities

 

LG&E’s primary use of funds for investing activities continues tobe for capital expenditures. Capital expenditures were $138.9 million, $148.3million and $213.0 million in 2005, 2004 and 2003, respectively. LG&Eexpects its capital expenditures for the three-year period ending December 31, 2008,to total approximately $530 million, which consists primarily of constructionestimates associated with the redevelopment of the Ohio Falls hydro facilitytotaling approximately $26 million, construction of Trimble County Unit 2totaling approximately $120 million and on-going construction related togeneration and distribution assets.

 

Net cash used for investing activities decreased $21.1 million in 2005compared to 2004 and $53.7 million in 2004 compared to 2003, primarily due tothe level of construction expenditures.

 

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Financing Activities

 

Net cash inflows (outflows) for financing activities were $(12.1)million, $(7.4) million and $34.2 million in 2005, 2004 and 2003, respectively.

 

Redemptions and maturities of long-term debt for 2005, 2004 and 2003are summarized below:

 
| ($ in millions) |       |                                    |       |                  |       |     |       |                    |       |
|---------------------------|------------|-----------------------------------------|------------|-----------------------|------------|----------|------------|-------------------------|------------|
|                      |       |                                    |       |                  |       |     |       |                    |       |
| **Year**                  | ** ** | **Description**                         | ** ** | **Principal  Amount** | ** ** | **Rate** | ** ** | **Secured/  Unsecured** | ** ** | **Maturity** | ** ** |
|                      |       |                                    |       |                  |       |     |       |                    |       |   |   |
| 2005                      |       | Pollution  control bonds                |       | $                     | 40.0       |     | 5.90       | %                       | Secured    |   | Apr 2023 |   |
| 2005                      |       | Due to  Fidelia                         |       | $                     | 50.0       |     | 1.53       | %                       | Secured    |   | Jan 2005 |   |
| 2005                      |       | Mandatorily  Redeemable Preferred Stock |       | $                     | 1.3        |     | 5.875      | %                       | Unsecured  |   | Jul 2005 |   |
| 2004                      |       | Due to  Fidelia                         |       | $                     | 50.0       |     | 1.53       | %                       | Secured    |   | Jan 2005 |   |
| 2004                      |       | Mandatorily  Redeemable Preferred Stock |       | $                     | 1.3        |     | 5.875      | %                       | Unsecured  |   | Jul 2004 |   |
| 2003                      |       | Pollution  control bonds                |       | $                     | 102.0      |     | 5.625      | %                       | Secured    |   | Aug 2019 |   |
| 2003                      |       | Pollution  control bonds                |       | $                     | 26.0       |     | 5.45       | %                       | Secured    |   | Oct 2020 |   |
| 2003                      |       | First  Mortgage Bonds                   |       | $                     | 42.6       |     | 6.00       | %                       | Secured    |   | Aug 2003 |   |
| 2003                      |       | Mandatorily  Redeemable Preferred Stock |       | $                     | 1.3        |     | 5.875      | %                       | Unsecured  |   | Jul 2003 |   |

 

Issuances of long-term debt for 2005, 2004 and 2003 are summarizedbelow:

 
| ($ in millions) |       |                     |       |                  |       |     |       |                    |       |
|---------------------------|------------|--------------------------|------------|-----------------------|------------|----------|------------|-------------------------|------------|
|                      |       |                     |       |                  |       |     |       |                    |       |
| **Year**                  | ** ** | **Description**          | ** ** | **Principal  Amount** | ** ** | **Rate** | ** ** | **Secured/  Unsecured** | ** ** | **Maturity** | ** ** |
|                      |       |                     |       |                  |       |     |       |                    |       |   |   |
| 2005                      |       | Pollution  control bonds |       | $                     | 40.0       |     | Variable   |                    | Secured    |   | Feb 2035 |   |
| 2004                      |       | Due to  Fidelia          |       | $                     | 25.0       |     | 4.33       | %                       | Secured    |   | Jan 2012 |   |
| 2004                      |       | Due to  Fidelia          |       | $                     | 100.0      |     | 1.53       | %                       | Secured    |   | Jan 2005 |   |
| 2003                      |       | Pollution  control bonds |       | $                     | 128.0      |     | Variable   |                    | Secured    |   | Oct 2033 |   |
| 2003                      |       | Due to  Fidelia          |       | $                     | 100.0      |     | 4.55       | %                       | Unsecured  |   | Apr 2013 |   |
| 2003                      |       | Due to  Fidelia          |       | $                     | 100.0      |     | 5.31       | %                       | Secured    |   | Aug 2013 |   |

 

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 fundingfuture capital requirements through operating cash flow, debt, and/or infusionsof capital from its parent.

 

LG&E has a variety of funding alternatives available to meet itscapital requirements. LG&E maintains a series of bilateral creditfacilities with banks totaling $185 million. Several intercompany financingarrangements are also available. LG&E participates in an intercompany moneypool agreement wherein E.ON U.S. and/or KU make funds available to LG&E atmarket-based rates up to $400 million. Fidelia also provides long-termintercompany funding to LG&E. See Note 9 of LG&E’s Notes to FinancialStatements under Item 8.

 

Regulatory approvals arerequired for LG&E to incur additional debt. The FERC authorizes theissuance of short-term debt while the Kentucky Commission authorizes issuanceof long-term debt. In February 2006,

 

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LG&E received atwo-year authorization from the FERC to borrow up to $400 million in short-termfunds.

 

LG&E’s debt ratings as of December 31, 2005, 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 securityrating is not a recommendation to buy, sell or hold securities and is subjectto revision or withdrawal at any time by the rating agency.

 

Contractual Obligations

 

The following is provided to summarize LG&E’scontractual cash obligations for periods after December 31, 2005. LG&Eanticipates cash from operations and external financing will be sufficient tofund future obligations. Future interest obligations cannot be quantifiedbecause most of LG&E’s debt is variable rate. (See LG&E’s Statements ofCapitalization)

 

(in millions)

 
| ** **                                    | ** ** | **Payments Due by Period** | ** ** |
|-----------------------------------------------|------------|-------------------------------------------|------------|
| **Contractual Cash Obligations**    | ** ** | **2006**                                  | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** | **Thereafter** | ** ** | **Total** | ** ** |
| Short-term debt (a)                           |       | $                                         | 141.2      |   | $ | — |   | $ | — |   | $ | — |   | $ | — |   | $ | — |   | $ | 141.2 |   |
| Long-term debt                                |       | 1.3                                       |       | 1.3 |   | 18.7 |   | — |   | — |   | 799.3 | (b) | 820.6 |   |
| Operating lease (c)                           |       | 3.5                                       |       | 3.6 |   | 3.7 |   | 3.8 |   | 3.8 |   | 18.5 |   | 36.9 |   |
| Unconditional power purchase obligations  (d) |       | 11.1                                      |       | 10.9 |   | 11.0 |   | 11.3 |   | 11.5 |   | 215.1 |   | 270.9 |   |
| Coal and gas purchase obligations (e)         |       | 248.0                                     |       | 197.6 |   | 201.2 |   | 174.2 |   | 188.6 |   | 199.8 |   | 1,209.4 |   |
| Retirement obligations (f)                    |       | 36.7                                      |       | 36.3 |   | 35.7 |   | 35.0 |   | 34.3 |   | 166.1 |   | 344.1 |   |
| Other obligations (g)                         |       | 23.0                                      |       | — |   | — |   | — |   | — |   | — |   | 23.0 |   |
| Total contractual cash obligations            |       | $                                         | 464.8      |   | $ | 249.7 |   | $ | 270.3 |   | $ | 224.3 |   | $ | 238.2 |   | $ | 1,398.8 |   | $ | 2,846.1 |   |

 

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(a)          Represents borrowingsfrom affiliated company due within one year.

(b)         Includes long-term debtof $246.2 million classified as current liabilities because these bonds aresubject to tender for purchase at the option of the holder and to mandatorytender for purchase upon the occurrence of certain events. Maturity dates forthese bonds range from 2013 to 2027. LG&E does not expect to pay theseamounts in 2006.

(c)          Operating leaserepresents the lease of LG&E’s administrative office building.

(d)         Represents future minimumpayments under OVEC purchased power agreements through 2024.

(e)          Represents contracts topurchase coal and natural gas.

(f)            Represents currentlyprojected cash flows for pension plans and other post-employment benefits ascalculated by the actuary.

(g)         Represents constructioncommitments.

 

Off-Balance Sheet Arrangements

 

In the ordinary course of business LG&E has operating leases forvarious vehicles, equipment and real estate. See Note 10 of LG&E’s Notes toFinancial Statements under Item 8 for further discussion of leases.

 

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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 and 7). Commencingin December 1999, LG&E and KU entered into a tax-efficient, 18-year leaseof the CTs. LG&E and KU have provided funds to fully defease the lease, andhave executed an irrevocable notice to exercise an early purchase optioncontained in the lease after 15.5 years. The financial statement treatment ofthis transaction is no different than if LG&E had retained its ownership. Theleasing transaction was entered into following receipt of required state andfederal 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 unwinding ofthe transaction due to governmental actions. No events of default currentlyexist 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, 2005, the maximum aggregate amount of default fees or amounts, whichdecrease over the term of the lease, was $8.2 million, of which LG&E wouldbe responsible for $3.1 million (38%). LG&E has made arrangements with E.ONU.S., via guarantee and regulatory commitment, for E.ON U.S. to pay LG&E’sfull portion of any default fees or amounts.

 

MARKET RISKS

 

LG&E is exposed to market risks from changes in interest rates andcommodity prices. To mitigate changes in cash flows attributable to theseexposures, LG&E uses various financial instruments including derivatives. Derivativepositions are monitored using techniques that include market value andsensitivity analysis.  See Note 1 andNote 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, 2005, the potential change in interest expenseassociated with a 1% change in base interest rates of LG&E’s unhedged debtis estimated at $3.6 million.

 

Interest rate swaps are used to hedge LG&E’s underlyingvariable-rate debt obligations. These swaps hedge specific debt issuances and,consistent with management’s designation, are accorded hedge accountingtreatment. See Note 4 of LG&E’s Notes to Financial Statements under Item 8.

 

As of December 31, 2005, LG&E had swaps with a combined notionalvalue of $211.3 million. The swaps exchange floating-rate interest payments forfixed rate interest payments to reduce the impact of interest rate changes onLG&E’s pollution control bonds. The potential loss in fair value resultingfrom a hypothetical 1% adverse movement in base interest rates is estimated atapproximately $17.6 million as of December 31, 2005. This estimate is derivedfrom third-party valuations. Changes in the market value of these swaps if heldto maturity, as LG&E intends to do, will have no effect on LG&E’s netincome or cash flow. See Note 4 of LG&E’s Notes to Financial Statementsunder Item 8.

 

In February 2005, an LG&Einterest rate swap with a notional amount of $17.0 million matured. The swapwas fully effective upon expiration. As a result, the impact on earnings andother comprehensive income from the swap maturity was less than $0.1 million.

 

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Commodity Price Sensitivity

 

LG&E is exposed to the market price volatility of coal, natural gasand oil (the fuels used to generate electricity) in its wholesale activities.It has limited exposure to such market price volatility as the result of itsretail FAC and GSC commodity price pass-through mechanisms.

 

# **Energy& Risk Management Activities**

# ** **

LG&E conducts energy trading and risk management activities tomaximize the value of power sales from physical assets it owns. Certain energytrading activities are accounted for on a mark-to-market basis in accordancewith SFAS No. 133, *Accounting for DerivativeInstruments and Hedging Activities*, as amended. Wholesale sales ofexcess asset capacity are treated as normal sales under SFAS No. 133, asamended, and are not marked to market.

 

Since the inception of the MISO Day 2 market in April 2005, LG&Ehas been eligible to receive FTRs from the MISO. FTRs are assigned by the MISOto market participants for a twelve-month period of time beginning June 1,2006, for off-peak and peak periods based on each market participant’s share ofgeneration. FTRs are utilized to manage price risk associated with transmissioncongestion. The value of FTRs is determined by the transmission congestioncharges that arise when the transmission grid is congested in the day-aheadmarket. FTRs are obtained through an allocation from the MISO at zero cost,however, they can also be bought and sold. FTRs are derivatives and their fair valueis insignificant due to the lack of liquidity in the forward market.

 

The fair value of LG&E’s energy trading and riskmanagement contracts as of December 31, 2005 and 2004, was less than $1.0million. No changes to valuation techniques for energy trading and riskmanagement activities occurred during 2005 or 2004. 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, pricevolatilities, and interest rates. The Company estimates that a movement inprices of $1 and a change in interest and volatilities of 1% would result in achange of less than $0.1 million. All contracts outstanding at December 31,2005, 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. AtDecember 31, 2005, 100% of the trading and risk management commitments werewith counterparties rated BBB-/Baa3 equivalent or better.

 

Accounts Receivable Securitization

 

LG&E terminated its accounts receivable securitization program inJanuary 2004, and in May 2004, dissolved its inactive accounts receivablesecuritization-related subsidiary, LG&E R. No material pre-tax gains orlosses resulted from the sale of the receivables in 2004 and 2003. LG&E’snet cash flows from LG&E R were reduced by $58.1 million and $6.2 millionfor 2004 and 2003, respectively. The allowance for doubtful accounts associatedwith the eligible securitized receivables at December 31, 2003 was $1.4 million.This allowance was based on historical experience of LG&E. Eachsecuritization facility contained a fully funded reserve for 

 

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uncollectible receivables.

 

RATES AND REGULATION

 

LG&E is subject to the jurisdiction of the Kentucky Commission invirtually all matters related to electric and natural gas utility regulation,and as such, its accounting is subject to SFAS No. 71. Given LG&E’scompetitive position in the marketplace and the status of regulation inKentucky, LG&E has no plans or intentions to discontinue its application ofSFAS No. 71. See Note 3 and Note 10 of LG&E’s Notes to Financial Statementsunder Item 8 for a discussion of rates and regulation.

 

FUTURE OUTLOOK

 

Competition and Customer Choice

 

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. The nature or timing of the ultimatelegislative or regulatory actions regarding industry restructuring and theirimpact 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 is designedto promote 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.

 

Over the last several years, LG&E has taken many steps to keep itsrates low while maintaining high levels of customer satisfaction, including: anincrease in focus on commercial, industrial and residential customers; anincrease in employee involvement and training; and continuous modifications ofits organizational structure. LG&E also strives to control costs throughcompetitive bidding and process improvements. LG&E’s performance innational customer satisfaction surveys continues to be high.

 

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RESULTS OF OPERATIONS

 

# **KU**

# ** **

Net Income

 

KU’s net income in 2005 decreased $21.4 million (16.0%) compared to2004. The decrease resulted primarily from higher fuel, power purchased andother operation and maintenance expenses. These cost increases were largely dueto MISO Day 2 requirements and KU operating unit outages during the year. Theincreases in costs were partially offset by increased retail revenues resultingfrom increased electricity demand and increased base rates, effective July 1,2004. Wholesale revenues also increased due to higher volumes and higherprices.

 

During 2005, KU made out-of-period adjustments for estimated over/undercollection of ECR revenues to be billed in subsequent periods. The adjustmentswere related to the reporting periods of May 2003 through December 2004. As aresult, 2005 revenues for KU were reduced by $2.9 million and net income wasreduced by $1.7 million. KU revenues and net income for 2004 were overstated by$3.2 million and $1.9 million, respectively, and KU revenues and net income for2003 were understated by $0.3 million and $0.2 million, respectively.

 

KU’s net income in 2004 increased $42.1 million (46.1%) compared to2003. The increase resulted primarily from higher revenues, primarily in theretail sector, due to increased base rates resulting from the rate case orderand higher volumes due to a warmer summer. Operating expenses of $2.7 millionrelated to severe May and July storms in 2004 partially offset the increase.

 

Revenues

 

The following table presents a comparison of operating revenues for theyears 2005 and 2004 with the immediately preceding year.

 
| (in millions)                         | ** ** | ** **                                                    | ** ** |
|---------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                            | ** ** | ** **                                                    | ** ** |
| ** **                            | ** ** | **Increase (Decrease) From Prior Period** | ** ** |
| **Cause**                             | ** ** | **2005**                                                      | ** ** | **2004** | ** ** |
| Retail sales:                         |       |                                                          |       |   |   |
| Fuel clause adjustments               |       | $                                                             | 90.3       |   | $ | 15.3 |   |
| KU/LG&E Merger surcredit          |       | (1.6                                                          | )          | (2.6 | ) |
| Environmental cost recovery surcharge |       | 0.7                                                           |       | 20.6 |   |
| Earnings sharing mechanism            |       | (9.0                                                          | )          | (1.0 | ) |
| Demand side management                |       | (0.6                                                          | )          | 1.0 |   |
| VDT surcredit                         |       | (0.7                                                          | )          | (0.5 | ) |
| Rate and rate structure               |       | 24.1                                                          |       | 21.7 |   |
| Variation in sales volumes and other  |       | 33.2                                                          |       | 24.6 |   |
| Total retail sales                    |       | 136.4                                                         |       | 79.1 |   |
| Wholesale sales                       |       | 49.9                                                          |       | 22.0 |   |
| MISO Day 2                            |       | 24.9                                                          |       | — |   |
| Other                                 |       | —                                                        |       | 2.5 |   |
| Total                                 |       | $                                                             | 211.2      |   | $ | 103.6 |   |

 

Electric revenues increased in 2005 primarily due to higher fuel costscost billed to customers through the fuel adjustment clause, an increase inwholesale sales and MISO related revenue, higher rates and a change in the ratestructure. Newrates implemented in July 2004 and the elimination of a volume dependent steprate structure, increased revenues by 3.0% in 2005. These increases werepartially offset by the elimination of the

 

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ESMin the second quarter of 2005. Retail volumes increased 4.7% due toweather. The KU service area experienced a warmer summer in 2005, with coolingdegree days for 2005 46% above 2004 and 18% above the 20-year average whileheating degree days were 3% above 2004 and 1% below the 20-year average.Wholesale revenues increased due to a 31% increase in prices.

 

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 milder winter. Coolingdegree days for 2004 increased 2.9% from 2003 and were 20% below the 20-yearaverage while heating degree days decreased 6.8% from 2003 and were 4% belowthe 20-year average. Wholesale revenues increased due to a combination of a14.2% increase in prices and 1.7% higher volumes. The price increase waslargely due to higher fuel prices and the volume increase was primarily due toincreased electricity demand in the region.

 

Expenses

 

Fuel for electric generation comprises a large component of KU’s totaloperating expenses. KU’s Kentucky jurisdictional electric rates are subject toan FAC whereby increases or decreases are reflected in the FAC factor, subjectto the approval of the Kentucky Commission and passed through to KU’s retailcustomers. KU’s municipal and Virginia jurisdictional electric rates contain afuel adjustment clause whereby increases or decreases in the cost of fuel arereflected in rates, subject to the approval of the FERC and the Virginia Commission,respectively.

 

Fuel for electric generation increased $91.6 million (31.3%) in 2005primarily due to:

•                  Increased costof fuel burned ($87.4 million) due to the MISO’s dispatch of natural gas-firedunits and higher coal and natural gas prices

•                  Increasedgeneration ($4.2 million) due to increased demand and the dispatch of units forMISO Day 2

 

Fuel for electric generation increased $26.1 million (9.8%) in 2004primarily due to:

•                  Increased costof fuel burned ($16.8 million) due to higher fuel prices

•                  Increasedgeneration ($9.3 million) due to increased demand

 

Power purchased expense increased $74.7 million (51.8%) in 2005primarily due to:

•                  Increased unitcost of purchases ($61.3 million) due to higher fuel prices

•                  Increasedvolumes purchased ($13.4 million) due to increased demand and unit outages

•                  Purchased powercosts from the MISO due to unit outages totaled $22.0 million

 

Power purchased expense increased $4.1 million (2.9%) in 2004 primarilydue to:

•                  Increasedvolumes purchased ($5.1 million) due to increased demand and unit outages

•                  Decreased unitcost of purchases ($0.9 million)

 

Other operation and maintenance expenses increased $64.7 million(29.1%) in 2005 primarily due to higher other operation expenses ($53.8million) and higher maintenance expenses ($11.4 million), partially offset bylower property and other taxes ($0.5 million).

 

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Other operation expenses increased $53.8 million (37.0%) in 2005primarily due to:

•      Increased other power supplyexpenses primarily due to MISO Day 2 costs ($43.1 million) for administrativeand allocated charges from the MISO for Day 2 operations

•      Increased employee welfareexpenses ($4.3 million)

•      Increased transmissionexpenses ($2.5 million) primarily due to increased costs associated with MISODay 1. The increase was partially offset by lower transmission costs resultingfrom MISO Day 2 ($2.9 million). Prior to the MISO Day 2 market, most bilateraltransactions required the purchase of transmission; however, with the Day 2market, most transactions are handled directly with the MISO and no additionaltransmission is necessary

•      Increased customer serviceand collections expense ($2.1 million)

•      Increased distribution costs($1.5 million)

 

Maintenance expenses increased $11.4 million (18.7%) in 2005 primarilydue to:

•      Increased steam generationexpenses ($5.9 million) primarily due to unit outages

•      Increased distributionmaintenance ($3.9 million) due to increased line repairs and tree trimmingcosts

•      Increased administrative andgeneral maintenance ($1.1 million)

•      Increased transmission linemaintenance ($0.3 million)

 

Other operation and maintenance expenses increased $0.8 million (0.4%)in 2004 primarily due to higher property and other taxes ($0.8 million) andhigher maintenance expenses ($0.6 million), partially offset by lower otheroperation expenses ($0.4 million).

 

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

•      Increased maintenanceexpense due to storm restoration costs related to severe May and July storms($2.2 million)

•      Increased combustion turbinemaintenance ($2.3 million)

•      Decreased expense due toreclassification of maintenance expense to a regulatory asset ($4.0 million) ofcosts related to the 2003 ice storm based on an order from the KentuckyCommission, to be amortized through June 2009. KU earns a return of theseamortized costs, which are included in KU’s jurisdictional operating expenses.

 

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

•      Decreased benefits expense($3.7 million), primarily due to lower pension expense

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

•      Increased emission allowanceexpense ($4.5 million)

•      Increased combustion turbineoperations expense ($0.9 million)

•      Increased operations expensedue to storm restoration costs related to severe storms in May and July 2004($0.5 million)

 

Depreciation and amortization increased $6.0 million (5.5%) in 2005 and$6.9 million (6.8%) in 2004 primarily due to additional plant in service.

 

Other income - net decreased $2.5 million (33.3%) in 2005 primarily dueto:

•      Increased income deductions($3.7 million)

•      Decreased AFUDC equity ($1.1million)

•      Decreased gain ondisposition of property ($0.5 million)

 

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•      Increased miscellaneousnon-operating income ($2.9 million)

 

Other income - net increased $3.0 million (66.7%) in 2004 primarily dueto:

•      Decreased income deductions($3.1 million)

•      Increased miscellaneous non-operatingincome ($0.6 million)

•      Increased gain ondisposition of property ($0.4 million)

•      Decreased equity in earnings– subsidiary company ($1.1 million)

 

Interest expense increased $5.5 million (21.6%) in 2005 primarily dueto:

•      Increased cost of interestrate swaps ($2.9 million)

•      Increased cost ofvariable-rate debt ($2.4 million)

•      Increased marked to marketof interest rate swaps ($1.6 million)

•      Decreased cost fromrefinancing fixed rate bonds with variable rate bonds ($1.5 million)

 

Interest expense increased $0.3 million (1.2%) in 2004 primarily dueto:

•      Increased borrowing fromFidelia ($9.0 million)

•      Decreased cost from retiredfirst mortgage debt ($4.4 million)

•      Decreased cost of interestrate swaps ($3.5 million)

•      Decreased borrowing from themoney pool ($0.8 million)

 

Details of KU’s exposure to variable interest rates on long-term debtare shown in the table below:

 
| ** **                                                                                                                   | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|------------------------------------------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Variable rate debt, including fixed rate  debt swapped to variable rate debt ($ in millions)                            |       | $        | 325.6      |     | $          | 349.0    |       | $ | 368.6 |   |
| Percentage of variable rate debt to total  long-term debt, including fixed rate debt swapped to variable rate debt           |       | 43.7     | %          | 48.6     | %          | 53.6     | %          |
| Weighted average interest rate on variable  rate debt for the year                                                           |       | 2.52     | %          | 1.32     | %          | 1.07     | %          |
| Weighted average interest rate on total  long-term debt at year-end, including expense amortization and interest rate  swaps |       | 4.50     | %          | 3.43     | %          | 2.96     | %          |
|                                                                                                                              |            |          |            |          |            |          |            |  |  |  |

 

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

 

Variations in income tax expense are largely attributable to changes inpre-tax income. KU’s 2005 effective income tax rate was 36.3%, a slightdecrease from 36.4% in 2004. See Note 7 of KU’s Notes to Financial Statementsunder 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 low rates of inflation in the past few yearshave 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 of these policies necessarily involvesjudgments regarding future events, including legal and regulatory challengesand 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 andoperating environment also may have a significant effect, not only on the

 

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operation of the business, but on the results reported through theapplication of accounting measures used in preparing the financial statementsand related disclosures, even if the nature of the accounting policies appliedhas not changed. Specific risks for these critical accounting policies aredescribed in the following paragraphs. Each of these has a higher likelihood ofresulting in materially different reported amounts under different conditionsor using different assumptions. Events rarely develop exactly as forecasted andthe best estimates routinely require adjustment. See also Note 1 of KU’s Notesto Financial Statements under Item 8.

 

**Unbilled Revenue**– At each month end KU prepares a financial estimate that projects electricusage by customers that has not been billed. The estimated usage is based onallocating the daily system net deliveries between billed volumes and unbilledvolumes. The allocation is based on a daily ratio of the number of meterreading cycles remaining in the month to the total number of meter readingcycles in each month. Each day’s ratio is then multiplied by each day’s systemnet deliveries to determine an estimated billed and unbilled volume for eachday of the accounting period. At December 31, 2005, a 10% change in theseestimated quantities would cause revenue and accounts receivable to change byapproximately $4.4 million. See also Note 1 of KU’s Notes to FinancialStatements under Item 8.

 

**Allowance for Doubtful Accounts** – At December31, 2005 and 2004, the KU allowance for doubtful accounts was $1.5 million and$0.6 million, respectively. The allowance is based on the ratio of the amountscharged-off during the last twelve months to the retail revenues billed overthe same period multiplied by the retail revenues billed over the last fourmonths. Accounts with no payment activity are charged-off after four months,although collection efforts continue thereafter.

 

**Pension and Post-retirement Benefits**– KU has both funded and unfunded non-contributory defined benefit pension andpost-retirement benefit plans that together cover substantially all of itsemployees. The plans are accounted for under SFAS No. 87 and SFAS No. 106.

 

The pension and other post-retirement benefit plancosts and liabilities are determined on an actuarial basis and are dependentupon numerous economic assumptions, such as discount rates, rates ofcompensation increases, estimates of the expected return on plan assets andhealth care cost trend rates and demographic and economic assumptions. Theactuarial assumptions used may differ materially from actual results due tochanging market and economic conditions, higher or lower health care costs orturnover, or longer or shorter life spans of participants. These differencesmay result in a significant impact on the amount of expenses recorded in futureperiods. The underlying assumptions and estimates related to the pension andpost-retirement benefit plan costs and liabilities are reviewed annually.

 

The assumed discount rate, expected return on assetsand rate of compensation increases generally have the most significant impacton the pension costs and liabilities. The discount rate is used to calculatethe actuarial present value of the benefits provided by the plans. KU bases itsdiscount rate assumption on Moody’s Aa Corporate Bond Rate rounded to thenearest 25 basis points, which has a duration comparable to the weightedaverage duration of the plans.

 

The expected long-term rate of return on assets isused to calculate the net periodic pension costs for the plans. To develop theexpected long-term rate of return on assets assumption, consideration is givento the current level of expected returns on risk free investments (primarilygovernment bonds), the historical performance of the asset managers versustheir respective benchmarks, the historical level of the risk premiumassociated with the other asset classes in which the portfolio is invested andthe expectations for future returns of each asset class. The expected returnfor each asset class is then weighted based on a target asset allocation. For2005, the actual return on pension assets was comparable to the assumedexpected rate of return.

 

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The following describes the effects on pensionbenefits by changing the major actuarial assumptions discussed above:

 

•                  A1% change in the assumed discount rate could have an approximate $32.6 millionpositive or negative impact to the 2005 accumulated benefit obligation of KU.

•                  A25 basis point change in the expected rate of return on assets would have anapproximate $0.6 million positive or negative impact on 2005 pension expense.

 

Compensation rate increases are used to calculateservice costs and the projected benefit obligation. Such rates are based on areview of KU’s historical salaries, promotion and bonus increases. For 2005 netperiodic pension benefit costs, KU used an assumption of 4.50%. Based on planexperience, the rate was increased to 5.25% for the projected benefitobligation at December 31, 2005.

 

When the plan experience differs from the actuarialassumptions, a portion of the difference may be deferred and is subject toamortization at rates based on the estimated average years of participants’future service. KU’s deferred losses on these assumptions were $24.6 million(44%) higher in 2005 than 2004 and $28.3 million (101%) higher in 2004 than2003, primarily due to declining discount rate assumptions during these years.

 

The assumptions related to the discount rate,retirement, turnover and healthcare cost trends, which represent expected ratesof increase in health care claim payments, generally have the most significantimpact on post-retirement benefit plan costs and liabilities. Unlike pensions,however, assumptions about per capita claims cost by age and participation ratesalso significantly impact post-retirement liability computations. A 1% changein the healthcare cost trend rates could have a positive or negative impact onthe 2005 post-retirement benefit obligation and post-retirement expense ofapproximately $6.0 million and $0.4 million, respectively.

 

Additionally, demographic and other economicassumptions affect the pension and post-retirement computations. Beginning withthe December 31, 2005 liability, KU replaced the 1983 Group Annuity Mortalitytables for males and females with the RP 2000 combined tables for males andfemales projected to 2006. These updated healthy mortality tables will be usedfor the 2006 expense.

 

The benefit obligation is compared with the plan assetvalues to determine a net position. Asset values are increased primarily byactual rates of return on plan assets and by employer contributions. Forexplanation of the investment policy including targeted asset allocations, seeNote 6 of KU’s Notes to Financial Statements under Item 8.

 

The pension plans are funded in accordance with allapplicable requirements of the ERISA and the IRC. In accordance with the ERISAguidelines, KU made discretionary contributions to the pension plans of $10.2million in 2003 and $43.4 million in 2004. No contributions were made in 2005.KU anticipates making additional contributions as deemed necessary. Additionally,KU made a contribution of $3.0 million to the post-retirement plan in 2005,representing the maximum employer contribution under IRC Section 401(h)requirements for all plan years through 2004. KU may continue to makesubsequent contributions in accordance with the maximum funding limitationgoverned by tax laws.

 

As prescribed by SFAS No.87, KU was required to recognize an additional minimum pension liability of$9.5 million and $12.4 million during 2005 and 2004, respectively, since thefair value of the plan assets was less than the accumulated benefit obligationat that time. This additional minimum pension liability was recorded as a

 

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reduction to othercomprehensive income and did not affect net income. Historically low corporatebond rates, used to determine the discount rate, significantly increased thepotential value of the pension liabilities above the actual value of the planassets. If the fair value of the plan assets exceeds the accumulated benefitobligation, the recorded liability will be reduced and other comprehensiveincome will be restored in the balance sheet. In 2003, KU recognized areduction of the minimum pension liability of $7.7 million.

 

Should poor marketconditions return or should interest rates decline further, KU’s unfundedaccumulated benefit obligations and future pension expense could increase. TheCompany believes that such increases are recoverable in whole or in part underfuture rate proceedings or mechanisms.  Seealso Note 6 and Note 13 of KU’s Notes to Financial Statements under Item 8.

 

**Regulatory Mechanisms**– Judgments and uncertainties include future regulatory decisions, the impactof deregulation and competition on the ratemaking process and externalregulatory decisions. Regulatory assets represent incurred costs that have beendeferred because they are probable of future recovery in customer rates based uponKentucky Commission, Virginia Commission and FERC orders. Regulatoryliabilities generally represent obligations to make refunds to customers forprevious collections based upon orders by the Kentucky Commission, VirginiaCommission and FERC. Management believes, based on orders, the existingregulatory assets and liabilities are probable of recovery. This determinationreflects the current regulatory climate in the state. If future recovery ofcosts ceases to be probable the assets and liabilities would be required to berecognized in current period earnings.  Seealso Note 3 of KU’s Notes to Financial Statements under Item 8.

 

**IncomeTaxes –**Income taxesare 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 for income taxes, and there aretransactions for which the ultimate tax outcome is uncertain.

 

Toprovide for these uncertainties or exposures, an allowance is maintainedfor tax contingencies based on management’s best estimate of probableloss. Tax contingencies are analyzed periodicallyand adjustments are made when events occur to warrant a change.On September 19, 2005, KU received notice from the Congressional JointCommittee on Taxation approving the Internal Revenue Service’s audit of KU’sincome tax returns for the periods December 1999 through December 2003. As aresult of resolving numerous tax matters during these periods, KU reducedincome tax accruals by $4.6 million during 2005.

 

Thecompany recognized additional deferred income tax expense in the third quarterof 2005 ($3.1 million) related to the undistributed earnings of its EEIunconsolidated investment. Recent EEI management decisions regarding changes inthe distribution of EEI’s earnings led to the decision to provide deferredtaxes for all book and tax temporary differences related to this investment.

 

H. R. 4520, known as the “American Jobs Creation Act of 2004” allowselectric utilities to take a deduction of up to 3% of their qualifiedproduction activities income in 2005. This deduction reduced KU’s effective taxrate by less than 1% for 2005.

 

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Kentucky HouseBill 272, also known as “Kentucky’s Tax Modernization Plan,” was signed intolaw in March 2005. This bill contains a number of changes in Kentucky’s taxsystem, including the reduction of the Corporate income tax rate from 8.25% to7% effective January 1, 2005, and a further reduction to 6% effective January1, 2007. As a result of the income tax rate change, KU’s deferred tax reserveamount will exceed its actual deferred tax liability attributable to existingtemporary differences since the new statutory rates are lower than the rateswere when the deferred tax liability originated. This excess amount is referredto as excess deferred income taxes. In June 2005, KU received approval from theKentucky Commission to establish and amortize a regulatory liability ($11.0million) for its net excess deferred income tax balances. Under this accountingtreatment, KU will amortize its depreciation-related excess deferred income taxbalances under the average rate assumption method. The average rate assumptionmethod matches the amortization of the excess deferred income taxes with thelife of the timing differences to which it relates. Excess deferred income taxbalances related to non-depreciation timing differences will be expensed in thecurrent year due to their immaterial amount.

 

KU expects to have adequate levels of taxable income to realize itsrecorded deferred taxes.

 

For further discussion of income tax issues, see Note 1 and Note 7 ofKU’s Notes to Financial Statements under Item 8.

 

NEW ACCOUNTINGPRONOUNCEMENTS

 

The following recent accounting pronouncements affected KU in 2005 and2004:

 

FIN 47

 

KU adopted FIN 47 effective December 31, 2005. FIN 47 expands the term“conditional asset retirement obligation” as used in SFAS No. 143 to refer to alegal obligation to perform an asset retirement activity in which the timingand/or method of settlement are conditional on a future event that may or maynot be within the control of the entity. The obligation to perform the assetretirement activity is unconditional even though uncertainty exists about thetiming and/or method of settlement. An entity is required to recognize aliability for the fair value of a conditional asset retirement obligation ifthe fair value of the liability can be reasonably estimated. The fair value ofa liability for the conditional asset retirement obligation should berecognized when incurred; generally, upon acquisition, construction, ordevelopment and through the normal operation of the asset.

 

As a result of the implementation of FIN 47, KU recorded additional AROnet assets and liabilities during the fourth quarter of 2005 in the amount of$0.5 million and $4.6 million, respectively. KU also recorded a cumulativeeffect adjustment in the amount of $4.1 million to reflect the accumulateddepreciation and accretion of ARO assets at the transition date less amountspreviously accrued under regulatory depreciation. KU recorded offsettingregulatory assets of $4.1 million, pursuant to regulatory treatment prescribedunder SFAS No. 71, as the costs of removal are allowed under KentuckyCommission ratemaking.

 

Had FIN 47 been in effect at the beginning of the 2004 reportingperiod, KU would have established asset retirement obligations as described inthe following table (in millions):

 
| ** **                         | ** ** | **2005** | ** ** | **2004** | ** ** |
|------------------------------------|------------|----------|------------|----------|------------|
| Provision at beginning of the year |       | $        | 4.3        |     | $          | 4.1 |   |
| Accretion expense                  |       | 0.3      |       | 0.2      |       |
| Provision at end of the year       |       | $        | 4.6        |     | $          | 4.3 |   |

 

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See Note 1 of KU’s Notes to Financial Statements under Item 8 for a furtherdiscussion of FIN 47.

 

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 fundswill be sufficient to meet the needs of its business in the foreseeable future.

 

As of December 31, 2005, KU is in a negative working capital positionin part because of the classification of certain variable-rate pollutioncontrol bonds totaling $87.1 million that are subject to tender for purchase atthe option of the holder as current portion of long-term debt. KU expects tocover any working capital deficiencies with cash flow from operations, moneypool borrowings and borrowings from Fidelia.

 

Operating Activities

 

Cash provided by operations was $220.7 million, $185.9 million and$233.4 million in 2005, 2004 and 2003, respectively.

 

The 2005 increase of $34.8 million was primarily the result of changesin:

•                  Pension funding($35.9 million)

•                  Accounts payable($16.2 million) largely due to the increase in power purchased resulting fromincreased fuel costs

•                  Accountsreceivable ($8.9 million)

These increases were partially offset by:

•                  Lower earnings($21.4 million)

 

The 2004 decrease of $47.5 million was primarily due to the change in:

•                  Accountsreceivable ($63.0 million), including the termination of the accountsreceivable securitization program

•                  Additionalpension funding ($33.2 million)

•                  Lower environmentalcost recovery ($14.2 million)

These decreases were partially offset by:

•                  Higher earnings($42.1 million)

•                  Higher accountspayable ($13.3 million)

•                  Receipt of alitigation settlement ($11.4 million)

 

See Note 4 of KU’s Notes to Financial Statements under Item 8 for adiscussion of accounts receivable securitization.

 

Investing Activities

 

KU’s primary use of funds for investing activities continues to be forcapital expenditures. Capital expenditures were $140.0 million, $157.6 millionand $341.8 million in 2005, 2004 and 2003, respectively. KU expects its capitalexpenditures for the three-year period ending December 2008, to totalapproximately $1.5 billion, which consists primarily of construction estimates associatedwith installation of FGDs on Ghent and Brown units totaling approximately $560million, as described in the section titled “Environmental Matters,” theconstruction of Trimble County Unit 2 totaling approximately $510 million andon-going construction on generation and

 

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distribution assets.

 

Net cash used for investing activities increased $4.0 million in 2005compared to 2004 primarily due to the increase in restricted cash in 2005,partially offset by lower capital expenditures. Restricted cash is the escrowedproceeds of the Pollution Control Bonds issued in 2005 which will be disbursedas qualifying costs are incurred. Net cash used for investing activitiesdecreased $184.1 million in 2004 compared to 2003 primarily due to the level ofconstruction expenditures. NOx expenditures were zero in 2005 and approximately$45.0 million in 2004, while CT expenditures were approximately $8.1 million in2005 and $13.7 million in 2004.

 

Financing Activities

 

Net cash inflows (outflows) from financing activities were $(57.0)million, $(28.6) million and $107.8 million in 2005, 2004 and 2003, respectively.

 

Redemptions and maturities of long-term debt for 2005, 2004 and 2003are summarized below:

 
| ($ in millions) |       |                     |       |                  |       |     |       |                    |       |
|---------------------------|------------|--------------------------|------------|-----------------------|------------|----------|------------|-------------------------|------------|
|                      |       |                     |       |                  |       |     |       |                    |       |
| **Year**                  | ** ** | **Description**          | ** ** | **Principal  Amount** | ** ** | **Rate** | ** ** | **Secured/  Unsecured** | ** ** | **Maturity** | ** ** |
| 2005                      |       | First  mortgage bonds    |       | $                     | 50.0       |     | 7.55       | %                       | Secured    |   | Jun 2025 |   |
| 2005                      |       | Due to  Fidelia          |       | $                     | 75.0       |     | 2.29       | %                       | Secured    |   | Dec 2005 |   |
| 2004                      |       | Pollution  control bonds |       | $                     | 4.8        |     | Variable   |                    | Secured    |   | Feb 2032 |   |
| 2004                      |       | Pollution  control bonds |       | $                     | 50.0       |     | 5.75       | %                       | Secured    |   | Dec 2023 |   |
| 2003                      |       | First  mortgage bonds    |       | $                     | 62.0       |     | 6.32       | %                       | Secured    |   | Jun 2003 |   |
| 2003                      |       | First  mortgage bonds    |       | $                     | 33.0       |     | 8.55       | %                       | Secured    |   | May 2027 |   |

 

Issuances of long-term debt for 2005, 2004 and 2003 are summarizedbelow:

 
| ($ in millions) |       |                     |       |                  |       |     |       |                    |       |
|---------------------------|------------|--------------------------|------------|-----------------------|------------|----------|------------|-------------------------|------------|
|                      |       |                     |       |                  |       |     |       |                    |       |
| **Year**                  | ** ** | **Description**          | ** ** | **Principal  Amount** | ** ** | **Rate** | ** ** | **Secured/  Unsecured** | ** ** | **Maturity** | ** ** |
| 2005                      |       | Pollution  control bonds |       | $                     | 13.3       |     | Variable   |                    | Secured    |   | Jun 2035 |   |
| 2005                      |       | Pollution  control bonds |       | $                     | 13.3       |     | Variable   |                    | Secured    |   | Jun 2035 |   |
| 2005                      |       | Due to  Fidelia          |       | $                     | 50.0       |     | 4.735      | %                       | Unsecured  |   | Jul 2015 |   |
| 2005                      |       | Due to  Fidelia          |       | $                     | 75.0       |     | 5.36       | %                       | Unsecured  |   | Dec 2015 |   |
| 2004                      |       | Due to  Fidelia          |       | $                     | 50.0       |     | 4.39       | %                       | Unsecured  |   | Jan 2012 |   |
| 2004                      |       | Pollution  control bonds |       | $                     | 50.0       |     | Variable   |                    | Secured    |   | Oct 2034 |   |
| 2003                      |       | Due to  Fidelia          |       | $                     | 100.0      |     | 4.55       | %                       | Unsecured  |   | Apr 2013 |   |
| 2003                      |       | Due to  Fidelia          |       | $                     | 75.0       |     | 5.31       | %                       | Secured    |   | Aug 2013 |   |
| 2003                      |       | Due to  Fidelia          |       | $                     | 33.0       |     | 4.24       | %                       | Secured    |   | Nov 2010 |   |
| 2003                      |       | Due to  Fidelia          |       | $                     | 75.0       |     | 2.29       | %                       | Secured    |   | Dec 2005 |   |

 

In May 2005, KU repaid a $26.7 million loan against the cash surrendervalue of life insurance policies.

 

In October 2005, KU redeemed all of its outstanding shares of preferredstock for $40.8 million. KU paid $101 per share for the 4.75% Series and$102.939 per share for the 6.53% Series.

 

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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. KU anticipates funding futurecapital requirements through operating cash flow, debt, and/or infusion ofcapital from its parent.

 

KU has a variety of intercompany funding alternatives available to meetits capital requirements. KU participates in an intercompany money poolagreement wherein E.ON U.S. and/or LG&E make funds available to KU atmarket-based rates up to $400 million. Fidelia also provides long-termintercompany funding to KU. See Note 9 of KU’s Notes to Financial Statementsunder Item 8.

 

Regulatory approvals arerequired for KU to incur additional debt. The Virginia Commission and the FERCauthorize the issuance of short-term debt while the Kentucky Commission, theVirginia Commission and the Tennessee Regulatory Authority authorize theissuance of long-term debt. In February 2006, KU received approvals from theVirginia Commission and from the FERC to borrow up to $400 million inshort-term funds.

 

KU’s debt ratings as of December 31, 2005, 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 securityrating is not a recommendation to buy, sell or hold securities and is subjectto revision or withdrawal at any time by the rating agency.

 

Contractual Obligations

 

The following is provided to summarize KU’scontractual cash obligations for periods after December 31, 2005. KUanticipates cash from operations and external financing will be sufficient tofund future obligations. Future interest obligations cannot be quantifiedbecause most of KU’s debt is variable rate. (See KU’s Statements ofCapitalization)

 
| (in millions)                            |       |                                      |       |
|-----------------------------------------------|------------|-------------------------------------------|------------|
| ** **                                    | ** ** | ** **                                | ** ** |
| ** **                                    | ** ** | **Payments Due by Period** | ** ** |
| **Contractual Cash Obligations**    | ** ** | **2006**                                  | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** | **Thereafter** | ** ** | **Total** | ** ** |
| Short-term debt (a)                           |       | $                                         | 69.7       |   | $ | — |   | $ | — |   | $ | — |   | $ | — |   | $ | — |   | $ | 69.7 |   |
| Long-term debt                                |       | 36.0                                      |       | 55.0 |   | — |   | — |   | 33.0 |   | 622.6 (b | ) | 746.6 |   |
| Unconditional power purchase obligations  (c) |       | 24.2                                      |       | 24.5 |   | 23.3 |   | 24.7 |   | 24.9 |   | 358.2 |   | 479.8 |   |
| Coal purchase obligations (d)                 |       | 307.6                                     |       | 203.7 |   | 109.4 |   | 6.4 |   | — |   | — |   | 627.1 |   |
| Retirement obligations (e)                    |       | 26.1                                      |       | 26.0 |   | 25.6 |   | 25.4 |   | 25.2 |   | 126.7 |   | 255.0 |   |
| Other obligations (f)                         |       | 120.2                                     |       | — |   | — |   | — |   | — |   | — |   | 120.2 |   |
| Total contractual cash obligations            |       | $                                         | 583.8      |   | $ | 309.2 |   | $ | 158.3 |   | $ | 56.5 |   | $ | 83.1 |   | $ | 1,107.5 |   | $ | 2,298.4 |   |

 

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(a)          Represents borrowingsfrom affiliated company due within one year.

(b)         Includes long-term debtof $87.1 million classified as current liabilities because these bonds aresubject to tender for 

 

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purchase at the option ofthe holder and to mandatory tender for purchase upon the occurrence of certainevents. Maturity dates for these bonds range from 2024 to 2032. KU does notexpect to pay these amounts in 2006.

(c)          Represents futureminimum payments under OVEC and OMU purchased power agreements through 2024.

(d)         Represents contracts topurchase coal.

(e)          Represents currentlyprojected cash flows for pension plans and other post-employment benefits ascalculated by the actuary.

(f)            Representsconstruction commitments.

 

Off-Balance Sheet Arrangements

 

In the ordinary course of business KU has operating leases for variousvehicles, equipment and real estate. See Note 10 of KU’s Notes to FinancialStatements under Item 8 for further discussion of leases.  

 

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 and 7). Commencingin December 1999, LG&E and KU entered into a tax-efficient, 18-year leaseof the CTs. KU and LG&E have provided funds to fully defease the lease, andhave executed 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 existwith 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 December31, 2005, the maximum aggregate amount of default fees or amounts, whichdecrease over the term of the lease, was $8.2 million, of which KU would beresponsible for $5.1 million (62%). KU has made arrangements with E.ON U.S.,via guarantee and regulatory commitment, for E.ON U.S. to pay KU’s full portionof any default fees or amounts.

 

MARKET RISKS

 

KU is exposed to market risks from changes in interest rates andcommodity prices. To mitigate changes in cash flows attributable to theseexposures, KU uses various financial instruments including derivatives. Derivativepositions are monitored using techniques that include market value andsensitivity analysis.  See Note 1 andNote 4 of KU’s Notes to Financial Statements under Item 8.

 

Interest Rate Sensitivity

 

KU has short-term and long-term variable-rate debt obligationsoutstanding. At December 31, 2005, the potential change in interest expenseassociated with a 1% change in base interest rates of KU’s variable-rate debtis estimated at $3.3 million.

 

An interest rate swap is used to hedge KU’s underlying debt obligations.The swap hedges specific debt issuances and, consistent with management’sdesignation, are accorded hedge accounting treatment. See Note 4

 

64

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

 

As of December 31, 2005, KU has a swap with a notional value of $53.0million. The swap exchanged fixed-rate interest payments for floating rateinterest payments on KU’s Series P first mortgage bonds. The potential loss infair value resulting from a hypothetical 1% adverse movement in base interestrates is estimated at $0.6 million as of December 31, 2005. This estimate isderived from third-party valuations. Changes in the market value of theseswaps, if held to maturity, will have no effect on KU’s net income or cash flow.See Note 4 of KU’s Notes to Financial Statements under Item 8.

 

In June 2005, a KU interestrate swap with a notional amount of $50.0 million was terminated by thecounterparty pursuant to the terms of the swap agreement. KU received a paymentof $1.9 million in consideration for the termination of the agreement. KU alsocalled the underlying debt (First Mortgage Bond Series R) and paid a callpremium of $1.9 million. The swap was fully effective upon termination. Noimpact on earnings occurred as a result of the bond call and related swaptermination.

 

In February 2004, KU terminated the swaps it had in place at December31, 2003, related to the Series 9 pollution control bonds. The notional amountof the terminated swap was $50.0 million and KU received a payment of $2.0million as part of the termination. The swap was terminated because it was nolonger an effective hedge of the underlying bond.

 

Commodity Price Sensitivity

 

KU is exposed to the market price volatility of coal, natural gas andoil (the fuels used to generate electricity) in its wholesale activities. Ithas limited exposure to such market price volatility as the result of itsretail FAC commodity price pass-through mechanism.

 

# **Energy& Risk Management Activities**

# ** **

KU conducts energy trading and risk management activities to maximizethe value of power sales from physical assets it owns. Certain energy tradingactivities are accounted for on a mark-to-market basis in accordance with SFAS No.133, as amended. Wholesale sales of excess asset capacity are treated as normalsales under SFAS No. 133, as amended, and are not marked to market.

 

Since the inception ofthe MISO Day 2 market in April 2005, KU has been eligible to receive FTRs fromthe MISO. FTRs are assigned by the MISO to market participants for atwelve-month period of time beginning June 1, 2006, for off-peak and peakperiods based on each market participant’s share of generation. FTRs areutilized to manage price risk associated with transmission congestion. Thevalue of FTRs is determined by the transmission congestion charges that arisewhen the transmission grid is congested in the day-ahead market. FTRs areobtained through an allocation from the MISO at zero cost, however, they canalso be bought and sold. FTRs are derivatives and their fair value isinsignificant due to the lack of liquidity in the forward market.

 

The fair value of KU’s energy trading and riskmanagement contracts as of December 31, 2005 and 2004, was less than $1.0million. No changes to valuation techniques for energy trading and riskmanagement activities

 

65

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occurred during 2005. 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, pricevolatilities, and interest rates. The Company estimates that a movement inprices of $1 and a change in interest and volatilities of 1% would result in achange of less than $0.1 million. All contracts outstanding at December 31,2005 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 December31, 2005, 100% of the trading and risk management commitments were withcounterparties rated BBB-/Baa3 equivalent or better.

 

Accounts Receivable Securitization

 

KU terminated its accounts receivable securitization program in January2004, and in May 2004, dissolved its inactive accounts receivablesecuritization-related subsidiary, KU R. No material pre-tax gains or lossesresulted from the sale of the receivables in 2004 and 2003. KU’s net cash flowsfrom KU R were reduced by $50.1 million and $0.1 million for 2004 and 2003,respectively. The allowance for doubtful accounts associated with the eligiblesecuritized receivables at December 31, 2003 was $0.5 million. This allowancewas based on historical experience of KU. Each securitization facilitycontained a fully funded reserve for uncollectible receivables.

 

RATES AND REGULATION

 

KU is subject to the jurisdiction of the Kentucky Commission, the VirginiaCommission, the Tennessee Regulatory Authority and the FERC in virtually allmatters related to electric utility regulation, and as such, its accounting issubject to SFAS No. 71. Given KU’s competitive position in the marketplace andthe status of regulation in Kentucky and Virginia, KU has no plans orintentions to discontinue its application of SFAS No. 71. See Note 3 and Note10 of KU’s Notes to Financial Statements under Item 8.

 

FUTURE OUTLOOK

 

Competition and Customer Choice

 

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. The nature or timing of the ultimatelegislative or regulatory actions regarding industry restructuring and theirimpact on KU, 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 is designedto promote 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.

 

Virginia has enacted a phase-in of customer choice through the VirginiaElectric Restructuring Act, however,

 

66

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KU’s service territory has beeneffectively exempted from retail choice until such time as retail choice isoffered to customers in KU’s other service territories.

 

Over the last several years, KU has taken many steps to keep its rateslow while maintaining high levels of customer satisfaction, including: anincrease in focus on commercial, industrial and residential customers; anincrease in employee involvement and training; and continuous modifications ofits organizational structure. KU also strives to control costs throughcompetitive bidding and process improvements. KU’s performance in nationalcustomer satisfaction surveys continues to be high.

 

# **ITEM 7A. Quantitative andQualitative Disclosures 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.

 

67

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# **ITEM 8. Financial Statements andSupplementary Data.**

# ** **

INDEX OF ABBREVIATIONS

 
| AEP                 |   | American Electric Power Company, Inc.                                   |
|---------------------|--------|-------------------------------------------------------------------------|
| AFUDC               |   | Allowance for Funds Used During  Construction                           |
| AG                  |   | Attorney General of Kentucky                                            |
| APBO                |   | Accumulated Postretirement Benefit  Obligation                          |
| ARO                 |   | Asset Retirement Obligation                                             |
| CAIR                |   | Clean Air Interstate Rule                                               |
| CAMR                |   | Clean Air Mercury Rule                                                  |
| Capital Corp.       |   | E.ON U.S. Capital Corp. (formerly LG&E  Capital Corp.)              |
| CAVR                |   | Clean Air Visibility Rule                                               |
| Clean Air Act       |   | The Clean Air Act, as amended in 1990                                   |
| CCN                 |   | Certificate of Public Convenience and  Necessity                        |
| Company             |   | LG&E or KU, as applicable                                           |
| Companies           |   | LG&E and KU                                                         |
| CO2                 |   | Carbon Dioxide                                                          |
| CT                  |   | Combustion Turbines                                                     |
| CWIP                |   | Construction Work in Progress                                           |
| DOE                 |   | Department of Energy                                                    |
| DOJ                 |   | Department of Justice                                                   |
| 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                                                                 |
| E.ON U.S.           |   | E.ON U.S. LLC (formerly LG&E Energy LLC  and LG&E Energy Corp.) |
| E.ON U.S. Services  |   | E.ON U.S. Services Inc. (formerly LG&E  Energy Services Inc.)       |
| EPA                 |   | U.S. Environmental Protection Agency                                    |
| EPAct 2005          |   | Energy Policy Act of 2005                                               |
| ERISA               |   | Employee Retirement Income Security Act of  1974, as amended            |
| ESM                 |   | Earnings Sharing Mechanism                                              |
| Fidelia             |   | Fidelia Corporation (an E.ON affiliate)                                 |
| FAC                 |   | Fuel Adjustment Clause                                                  |
| FASB                |   | Financial Accounting Standards Board                                    |
| FERC                |   | Federal Energy Regulatory Commission                                    |
| FGD                 |   | Flue Gas Desulfurization                                                |
| FIN                 |   | FASB Interpretation                                                     |
| FPA                 |   | Federal Power Act                                                       |
| FSP                 |   | FASB Staff Position                                                     |
| FT and FT-A         |   | Firm Transportation                                                     |
| FTR                 |   | Financial Transmission Right                                            |
| GSC                 |   | Gas Supply Clause                                                       |
| GFA                 |   | Grandfathered Transmission Agreement                                    |
| IBEW                |   | International Brotherhood of Electrical  Workers                        |
| IMEA                |   | Illinois Municipal Electric Agency                                      |
| IMPA                |   | Indiana Municipal Power Agency                                          |
| IRC                 |   | Internal Revenue Code of 1986, as amended                               |
| IRP                 |   | Integrated Resource Plan                                                |
| ITP                 |   | Independent Transmission Provider                                       |
| 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                                                      |

 

68

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| Kv                  |   | Kilovolts                                               |
|---------------------|--------|---------------------------------------------------------|
| 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 (now E.ON U.S. LLC)                 |
| LG&E R          |   | LG&E Receivables LLC                                |
| LG&E Services   |   | LG&E Energy Services Inc. (now E.ON  U.S. Services) |
| LMP                 |   | Locational Marginal Pricing                             |
| LNG                 |   | Liquefied Natural Gas                                   |
| Mcf                 |   | Thousand Cubic Feet                                     |
| MGP                 |   | Manufactured Gas Plant                                  |
| MISO                |   | Midwest Independent Transmission System  Operator, Inc. |
| MMBtu               |   | Million British thermal units                           |
| Moody’s        |   | Moody’s Investor Services, Inc.                    |
| Mva                 |   | Megavolt-ampere                                         |
| 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 1935          |   | Public Utility Holding Company Act of 1935              |
| PUHCA 2005          |   | Public Utility Holding Company Act of 2005              |
| ROE                 |   | Return on Equity                                        |
| RTO                 |   | Regional Transmission Organization                      |
| RTOR                |   | Regional Through and Out Rates                          |
| 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                                          |
| SPP                 |   | Southwest Power Pool, Inc.                              |
| TEMT                |   | Transmission and Energy Markets Tariff                  |
| Tennessee Gas       |   | Tennessee Gas Pipeline Company                          |
| Texas Gas           |   | Texas Gas Transmission LLC                              |
| Trimble County      |   | LG&E’s Trimble County Unit 1                   |
| TVA                 |   | Tennessee Valley Authority                              |
| 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                        |

 

69

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Louisville Gas and Electric Company

Statements of Income

(Millions of $)

 
| ** **                                          | ** ** | **Years Ended December 31** | ** ** |
|-----------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                          | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| OPERATING  REVENUES:                                |       |                                       |       |   |   |   |   |
| Electric  (Note 13)                                 |       | $                                          | 987.4      |   | $ | 815.7 |   | $ | 768.2 |   |
| Gas                                                 |       | 436.9                                      |       | 357.1 |   | 325.3 |   |
| Total  operating revenues                           |       | 1,424.3                                    |       | 1,172.8 |   | 1,093.5 |   |
|                                                |       |                                       |       |   |   |   |   |
| OPERATING  EXPENSES:                                |       |                                       |       |   |   |   |   |
| Fuel for  electric generation                       |       | 282.4                                      |       | 208.3 |   | 198.0 |   |
| Power  purchased (Notes 10 and 13)                  |       | 140.6                                      |       | 92.1 |   | 79.6 |   |
| Gas supply  expenses                                |       | 339.4                                      |       | 266.0 |   | 233.6 |   |
| Other  operation and maintenance expenses           |       | 307.9                                      |       | 304.8 |   | 290.2 |   |
| Depreciation  and amortization (Note 1)             |       | 124.1                                      |       | 116.6 |   | 113.3 |   |
| Total  operating expenses                           |       | 1,194.4                                    |       | 987.8 |   | 914.7 |   |
|                                                |       |                                       |       |   |   |   |   |
| Net  operating income                               |       | 229.9                                      |       | 185.0 |   | 178.8 |   |
|                                                |       |                                       |       |   |   |   |   |
| Other  (income) expense - net                       |       | (0.7                                       | )          | 3.3 |   | 7.2 |   |
| Interest  expense (Notes 8 and 9)                   |       | 24.1                                       |       | 20.6 |   | 23.9 |   |
| Interest  expense to affiliated companies (Note 13) |       | 12.7                                       |       | 12.2 |   | 6.8 |   |
|                                                |       |                                       |       |   |   |   |   |
| Income  before income taxes                         |       | 193.8                                      |       | 148.9 |   | 140.9 |   |
|                                                |       |                                       |       |   |   |   |   |
| Federal and  state income taxes (Note 7)            |       | 64.9                                       |       | 53.3 |   | 50.1 |   |
|                                                |       |                                       |       |   |   |   |   |
| Net income                                          |       | $                                          | 128.9      |   | $ | 95.6 |   | $ | 90.8 |   |

 

The accompanying notes are an integral part of these financialstatements.

 

Statements of Retained Earnings

(Millions of $)

 
| ** **                                                               | ** ** | **Years Ended December 31** | ** ** |
|--------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                               | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
|                                                                     |       |                                       |       |   |   |   |   |
| Balance January 1                                                   |       | $                                          | 534.0      |   | $ | 497.4 |   | $ | 409.3 |   |
| Add net  income                                                          |       | 128.9                                      |       | 95.6 |   | 90.8 |   |
|                                                                     |       |                                       |       |   |   |   |   |
|                                                                     |       | 662.9                                      |       | 593.0 |   | 500.1 |   |
| Deduct:      Cash dividends declared on  stock: |       |                                       |       |   |   |   |   |
| 5%  cumulative preferred                                                 |       | 1.1                                        |       | 1.1 |   | 1.1 |   |
| Auction rate  cumulative preferred                                       |       | 1.8                                        |       | 0.9 |   | 0.9 |   |
| $5.875  cumulative preferred                                             |       | —                                     |       | — |   | 0.7 |   |
| Common                                                                   |       | 39.0                                       |       | 57.0 |   | — |   |
|                                                                     |       |                                       |       |   |   |   |   |
|                                                                     |       | 41.9                                       |       | 59.0 |   | 2.7 |   |
|                                                                     |       |                                       |       |   |   |   |   |
| Balance December 31                                                 |       | $                                          | 621.0      |   | $ | 534.0 |   | $ | 497.4 |   |

 

The accompanying notes are an integral part of these financialstatements.

 

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Louisville Gas and ElectricCompany

Statements of ComprehensiveIncome

(Millions of $)

 
| ** **                                                                                                                                                                           | ** ** | **Years Ended December 31** | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                                                                                                                           | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| Net income                                                                                                                                                                           |       | $                                          | 128.9      |   | $ | 95.6 |   | $ | 90.8 |   |
|                                                                                                                                                                                 |       |                                       |       |   |   |   |   |
| Gain (loss)  on derivative instruments and hedging activities, net of tax benefit  (expense) of $0, $0.9 and $(0.4) for 2005, 2004 and 2003, respectively (Notes  1 and 4) |       | (0.1                                       | )          | (1.4 | ) | 0.5 |   |
|                                                                                                                                                                                 |       |                                       |       |   |   |   |   |
| Additional  minimum pension liability adjustment, net of tax benefit (expense) of $6.7,  $4.1 and $(1.2) for 2005, 2004 and 2003, respectively (Note 6)                              |       | (12.5                                      | )          | (6.1 | ) | 1.9 |   |
|                                                                                                                                                                                 |       |                                       |       |   |   |   |   |
| Other  comprehensive income (loss), net of tax (Note 14)                                                                                                                             |       | (12.6                                      | )          | (7.5 | ) | 2.4 |   |
|                                                                                                                                                                                 |       |                                       |       |   |   |   |   |
| Comprehensive  income                                                                                                                                                                |       | $                                          | 116.3      |   | $ | 88.1 |   | $ | 93.2 |   |

 

The accompanying notes are an integral part of these financialstatements.

 

71

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Louisville Gas and ElectricCompany

Balance Sheets

(Millions of $)

 
| ** **                                                                                     | ** ** | **December 31** | ** ** |
|------------------------------------------------------------------------------------------------|------------|----------------------|------------|
| ** **                                                                                     | ** ** | **2005**             | ** ** | **2004** | ** ** |
|                                                                                           |       |                 |       |   |   |
| ASSETS:                                                                                        |       |                 |       |   |   |
| Current  assets:                                                                               |       |                 |       |   |   |
| Cash and  cash equivalents (Note 1)                                                            |       | $                    | 7.1        |   | $ | 6.8 |   |
| Accounts  receivable - less reserve of $1.1 million in 2005 and $0.8 million in 2004  (Note 4) |       | 267.5                |       | 167.0 |   |
| Materials  and supplies (Note 1):                                                              |       |                 |       |   |   |
| Fuel  (predominantly coal)                                                                     |       | 38.7                 |       | 21.8 |   |
| Gas stored  underground                                                                        |       | 124.9                |       | 77.5 |   |
| Other  materials and supplies                                                                  |       | 27.7                 |       | 26.1 |   |
| Prepayments  and other current assets                                                          |       | 5.8                  |       | 3.9 |   |
| Total  current assets                                                                          |       | 471.7                |       | 303.1 |   |
|                                                                                           |       |                 |       |   |   |
| Other  property and investments – less reserve of $0.1 million in 2005 and 2004  (Note 1) |       | 0.7                  |       | 0.5 |   |
|                                                                                           |       |                 |       |   |   |
| Utility  plant, at original cost (Note 1):                                                     |       |                 |       |   |   |
| Electric                                                                                       |       | 3,179.9              |       | 3,113.7 |   |
| Gas                                                                                            |       | 511.6                |       | 487.8 |   |
| Common                                                                                         |       | 198.8                |       | 177.5 |   |
| Total  utility plant, at original cost                                                         |       | 3,890.3              |       | 3,779.0 |   |
|                                                                                           |       |                 |       |   |   |
| Less:  reserve for depreciation                                                                |       | 1,508.7              |       | 1,396.3 |   |
| Total  utility plant, net                                                                      |       | 2,381.6              |       | 2,382.7 |   |
|                                                                                           |       |                 |       |   |   |
| Construction  work in progress                                                                 |       | 158.8                |       | 136.8 |   |
| Total  utility plant and construction work in progress                                         |       | 2,540.4              |       | 2,519.5 |   |
|                                                                                           |       |                 |       |   |   |
| Deferred  debits and other assets:                                                             |       |                 |       |   |   |
| Restricted  cash (Note 1)                                                                      |       | 9.8                  |       | 10.9 |   |
| Unamortized  debt expense (Note 1)                                                             |       | 8.6                  |       | 8.4 |   |
| Regulatory  assets (Note 3)                                                                    |       | 84.5                 |       | 91.9 |   |
| Other assets                                                                                   |       | 30.7                 |       | 32.2 |   |
| Total  deferred debits and other assets                                                        |       | 133.6                |       | 143.4 |   |
|                                                                                           |       |                 |       |   |   |
| Total Assets                                                                                   |       | $                    | 3,146.4    |   | $ | 2,966.5 |   |

 

The accompanying notes are an integral part of these financialstatements.

 

72

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Louisville Gas and ElectricCompany

Balance Sheets (continued)

(Millions of $)

 
| ** **                                                                                      | ** ** | **December 31** | ** ** |
|-------------------------------------------------------------------------------------------------|------------|----------------------|------------|
| ** **                                                                                      | ** ** | **2005**             | ** ** | **2004** | ** ** |
|                                                                                            |       |                 |       |   |   |
| LIABILITIES  AND EQUITY:                                                                        |       |                 |       |   |   |
| Current  liabilities:                                                                           |       |                 |       |   |   |
| Current  portion of long-term debt:                                                             |       |                 |       |   |   |
| Long-term  bonds (Note 8)                                                                       |       | $                    | 247.5      |   | $ | 247.4 |   |
| Long-term  notes to affiliated company (Note 8)                                                 |       | —               |       | 50.0 |   |
| Total  current portion of long term debt                                                        |       | 247.5                |       | 297.4 |   |
|                                                                                            |       |                 |       |   |   |
| Notes  payable to affiliated company (Notes 9 and 13)                                           |       | 141.2                |       | 58.2 |   |
| Accounts  payable                                                                               |       | 140.5                |       | 106.1 |   |
| Accounts  payable to affiliated companies (Note 13)                                             |       | 52.4                 |       | 31.7 |   |
| Accrued  income taxes                                                                           |       | 6.2                  |       | 6.2 |   |
| Customer  deposits                                                                              |       | 16.7                 |       | 14.0 |   |
| Other  current liabilities                                                                      |       | 15.2                 |       | 18.6 |   |
| Total  current liabilities                                                                      |       | 619.7                |       | 532.2 |   |
|                                                                                            |       |                 |       |   |   |
| Long-term  debt:                                                                                |       |                 |       |   |   |
| Long-term  bonds (Note 8)                                                                       |       | 328.1                |       | 328.1 |   |
| Long-term  notes to affiliated company (Note 8)                                                 |       | 225.0                |       | 225.0 |   |
| Mandatorily  redeemable preferred stock (Note 8)                                                |       | 20.0                 |       | 21.3 |   |
| Total long  term debt                                                                           |       | 573.1                |       | 574.4 |   |
|                                                                                            |       |                 |       |   |   |
| Deferred  credits and other liabilities:                                                        |       |                 |       |   |   |
| Accumulated  deferred income taxes (Note 7)                                                     |       | 321.7                |       | 347.2 |   |
| Investment tax  credit, in process of amortization                                              |       | 42.1                 |       | 46.2 |   |
| Accumulated  provision for pensions and related benefits (Note 6)                               |       | 143.5                |       | 120.6 |   |
| Asset  retirement obligations                                                                   |       | 26.6                 |       | 10.3 |   |
| Regulatory  liabilities (Note 3):                                                               |       |                 |       |   |   |
| Accumulated  cost of removal of utility plant                                                   |       | 218.9                |       | 220.2 |   |
| Regulatory  liability deferred income taxes                                                     |       | 41.7                 |       | 37.2 |   |
| Other  regulatory liabilities                                                                   |       | 20.2                 |       | 14.9 |   |
| Other  liabilities                                                                              |       | 41.3                 |       | 40.1 |   |
| Total  deferred credits and other liabilities                                                   |       | 856.0                |       | 836.7 |   |
|                                                                                            |       |                 |       |   |   |
| Commitments  and contingencies (Note 10)                                                        |       |                 |       |   |   |
|                                                                                            |       |                 |       |   |   |
| Cumulative  preferred stock                                                                     |       | 70.4                 |       | 70.4 |   |
|                                                                                            |       |                 |       |   |   |
| COMMON  EQUITY:                                                                                 |       |                 |       |   |   |
| Common  stock, without par value - Authorized 75,000,000 shares, outstanding  21,294,223 shares |       | 424.4                |       | 424.4 |   |
| Additional  paid-in capital                                                                     |       | 40.0                 |       | 40.0 |   |
| Accumulated  other comprehensive income (Note 14)                                               |       | (58.2                | )          | (45.6 | ) |
| Retained  earnings                                                                              |       | 621.0                |       | 534.0 |   |
| Total common  equity                                                                            |       | 1,027.2              |       | 952.8 |   |
|                                                                                            |       |                 |       |   |   |
| Total  Liabilities and Equity                                                                   |       | $                    | 3,146.4    |   | $ | 2,966.5 |   |

 

The accompanying notes are an integral part of these financialstatements.

 

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Louisville Gas and ElectricCompany

Statements of Cash Flows

(Millions of $)

 
| ** **                                                  | ** ** | **Years Ended December 31** | ** ** |
|-------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                  | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| CASH FLOWS  FROM OPERATING ACTIVITIES:                      |       |                                       |       |   |   |   |   |
| Net income                                                  |       | $                                          | 128.9      |   | $ | 95.6 |   | $ | 90.8 |   |
| Items not  requiring cash currently:                        |       |                                       |       |   |   |   |   |
| Depreciation  and amortization                              |       | 119.3                                      |       | 116.6 |   | 113.3 |   |
| Deferred  income taxes - net                                |       | (14.3                                      | )          | 5.5 |   | 20.1 |   |
| Investment  tax credit - net                                |       | (4.1                                       | )          | (4.1 | ) | (4.2 | ) |
| VDT  amortization                                           |       | 30.2                                       |       | 30.1 |   | 30.4 |   |
| Unrealized  gain (loss) on derivatives                      |       | —                                     |       | 2.6 |   | (1.1 | ) |
| Other                                                       |       | 7.8                                        |       | (2.0 | ) | 10.8 |   |
| Change in  certain current assets and liabilities:          |       |                                       |       |   |   |   |   |
| Accounts  receivable                                        |       | (100.5                                     | )          | (82.4 | ) | (16.1 | ) |
| Materials  and supplies                                     |       | (65.9                                      | )          | (5.3 | ) | (7.6 | ) |
| Accounts  payable                                           |       | 55.1                                       |       | 6.3 |   | 8.7 |   |
| Accrued  income taxes                                       |       | —                                     |       | (5.3 | ) | 17.2 |   |
| Prepayments  and other                                      |       | (2.5                                       | )          | 6.8 |   | 0.9 |   |
| Pension  funding                                            |       | (9.8                                       | )          | (34.5 | ) | (89.1 | ) |
| Gas supply  clause receivable, net                          |       | (3.2                                       | )          | 10.3 |   | (4.7 | ) |
| Litigation  settlement                                      |       | —                                     |       | 7.0 |   | — |   |
| Earnings  sharing mechanism receivable                      |       | 2.1                                        |       | 10.2 |   | 0.1 |   |
| Other                                                       |       | 7.3                                        |       | 14.2 |   | (6.2 | ) |
| Net cash  provided by operating activities                  |       | 150.4                                      |       | 171.6 |   | 163.3 |   |
|                                                        |       |                                       |       |   |   |   |   |
| CASH FLOWS  FROM INVESTING ACTIVITIES:                      |       |                                       |       |   |   |   |   |
| Construction  expenditures                                  |       | (138.9                                     | )          | (148.3 | ) | (213.0 | ) |
| Change in  restricted cash                                  |       | 1.1                                        |       | (10.9 | ) | — |   |
| Other                                                       |       | (0.2                                       | )          | 0.1 |   | 0.2 |   |
| Net cash  used for investing activities                     |       | (138.0                                     | )          | (159.1 | ) | (212.8 | ) |
|                                                        |       |                                       |       |   |   |   |   |
| CASH FLOWS  FROM FINANCING ACTIVITIES:                      |       |                                       |       |   |   |   |   |
| Long-term  borrowings from affiliated company               |       | —                                     |       | 125.0 |   | 200.0 |   |
| Repayment of  long-term borrowings from affiliated company  |       | (50.0                                      | )          | (50.0 | ) | — |   |
| Short-term  borrowings from affiliated company              |       | 788.6                                      |       | 552.8 |   | 602.7 |   |
| Repayment of  short-term borrowings from affiliated company |       | (705.6                                     | )          | (574.9 | ) | (715.4 | ) |
| Retirement  of first mortgage bonds                         |       | —                                     |       | — |   | (42.6 | ) |
| Issuance of  pollution control bonds                        |       | 40.0                                       |       | — |   | 128.0 |   |
| Issuance  expense on pollution control bonds                |       | (1.9                                       | )          | (0.1 | ) | (5.9 | ) |
| Retirement  of pollution control bonds                      |       | (40.0                                      | )          | — |   | (128.0 | ) |
| Retirement  of mandatorily redeemable preferred stock       |       | (1.3                                       | )          | (1.3 | ) | (1.3 | ) |
| Payment of  dividends                                       |       | (41.9                                      | )          | (58.9 | ) | (3.3 | ) |
| Net cash  (used for) provided by financing activities       |       | (12.1                                      | )          | (7.4 | ) | 34.2 |   |
|                                                        |       |                                       |       |   |   |   |   |
| Change in  cash and cash equivalents                        |       | 0.3                                        |       | 5.1 |   | (15.3 | ) |
|                                                        |       |                                       |       |   |   |   |   |
| Cash and  cash equivalents at beginning of year             |       | 6.8                                        |       | 1.7 |   | 17.0 |   |
|                                                        |       |                                       |       |   |   |   |   |
| Cash and  cash equivalents at end of year                   |       | $                                          | 7.1        |   | $ | 6.8 |   | $ | 1.7 |   |
|                                                        |       |                                       |       |   |   |   |   |
| Supplemental  disclosures of cash flow information:         |       |                                       |       |   |   |   |   |
|                                                        |       |                                       |       |   |   |   |   |
| Cash paid  during the year for:                             |       |                                       |       |   |   |   |   |
| Income taxes                                                |       | $                                          | 83.3       |   | $ | 52.1 |   | $ | 24.9 |   |
| Interest on  borrowed money                                 |       | 20.9                                       |       | 18.1 |   | 23.8 |   |
| Interest to  affiliated companies on borrowed money         |       | 12.7                                       |       | 11.3 |   | 4.2 |   |

 

The accompanying notes are an integral part of these financialstatements.

 

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Louisville Gas and ElectricCompany

Statements of Capitalization

(Millions of $)

 
| ** **                                                                | ** ** | **December 31** | ** ** |
|---------------------------------------------------------------------------|------------|----------------------|------------|
| ** **                                                                | ** ** | **2005**             | ** ** | **2004** | ** ** |
|                                                                      |       |                 |       |   |   |
| LONG-TERM  DEBT (Note 8):                                                 |       |                 |       |   |   |
| Pollution  control series:                                                |       |                 |       |   |   |
| S due September 1,  2017, variable %                                 |       | $                    | 31.0       |   | $ | 31.0 |   |
| T due September 1,  2017, variable %                                 |       | 60.0                 |       | 60.0 |   |
| U due August 15,  2013, variable %                                   |       | 35.2                 |       | 35.2 |   |
| X due April 15,  2023, 5.90%                                         |       | —               |       | 40.0 |   |
| Y due May 1,  2027, variable %                                       |       | 25.0                 |       | 25.0 |   |
| Z due August 1,  2030, variable %                                    |       | 83.3                 |       | 83.3 |   |
| AA due September 1,  2027, variable %                                |       | 10.1                 |       | 10.1 |   |
| BB due September 1,  2026, variable %                                |       | 22.5                 |       | 22.5 |   |
| CC due September 1,  2026, variable %                                |       | 27.5                 |       | 27.5 |   |
| DD due November 1,  2027, variable %                                 |       | 35.0                 |       | 35.0 |   |
| EE due November 1,  2027, variable %                                 |       | 35.0                 |       | 35.0 |   |
| FF due October 1,  2032, variable %                                  |       | 41.7                 |       | 41.7 |   |
| GG due October 1,  2033, variable %                                  |       | 128.0                |       | 128.0 |   |
| HH due February 1,  2035, variable %                                 |       | 40.0                 |       | — |   |
| Notes  payable to Fidelia:                                                |       |                 |       |   |   |
| Due January 6,  2005, 1.53%, secured                                 |       | —               |       | 50.0 |   |
| Due January 16,  2012, 4.33%, secured                                |       | 25.0                 |       | 25.0 |   |
| Due April 30,  2013, 4.55%, unsecured                                |       | 100.0                |       | 100.0 |   |
| Due August 15,  2013, 5.31%, secured                                 |       | 100.0                |       | 100.0 |   |
| Mandatorily  redeemable preferred stock:                                  |       |                 |       |   |   |
| $5.875  series, outstanding shares of 212,500 in 2005 and 225,000 in 2004 |       | 21.3                 |       | 22.5 |   |
|                                                                      |       |                 |       |   |   |
| Total  long-term debt outstanding                                         |       | 820.6                |       | 871.8 |   |
|                                                                      |       |                 |       |   |   |
| Less current  portion of long-term debt                                   |       | 247.5                |       | 297.4 |   |
|                                                                      |       |                 |       |   |   |
| Long-term  debt                                                           |       | 573.1                |       | 574.4 |   |
|                                                                           |            |                      |            |  |  |  |  |

 

CUMULATIVE PREFERRED STOCK:

 
| ** **                                                     | ** ** | **Shares**      | ** ** | **Current**               | ** ** | ** ** | ** ** | ** ** | ** ** |
|----------------------------------------------------------------|------------|-----------------|------------|---------------------------|------------|------------|------------|------------|------------|
| ** **                                                     | ** ** | **Outstanding** | ** ** | **Redemption Price** | ** ** | ** ** | ** ** | ** ** | ** ** |
| $25 par value, 1,720,000 shares authorized  - 5% series        |       | 860,287         |       | $                         | 28.00      |       | 21.5       |       | 21.5       |   |
| Without par  value, 6,750,000 shares authorized - Auction rate |       | 500,000         |       | $                         | 100.00     |       | 50.0       |       | 50.0       |   |
| Preferred  stock expense, net                                  |       |            |       |                      |       | (1.1       | )          | (1.1       | )          |
|                                                           |       |            |       |                      |       |       |       |       |       |
|                                                           |       |            |       |                      |       | 70.4       |       | 70.4       |       |

 

COMMON EQUITY:

 
| Common  stock, without par value - Authorized 75,000,000 shares, outstanding  21,294,223 shares |   | 425.2   |    | 425.2  |   |
|-------------------------------------------------------------------------------------------------|--------|---------|---------|--------|--------|
| Common stock  expense                                                                           |   | (0.8    | )       | (0.8   | )      |
| Additional  paid-in capital                                                                     |   | 40.0    |    | 40.0   |   |
| Accumulated  other comprehensive income (Note 14)                                               |   | (58.2   | )       | (45.6  | )      |
| Retained  earnings                                                                              |   | 621.0   |    | 534.0  |   |
| Total common  equity                                                                            |   | 1,027.2 |    | 952.8  |   |
| Total  capitalization                                                                           |   | $       | 1,670.7 |   | $      | 1,597.6 |   |
|                                                                                                 |        |         |         |        |        |  |  |

 

The accompanying notes are an integral part of these financialstatements.

 

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Louisville Gas and ElectricCompany

Notes to Financial Statements

 

**Note 1 - Summary of Significant AccountingPolicies**

 

LG&E, a subsidiary of E.ON U.S. (formerly LG&E Energy) and anindirect subsidiary of E.ON, is a regulated public utility engaged in thegeneration, transmission, distribution and sale of electric energy and thestorage, distribution and sale of natural gas in Louisville and adjacent areasin Kentucky. E.ON U.S. is a public utility holding company with wholly ownedsubsidiaries including LG&E, KU, Capital Corp., LEM and E.ON U.S. Services.All of LG&E’s common stock is held by E.ON U.S. In May 2004, LG&Edissolved its accounts receivable securitization-related subsidiary, LG&E R.Prior to May 2004, the consolidated financial statements included theaccounts of LG&E and LG&E R with the elimination of intercompanyaccounts and transactions.

 

Effective December 30, 2003, LG&E Energy LLC became thesuccessor, by assignment and subsequent merger, to all assets and liabilitiesof LG&E Energy Corp. Effective December 1, 2005, LG&E Energy LLCwas renamed E.ON U.S. LLC.

 

Certain reclassification entries have been made to the previous years’financial statements to conform to the 2005 presentation with no impact onnet assets, liabilities and capitalization or previously reported net incomeand cash flows.

 

During 2005, LG&E made out-of-period adjustments for estimatedover/under collection of ECR revenues to be billed in subsequent periods. Theadjustments were related to the reporting periods of March 2003 through December 2004.As a result, LG&E revenues for 2005 were increased $5.3 million and netincome for 2005 was increased $3.2 million. LG&E revenues for 2004 and 2003were understated by $2.4 million and $2.9 million, respectively, and net incomewas understated by $1.4 million and $1.8 million, respectively.

 

**Regulatory Accounting.**LG&Eis subject to SFAS No. 71 under which costs that would otherwise becharged to expense are deferred as regulatory assets based on expected recoveryfrom customers in future rates. Likewise, credits that would otherwise bereflected as income are deferred as regulatory liabilities based on expected returnto customers in future rates. LG&E’s current or expected recovery ofdeferred costs and expected return of deferred credits is based on specificratemaking decisions or precedent for each item as prescribed by the FERC orthe Kentucky Commission. See Note 3, Rates and Regulatory Matters, foradditional detail regarding regulatory assets and liabilities.

 

**Cash and Cash Equivalents.**LG&Econsiders all debt instruments purchased with an original maturity of threemonths or less to be cash equivalents.

 

**Allowancefor Doubtful Accounts.** The allowance for doubtful accounts isbased on the ratio of the amounts charged-off during the last twelve months tothe retail revenues billed over the same period multiplied by the retailrevenues billed over the last four months. Accounts with no payment activityare charged-off after four months, although collection efforts continuethereafter.

 

**Materials and Supplies.**Fuel,gas stored underground and other materials and supplies inventories areaccounted for using the average-cost method. Emission allowances are includedin inventory at cost and are not currently traded by LG&E. AtDecember 31, 2005 and 2004, the emission allowances inventory was lessthan $0.1 million.

 

**Other Property and Investments.**Otherproperty and investments on the balance sheet consists of LG&E’s investmentin OVEC and non-utility plant. LG&E and 11 other electric utilities areparticipating owners of OVEC, located in Piketon, Ohio. OVEC owns and operatestwo power plants that burn coal to generate

 

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electricity, Kyger Creek Station in Ohio and Clifty Creek Station inIndiana. Through March 2006, LG&E is entitled to receive 7% of OVEC’soutput, and thereafter is entitled to receive 5.63%, representing approximately124 Mw.

 

As of December 31, 2005 and 2004, LG&E’s investment in OVECtotaled $0.6 and $0.5 million, respectively. LG&E is not the primarybeneficiary of OVEC, and, therefore, it is not consolidated into the financialstatements of LG&E and is accounted for under the cost method ofaccounting. LG&E’s maximum exposure to loss as a result of its involvementwith OVEC is limited to the value of its investment. In the event of theinability of OVEC to fulfill its power provision requirements, LG&E wouldsubstitute such power supply with either owned generation or market purchasesand would generally recover associated incremental costs through regulatoryrate mechanisms. See Note 10, Commitments and Contingencies, for furtherdiscussion of developments regarding LG&E’s ownership interest and power purchaserights.

 

**Utility Plant.**LG&E’sutility plant is stated at original cost, which includes payroll-related costssuch as taxes, fringe benefits, and administrative and general costs. Constructionwork in progress has been included in the rate base for determining retailcustomer rates. LG&E has not recorded any allowance for funds used duringconstruction, in accordance with Kentucky Commission regulations.

 

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 completeoperating units are disposed of, appropriate adjustments are made to the reservefor depreciation and gains and losses, if any, are recognized.

 

**Depreciation and Amortization.**Depreciationis provided on the straight-line method over the estimated service lives ofdepreciable plant. The amounts provided were approximately 3.2% in 2005 (3.0%electric, 2.4% gas, and 8.0% common); 3.1% in 2004 (2.9% electric, 2.8% gas and7.6% common); and 3.3% for 2003 (2.9% electric, 2.8% gas and 9.4% common), ofaverage depreciable plant. Of the amount provided for depreciation, at December 31,2005, approximately 0.4% electric, 0.8% gas and 0.02% common were related tothe retirement, removal and disposal costs of long lived assets.  Of the amount provided for depreciation, at December 31,2004, approximately 0.4% electric, 0.9% gas and 0.04% common were related tothe retirement, removal and disposal costs of long lived assets.

 

**Restricted Cash.**Adeposit in the amount of $9.8 million, used as collateral for an $83.3 millioninterest rate swap expiring in 2020, is classified as restricted cash onLG&E’s balance sheet.

 

**Unamortized Debt Expense.**Debtexpense is capitalized in deferred debits and amortized over the lives of therelated bond issues.

 

**Income Taxes.**Incometaxes are accounted for under SFAS No.109. In accordance with this statement,

 

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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 respectivetax bases, as measured by enacted tax rates that are expected to be in effectin the periods when the deferred tax assets and liabilities are expected to besettled or realized. Significant judgment is required in determiningthe provision for income taxes, and there are transactions for whichthe ultimate tax outcome is uncertain. To provide for these uncertaintiesor exposures, an allowance is maintained for tax contingencies based onmanagement’s best estimate of probable loss. Tax contingencies are analyzedperiodically and adjustments are made when events occur towarrant a change. See Note 7, Income Taxes.

 

**Deferred Income Taxes.**Deferredincome taxes are recognized at currently enacted tax rates for all materialtemporary differences between the financial reporting and income tax bases ofassets and liabilities.

 

**Investment Tax Credits.**Investmenttax credits resulted from provisions of the tax law that permitted a reductionof LG&E’s tax liability based on credits for construction expenditures. Deferredinvestment tax credits are being amortized to income over the estimated livesof the related property that gave rise to the credits.

 

**RevenueRecognition.**Revenues are recorded based on service renderedto 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’s ratio is then multiplied by each day’ssystem net deliveries to determine an estimated billed and unbilled volume foreach day of the accounting period. The unbilled revenue estimates included inaccounts receivable were approximately $81.8 million and $63.0 million at December 31,2005 and 2004, respectively.

 

**Fuel and Gas Costs.**Thecost of fuel for electric generation is charged to expense as used, and thecost of natural gas supply is charged to expense as delivered to thedistribution system. LG&E implemented a Kentucky Commission-approvedperformance-based ratemaking mechanism related to natural gas procurementactivity. See Note 3, Rates and Regulatory Matters.

 

**Management’s Use of Estimates.**Thepreparation of financial statements in conformity with generally acceptedaccounting principles requires management to make estimates and assumptionsthat affect the reported assets and liabilities and disclosure of contingentitems at the date of the financial statements and the reported amounts ofrevenues and expenses during the reporting period. Accrued liabilities,including legal and environmental, are recorded when they are probable and estimable.Actual results could differ from those estimates.

 

**New Accounting Pronouncements.**The following accounting pronouncement was issued that affected LG&E in2005:

 

FIN 47

 

LG&E adopted FIN 47, effective December 31, 2005. FIN 47 expands the term “conditionalasset retirement obligation” as used in SFAS No. 143*,*to refer to a legal obligation to perform an asset retirement activity inwhich the timing and/or method of settlement are conditional on a future eventthat may or may not be within the control of the entity. Theobligation to perform the asset retirement activity is unconditional eventhough uncertainty exists about the timing and/or method of settlement. Anentity is required to recognize a liability for the fair value of a conditionalasset retirement obligation if the fair value of the liability can bereasonably estimated. The fair value of a liability for the conditional assetretirement obligation should be recognized when

 

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incurred; generally, upon acquisition, construction or development andthrough the normal operation of the asset.

 

As a result of the implementation of FIN 47, LG&E recordedadditional ARO net assets and liabilities during the fourth quarter of 2005 inthe amount of $1.0 million and $15.7 million, respectively. LG&E alsorecorded a cumulative effect adjustment in the amount of $12.3 million toreflect the accumulated depreciation and accretion of ARO assets at thetransition date less amounts previously accrued under regulatory depreciation. A$2.4 million reduction in the accumulated cost of removal regulatory liabilitywas also recorded for this previously accrued cost of removal. LG&Erecorded offsetting regulatory assets of $12.3 million, pursuant to regulatorytreatment prescribed under SFAS No. 71 as the costs of removal are allowedunder Kentucky Commission ratemaking.

 

Had FIN 47 been in effect at the beginning of the 2004 reportingperiod, LG&E would have established asset retirement obligations asdescribed in the following table (in millions):

 
| ** **                          | ** ** | **2005** | ** ** | **2004** | ** ** |
|-------------------------------------|------------|----------|------------|----------|------------|
| Provision at  beginning of the year |       | $        | 14.8       |     | $          | 14.0 |   |
| Accretion  expense                  |       | 0.9      |       | 0.8      |       |
| Provision at  end of the year       |       | $        | 15.7       |     | $          | 14.8 |   |

 

**Note 2 – Company Structure**

 

On July 1,2002, E.ON completed its acquisition of Powergen, including E.ON U.S. (formerlyLG&E Energy), for approximately £5.1 billion ($7.3 billion). As a result ofthe acquisition, E.ON U.S. became a wholly owned subsidiary of E.ON and, as aresult, LG&E also became an indirect subsidiary of E.ON. LG&E hascontinued its separate identity and serves customers in Kentucky under itsexisting name. The preferred stock and debt securities of LG&E were notaffected by this transaction and the Company continues to file SEC reports.

 

**Note 3 - Rates and Regulatory Matters**

 

Electric and Gas Rate Cases

 

In December 2003, LG&E filed an application with the KentuckyCommission requesting adjustments in LG&E’s electric and natural gas rates.LG&E asked for general adjustments in electric and natural gas rates basedon the twelve month test period ended September 30, 2003. The revenueincreases requested were $63.8 million for electric and $19.1 million fornatural gas. In June 2004, the Kentucky Commission issued an orderapproving increases in LG&E’s annual electric base rates of approximately$43.4 million (7.7%) and annual natural gas base rates of approximately $11.9million (3.4%). The rate increases took effect on July 1, 2004.

 

During2004 and 2005, the AG conducted an investigation of LG&E, as well as of theKentucky Commission and its staff, requesting information regarding allegedlyimproper communications between LG&E and the Kentucky Commission,particularly during the period covered by the rate cases. Concurrently, the AGhad filed pleadings with the Kentucky Commission requesting rehearing of therate cases on computational components of the increased rates, including incometaxes, cost of removal and depreciation amounts. In August 2004, theKentucky Commission denied the AG’s rehearing request on the cost of removaland depreciation issues and granted rehearing on the income tax component. TheKentucky Commission further agreed to hold in abeyance further proceedings inthe rate case, until the AG filed its investigative report regarding theallegations of improper communication.

 

In January 2005and February 2005, the AG filed a motion summarizing its investigativereport as containing evidence of improper communications and record-keepingerrors by LG&E in its conduct of activities before

 

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the KentuckyCommission or other state governmental entities and forwarded such report tothe Kentucky Commission under continued confidential treatment to allow it toconsider the report, including its impact, if any, on completing itsinvestigation and any remaining steps in the rate case. To date, LG&E hasneither seen nor requested copies of the report or its contents.

 

InDecember 2005, the Kentucky Commission issued an order noting completionif its inquiry, including review of the AG’s investigative report. The orderconcludes no improper communications occurred during the rate proceedings. Theorder further established a procedural schedule through the first quarterof 2006 for considering the sole issue for which rehearing was granted: stateincome tax rates used in calculating the granted rate increases. This issue isestimated at less than $1 million annually. Upon resolution of this issue onrehearing, the initial rate increase order could be subject to judicial appeal.

 

LG&E believes no improprieties have occurred in its communicationswith the Kentucky Commission and has cooperated with the proceedings before theAG and the Kentucky Commission. LG&E is currently unable to determine theultimate impact, if any, of, or any possible future actions of the AG or theKentucky Commission arising out of, the AG’s report and investigation,including whether there will be further actions to appeal, review or otherwisechallenge the granted increases in rates.

 

Regulatory Assets and Liabilities

 

The following regulatory assets and liabilities were included inLG&E’s Balance Sheets as of December 31:

 
| **(in millions)**                        | ** ** | **2005** | ** ** | **2004** | ** ** |
|-----------------------------------------------|------------|----------|------------|----------|------------|
|                                          |       |     |       |     |       |
| VDT Costs                                     |       | $        | 7.5        |     | $          | 37.7 |   |
| Unamortized  loss on bonds                    |       | 20.6     |       | 20.3     |       |
| ARO                                           |       | 20.0     |       | 6.9      |       |
| Gas supply  adjustments                       |       | 25.4     |       | 13.3     |       |
| Merger  surcredit                             |       | 3.5      |       | 4.8      |       |
| Other                                         |       | 7.5      |       | 8.9      |       |
| Total  regulatory assets                      |       | $        | 84.5       |     | $          | 91.9 |   |
|                                          |       |     |       |     |       |
| Accumulated  cost of removal of utility plant |       | $        | 218.9      |     | $          | 220.2 |   |
| Deferred  income taxes - net                  |       | 41.7     |       | 37.2     |       |
| Gas supply  adjustments                       |       | 17.3     |       | 8.4      |       |
| ECR                                           |       | —   |       | 4.0      |       |
| Other                                         |       | 2.9      |       | 2.5      |       |
| Total  regulatory liabilities                 |       | $        | 280.8      |     | $          | 272.3 |   |

 

LG&E currently earns a return on all regulatory assets except forgas supply adjustments, FAC, gas performance based ratemaking and DSM, all ofwhich are separate rate mechanisms with recovery within twelve months.Additionally, no current return is earned on the ARO regulatory asset. Thisregulatory asset will be offset against the associated regulatory liability,ARO asset, and ARO liability at the time the underlying asset is retired. SeeNote 1, Summary of Significant Accounting Policies.

 

**VDT.**During thefirst quarter of 2001, LG&E recorded a $144.0 million charge for aworkforce reduction program. Primary components of the charge were separationbenefits, enhanced early retirement benefits and healthcare benefits. Theresult of this workforce reduction was the elimination of approximately 700positions, accomplished primarily through a voluntary enhanced severanceprogram.

 

In December 2001, the Kentucky Commission issued an orderapproving a settlement agreement allowing LG&E to set up a regulatory assetof $141.0 million for the workforce reduction costs and begin amortizing

 

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these costs over a five-year period starting in April 2001. Someemployees rescinded their participation in the voluntary enhanced severanceprogram, which thereby decreased the charge to the regulatory asset from $144.0million to $141.0 million. The order reduced revenues by approximately $26.0million through a surcredit on bills to ratepayers over the same five-yearperiod. The surcredit represents savings, net of the amortization of the costs,stipulated by LG&E and shared 40% with ratepayers and with LG&Eretaining 60% of the net savings.

 

The five-year VDT amortization period is scheduled to expire in March 2006.As part of the settlement agreements in the electric and natural gas ratecases, LG&E was required to file, and did file on September 30, 2005,with the Kentucky Commission a plan for the future ratemaking treatment of theVDT surcredit and costs. The surcredit will remain in effect until theCommission enters an order on the future disposition of VDT-related issues.

 

On February 27, 2006, the AG, KIUC, LG&E and KU reached asettlement agreement on the future ratemaking treatment of the VDT surcreditsand costs and subsequently submitted a joint motion to the Kentucky Commissionto approve the unanimous settlement agreement. Under the terms of thesettlement agreement, the VDT surcredit will continue at the current leveluntil such time as LG&E files for a change in electric or gas base rates. TheKentucky Commission held a public hearing in the proceeding on March 21,2006 and issued an order thereafter approving the settlement agreement.

 

**Unamortized Loss on Bonds.**The****costs of early extinguishment of debt, including****call premiums, legal****and otherexpenses, and any unamortized balance of debt expense are amortized over thelife of either replacement debt (in the case of re-financing) or the originallife of the extinguished debt.

 

**ARO.**A summary ofLG&E’s net ARO assets, regulatory assets, liabilities and cost of removalestablished under FIN 47 and SFAS No. 143 follows:

 
| ** **                    | ** ** | **ARO Net** | ** ** | **ARO**         | ** ** | **Regulatory** | ** ** | **Regulatory**  | ** ** | **Accumulated**               | ** ** | **Cost of Removal** | ** ** |
|-------------------------------|------------|------------------|------------|-----------------|------------|----------------|------------|-----------------|------------|-------------------------------|------------|-------------------------------|------------|
| **(in millions)**        | ** ** | **Assets**       | ** ** | **Liabilities** | ** ** | **Assets**     | ** ** | **Liabilities** | ** ** | **Cost of Removal** | ** ** | **Depreciation**              | ** ** |
| ** **                    | ** ** | ** **       | ** ** | ** **      | ** ** | ** **     | ** ** | ** **      | ** ** | ** **                    | ** ** | ** **                    | ** ** |
| As of December 31,  2003 |       | $                | 3.5        |            | $          | (9.7           | )          | $               | 6.0        |                          | $          | (0.1                          | )          | $ | 0.5 |   | $ | — |   |
| ARO  accretion                |       | —           |       | (0.7            | )          | 0.7            |       | —          |       | —                        |       | —                        |       |
| ARO  depreciation             |       | (0.2             | )          | —          |       | 0.2            |       | —          |       | —                        |       | —                        |       |
| Removal cost  incurred        |       | —           |       | 0.1             |       | —         |       | —          |       | —                        |       | —                        |       |
| Cost of  removal depreciation |       | —           |       | —          |       | —         |       | —          |       | —                        |       | —                        |       |
| As of December 31,  2004 |       | 3.3              |       | (10.3           | )          | 6.9            |       | (0.1            | )          | 0.5                           |       | —                        |       |
| FIN 47 net  asset additions   |       | 1.0              |       | (15.7           | )          | 12.3           |       | —          |       | 2.4                           |       | —                        |       |
| ARO  accretion                |       | —           |       | (0.7            | )          | 0.7            |       | —          |       | —                        |       | —                        |       |
| ARO  depreciation             |       | (0.1             | )          | —          |       | 0.1            |       | —          |       | —                        |       | —                        |       |
| Removal cost  incurred        |       | —           |       | 0.1             |       | —         |       | —          |       | —                        |       | —                        |       |
| Cost of  removal depreciation |       | —           |       | —          |       | —         |       | (0.1            | )          | —                        |       | 0.1                           |       |
| As of December 31,  2005 |       | $                | 4.2        |            | $          | (26.6          | )          | $               | 20.0       |                          | $          | (0.2                          | )          | $ | 2.9 |   | $ | 0.1 |   |

 

Pursuant to regulatory treatment prescribed under SFAS No. 71, anoffsetting regulatory credit was recorded in Depreciation and amortization in theincome statement of $0.8 million in 2005 and $0.9 million in 2004 for the AROaccretion and depreciation expense. LG&E AROs are primarily related to thefinal retirement of assets associated with generating units and natural gaswells. For assets associated with AROs, the removal cost accrued throughdepreciation under regulatory accounting is established as a regulatory assetor liability pursuant to regulatory treatment prescribed under SFAS No. 71.For the years ended December 31, 2005 and 2004, LG&E recorded lessthan $0.1 million of depreciation expense related to the cost of removal of AROrelated assets. An offsetting regulatory liability was established pursuant toregulatory treatment prescribed under SFAS No. 71.

 

LG&E transmission and distribution lines largely operate underperpetual property easement agreements which

 

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do not generally require restoration upon removal of the property. Therefore,under SFAS No. 143, no material asset retirement obligations are recordedfor transmission and distribution assets.

 

**Merger Surcredit.**Aspart of the LG&E Energy merger with KU Energy in 1998, LG&Eestimated non-fuel savings over a ten-year period following the merger. Coststo achieve these savings were deferred and amortized over a five-year periodpursuant to regulatory orders. In approving the merger, the Kentucky Commissionadopted LG&E’s proposal to reduce its retail customers’ bills based onone-half of the estimated merger-related savings, net of deferred and amortizedamounts, over a five-year period. The surcredit mechanism provides that 50% ofthe net non-fuel cost savings estimated to be achieved from the merger beprovided to ratepayers through a monthly bill credit, and 50% be retained byLG&E and KU, over a five-year period. The surcredit was allocated 53% to KUand 47% to LG&E. In that same order, the Commission required LG&E andKU, after the end of the five-year period, to present a plan for sharing withratepayers the then-projected non-fuel savings associated with the merger. TheCompanies submitted this filing in January 2003, proposing to continue toshare with ratepayers, on a 50%/50% basis, the estimated fifth-year gross levelof non-fuel savings associated with the merger. In October 2003, theKentucky Commission issued an order approving a settlement agreement reachedwith the parties in the case. LG&E’s merger surcredit will remain in placefor another five-year term beginning July 1, 2003 and the merger savingswill continue to be shared 50% with ratepayers and 50% with shareholders.

 

**ESM.**Prior to 2004,LG&E’s retail electric rates were subject to an ESM. The ESM, initially inplace for three years beginning in 2000, set an upper (12.5%) and lower (10.5%)limit for rate of return on equity. 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 ESM filing went into effect in April of eachyear subject 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 focusedmanagement audit to review the ESM plan and reassess its reasonableness. LG&Efiled its 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.In June 2004, the Kentucky Commission issued an order largely accepting proposedsettlement agreements by LG&E and all intervenors regarding the ESM. Underthe ESM settlements, LG&E continued to collect approximately $13.0 millionof previously requested 2003 ESM revenue amounts through March 2005. As part ofthe settlement, the parties agreed to a termination of the ESM mechanismrelating to all periods after 2003.

 

**FAC.**LG&E’sretail electric rates contain an FAC, whereby increases and decreases in thecost of fuel for electric generation are reflected in the rates charged toretail electric customers. In January 2003, the Kentucky Commissionreviewed KU’s FAC and, as part of the order in that case, required that anindependent audit be conducted to examine operational and management aspects ofboth LG&E’s and KU’s fuel procurement functions. The final report wasissued in February 2004. The report’s recommendations related to documentationand process improvements. Management Audit Action Plans were agreed upon byLG&E and the Kentucky Commission Staff in the second quarter of 2004. LG&Efiled its first Audit Progress Report with the Kentucky Commission Staff in November 2004.A second Audit Progress Report was filed May 2005. The third AuditProgress Report was filed in December 2005. In January 2006, theKentucky Commission staff informed LG&E and KU that reporting on all of theoriginal recommendations, but one, has been concluded. LG&E and KU are tofile another Audit Progress Report on the remaining open recommendation on August 15,2006.

 

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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. No significant issues have beenidentified as a result of these reviews.

 

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 matter was held on March 17, 2005. An orderby the Kentucky Commission was issued in May 2005 approving LG&E’sbase fuel component of 13.49 mills/kwh as filed. Revised tariff schedules forLG&E were filed to reflect the change in the base fuel component.

 

On July 7, 2005, the Kentucky Commissioninitiated the six-month review of the LG&E fuel adjustment clause for theperiod of November 2004 through April 2005. During November 2005,the Kentucky Commission approved the charges and credits billed and the fuelprocurement practices of LG&E.

 

On December 27, 2005, the KentuckyCommission initiated the six-month review of the LG&E fueladjustment clause for the period of May 2005 through October 2005. Initialdiscovery was completed on January 17, 2006, and a hearing was held on March 16,2006. LG&E anticipates KentuckyCommission approval of the charges and credits billed and the fuelprocurement practices of LG&E during the second quarter of 2006.

 

**DSM.**LG&E’srates contain a DSM provision. The provision includes a rate mechanism that providesfor concurrent recovery of DSM costs and provides an incentive for implementingDSM programs. The provision allows LG&E to recover revenues from lost salesassociated with the DSM programs based on program plan engineering estimatesand post-implementation evaluations.

 

**Gas Supply Adjustments.  **Since November 1,1997, LG&E has operated under an experimental PBR mechanism related to itsnatural gas procurement activities. LG&E’s rates are adjusted annually torecover (or refund) its portion of the savings (or expenses) incurred duringeach PBR year (12 months ending October 31). During the PBR year ending in2005, LG&E achieved $10.8 million in savings. Of that total savings amount,LG&E’s portion was $2.7 million and the ratepayers’ portion was $8.1million. Pursuant to the extension of LG&E’s natural gas supply cost PBRmechanism effective November 1, 2001, the sharing mechanism under the PBRrequires savings (and expenses) to be shared 25% with shareholders and 75% withratepayers up to 4.5% of the benchmarked natural gas costs. Savings (andexpenses) in excess of 4.5% of the benchmarked natural gas costs are shared 50%with shareholders and 50% with ratepayers. LG&E filed a report andassessment with the Kentucky Commission in December 2004, seekingmodification and extension of the mechanism. Following a review by the KentuckyCommission, the current natural gas supply cost PBR mechanism was extendedthrough 2010 without further modification.

 

**Accumulated Cost of Removal of Utility Plant.**As of December 31, 2005 and 2004, LG&E hassegregated the cost of removal, embedded in accumulated depreciation, of $218.9million and $220.2 million, respectively, in accordance with FERC Order No. 631.For reporting purposes in the balance sheets, LG&E has presented this costof removal as a regulatory liability pursuant to SFAS No. 71.

 

**Deferred Income Taxes – Net.**Deferredincome taxes represent the future income tax effects of recognizing theregulatory assets and liabilities in the income statement. Deferred incometaxes are recognized at currently enacted tax rates for all material temporarydifferences between the financial reporting and income tax bases of assets andliabilities.

 

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**ECR**. LG&E’sretail rates contain an ECR surcharge which recovers costs incurred by LG&Ethat are required to comply with the Clean Air Act and other environmentalregulations.  In January 2003, theKentucky Commission initiated a six-month review of LG&E’s environmentalsurcharge. A final order was issued in April 2003, in which LG&E wasordered to refund $2.9 million it had previously over-collected from customers.In July 2003, the Kentucky Commission initiated a two-year review ofLG&E’s environmental surcharge. 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 now includedin base rates going forward. Additionally, LG&E was ordered to collect $0.2million to correct for amounts under-collected from customers. The rates ofreturn for LG&E’s 1995 and post-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 costs associatedwith new and additional environmental compliance facilities, including theexpansion of the landfill facility at the Mill Creek station. The estimatedcapital cost of the additional facilities for the next three years isapproximately $40.0 million. LG&E requested an overall rate of return of10.72%, including an 11% return on common equity. Hearings in these cases occurred during May 2005 and final orderswere issued in June 2005, granting approval of the amendments to LG&E’scompliance plans.

 

Other Regulatory Matters

 

**MISO.**The MISO is anon-profit independent transmission system operator that controls approximately97,000 miles of transmission lines over 947,000 square miles in 15 northernMidwest states and one Canadian province. The MISO operates the regional powergrid and wholesale electricity market in an effort to optimize efficiency andsafeguard reliability in accordance with federal energy policy.

 

LG&E is now involved in proceedings with the Kentucky Commissionand the FERC seeking the authority to exit the MISO. A timeline of eventsregarding the MISO and various proceedings is as follows:

 

•                  September 1998– The FERC granted conditional approval for the formation of the MISO. LG&Ewas a founding member.

 

•                  October 2001– The FERC ordered that all bundled retail loads and grandfathered wholesaleloads of each member transmission owner be included in the calculation of theMISO “cost adder,” the Schedule 10 charges designed to recover the MISO’scost of operation, including start-up capital (debt) costs. LG&E andseveral owners opposed the FERC order and filed suit with the United StatesCourt of Appeals.

 

•                  February 2002– The MISO began commercial operations.

 

•                  February 2003– The FERC reaffirmed its position on the Schedule 10 charges and theorder was subsequently upheld by the U.S. Court of Appeals.

 

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•                  July 2003– The Kentucky Commission opened an investigation into LG&E’s MISOmembership. Testimony was filed by LG&E that supported an exit from theMISO, under certain conditions. This proceeding remains open.

 

•                  August 2004– The MISO filed its FERC-required TEMT. LG&E and other owners filedopposition to certain conditions of the TEMT and sought to delay theimplementation. Such opposition was denied by the FERC.

 

•                  December 2004– LG&E provided the MISO its required one-year notice of intent to exit thegrid.

 

•                  April 2005– The MISO implemented its day-ahead and real-time market (MISO Day 2),including a congestion management system.

 

•                  October 2005– LG&E filed documents with the FERC seeking authority to exit the MISO.This proceeding remains open.

 

•                  November 2005– LG&E requested a Kentucky Commission order authorizing the transfer offunctional control of its transmission facilities from the MISO to LG&E,for the purpose of exiting the MISO. The request stated that the TVA would havecontrol to the extent necessary to act as LG&E’s Reliability Coordinatorand for the SPP to perform its function as LG&E’s IndependentTransmission Organization. This proceeding remains open.

 

Based on various financial analyses performed internally, in responseto the July 2003 Kentucky Commission investigation into MISO membership,and particularly in light of the financial impacts following MISO’simplementation of the new day-ahead and real-time markets, LG&E determinedthat the costs of MISO membership, both now and in the future, outweigh thebenefits.

 

Should LG&E be allowed to exit the MISO, an aggregate exit fee ofup to $41.0 million (approximately $16.0 million for LG&E and approximately$25.0 million for KU) could be imposed, depending on the timing andcircumstances of the actual exit. LG&E estimates that, over time, such feecould be more than offset by savings resulting from exit from the MISO.Conversely, should LG&E be ordered to remain in the MISO, costs areexpected to continue to exceed benefits, currently without mechanisms for immediaterecovery.

 

On March 17, 2006, the FERC issued an order conditionally approving therequest of LG&E and KU to exit the MISO. For further discussion, see Note16, Subsequent Events.

 

**Market-Based Rate Authority.**SinceApril 2004, the FERC has initiated proceedings to modify its methods whichassess generation market power and has established more stringent interimmarket screen tests. During 2005, in connection with LG&E’s and KU’stri-annual market-based rate tariff renewals, although disputed by LG&E andKU, the FERC continued to contend that LG&E and KU failed such marketscreens in certain regions. In January 2006, in order to resolve thematter, LG&E and KU submitted proposed tariff schedules to the FERCcontaining a mitigation mechanism with respect to applicable power sales intoan adjacent western Kentucky control area where a non-utility affiliate companyis active. Prices for such sales will be capped at a relevant MISO power poolindex price. Should LG&E and KU exit the MISO, they could additionally bedeemed to have market power in their own joint control area, potentiallyrequiring a similar mitigation mechanism for power sales into such region. LG&Eand KU cannot predict the ultimate impact of the current or potentialmitigation mechanisms on their future wholesale power revenues.

 

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**IRP.**In April 2005, LG&E and KU filed their2005 Joint IRP with the Kentucky Commission. The IRP provides historical andprojected demand, resource and financial data, and other operating performanceand system information. The AG and the KIUC were granted intervention in theIRP proceeding. The Kentucky Commission issued its staff report on February 15,2006, with no substantive issues noted and closed the case by Order dated February 24,2006.

 

**Kentucky CommissionAdministrative Case for System Adequacy.**In June 2001, Kentucky’s Governorissued Executive Order 2001-771, which directed the Kentucky Commission toreview and study issues relating to the need for and development of newelectric generating capacity in Kentucky. In response to that Executive Order,in July 2001 the Kentucky Commission opened Administrative Case No. 387to review the adequacy of Kentucky’s generation capacity and transmissionsystem. Specifically, the items reviewed were the appropriate level of relianceon purchased power, the appropriate reserve margins to meet existing and futureelectric demand, the impact of spikes in natural gas prices on electric utilityplanning strategies, and the adequacy of Kentucky’s electric transmissionfacilities. In December 2001, the Kentucky Commission issued an order inwhich it noted that LG&E is responsibly addressing the long-term supplyneeds of native load customers and that current reserve margins are appropriate.However, due to the rapid pace of change in the industry, the order also requiresLG&E to provide an annual assessment of supply resources, future demand,reserve margin and the need for new resources.

 

Regarding the transmission system, the Kentucky Commission 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 the 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.

 

**EPAct 2005.**TheEPAct 2005 was enacted on August 8, 2005. Among other matters, this comprehensivelegislation contains provisions mandating improved electric reliabilitystandards and performance; providing economic and other incentives relating totransmission, pollution control and renewable generation assets; increasingfunding for clean coal generation incentives; repealing PUHCA 1935; enactingPUHCA 2005 and expanding FERC jurisdiction over public utility holdingcompanies and related matters via the FPA and PUHCA 2005.

 

The FERC wasdirected by the EPAct 2005 to adopt rules to address many areas previouslyregulated by the other agencies under other statutes, including PUHCA 1935. TheFERC is in various stages of rulemaking on these issues and LG&E ismonitoring these rulemaking activities and actively participating in these andother rulemaking proceedings. LG&E is still evaluating the potentialimpacts of the EPAct 2005 and the associated rulemakings and cannot predictwhat impact the EPAct 2005, and any such rulemakings, will have on itsoperations or financial position.

 

**KentuckyCommission 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 is 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 Commissionestablished Administrative Case No. 2005-00090 to collect information fromall

 

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jurisdictionalutilities in Kentucky, including LG&E, pertaining to Kentucky electricgeneration, transmission and distribution systems. LG&E responded to theKentucky Commission’s first set of data requests at the end of March 2005and to a second set of data requests in May 2005. The Commission held aTechnical Conference on June 14, 2005, in which all parties participatedin a panel discussion. A final report was provided on August 22, 2005 fromthe Kentucky Commission to the Governor. The Kentucky Commission issued anorder and closed this proceeding on September 15, 2005. Some of the keyfindings from the report are:

 

•                  Kentucky’selectric utilities currently have adequate infrastructure as well as adequateplanning to serve the needs of customers through 2025;

 

•                  Kentucky willneed 7,000 megawatts of additional generating capacity by 2025;

 

•                  Kentucky’selectric transmission is reliable but intrastate power transfers are limited;

 

•                  Additionalincentives to use renewable energy and educate the public on the benefits ofrenewables are needed;

 

•                  Financialincentives should be available for coal purification and other clean airtechnologies;

 

•                  A cautiousapproach should be taken toward deregulation; and

 

•                  Kentucky must beinvolved in federal decisions that impact its status as a low cost energyprovider.

 

**Note 4 - Financial Instruments**

 

The cost and estimated fair values of LG&E’s non-trading financialinstruments as of December 31, 2005, and 2004 follow:

 
| ** **                                       | ** ** | **2005**     | ** ** | **2004**  | ** ** |
|--------------------------------------------------|------------|--------------|------------|-----------|------------|
| ** **                                       | ** ** | **Carrying** | ** ** | **Fair**  | ** ** | **Carrying** | ** ** | **Fair** | ** ** |
| **(in millions)**                           | ** ** | **Value**    | ** ** | **Value** | ** ** | **Value** | ** ** | **Value** | ** ** |
| Preferred  stock subject to mandatory redemption |       | $            | 21.3       |      | $          | 21.4 |   | $ | 22.5 |   | $ | 22.8 |   |
| Long-term  debt (including current portion)      |       | $            | 574.3      |      | $          | 574.3 |   | $ | 574.3 |   | $ | 575.4 |   |
| Long-term  debt from affiliate                   |       | $            | 225.0      |      | $          | 224.8 |   | $ | 275.0 |   | $ | 280.7 |   |
| Interest-rate  swaps - liability                 |       | $            | (18.6      | )         | $          | (18.6 | ) | $ | (18.5 | ) | $ | (18.5 | ) |

 

All of the above valuations reflect prices quoted by exchanges exceptfor the swaps and intercompany loans. The fair values of the swaps and intercompanyloans reflect price quotes from dealers or amounts calculated using acceptedpricing models. The fair values of cash and cash equivalents, accountsreceivable, accounts payable and notes payable are substantially the same astheir carrying values.

 

**Interest Rate Swaps.** LG&E uses over-the-counter interestrate swaps to hedge exposure to market fluctuations in certain of its debtinstruments. Pursuant to Company policy, use of these financial instruments isintended to mitigate risk, earnings and cash flow volatility and is notspeculative in nature. Management has designated all of the interest rate swapsas hedge instruments. Financial instruments designated as cash flow hedges haveresulting gains and losses recorded within other comprehensive income andstockholders’ equity. See Note 14, Accumulated Other Comprehensive Income. Financialinstruments designated as fair value hedges and the underlying hedged items areperiodically marked to market with the resulting net gains and losses recordeddirectly into net income.  Upontermination of any fair value hedge, the resulting gain or loss is recordedinto net income.

 

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LG&E was party to various interest rate swap agreements with aggregatenotional amounts of $211.3 million and $228.3 million as of December 31,2005 and 2004. Under these swap agreements, LG&E paid fixed rates averaging4.38% and received variable rates based on LIBOR or the Bond Market Association’smunicipal swap index averaging 3.15% and 1.74% at December 31, 2005 and2004, respectively. The swap agreements in effect at December 31, 2005have been designated as cash flow hedges and mature on dates ranging from 2020to 2033. The cash flow designation was assigned because the underlying variablerate debt has variable future cash flows. The hedges have been deemed to befully effective resulting in a pretax loss of $0.1 million for 2005 and $2.3million in 2004, recorded in other comprehensive income. Upon expiration ofthese hedges, the amount recorded in other comprehensive income will bereclassified into earnings. The amount expected to be reclassified from othercomprehensive income to earnings in the next twelve months is less than $0.1million. A deposit in the amount of $9.8 million, used as collateral for one ofthe interest rate swaps, is classified as restricted cash on LG&E’s BalanceSheet. The amount of the deposit required is tied to the market value of theswap.

 

# **Energy Risk ManagementActivities.**LG&Econducts energy trading and risk management activities to maximize the value ofpower sales from physical assets it owns. Certain energy trading activities areaccounted for on a mark-to-market basis in accordance with SFAS No. 133,as amended. Wholesale sales of excess asset capacity are treated as normalsales under SFAS No. 133, as amended and are not marked to market.

# ** **

No changes to valuationtechniques for energy trading and risk management activities occurred during2005 and 2004. Changes in market pricing, interest rate and volatilityassumptions were made during both years. All contracts outstanding at December 31,2005, 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 31,2005, 100% of the trading and risk management commitments were withcounterparties rated BBB-/Baa3 equivalent or better.

 

LG&E hedges the price volatility of its forecasted electricoff-system sales with the sales of market-traded electric forward contracts forperiods of less than one year. These electric forward sales have beendesignated as cash flow hedges and are not speculative in nature. Gains orlosses on these instruments, to the extent that the hedging relationship hasbeen effective, are deferred in other comprehensive income. Gains and lossesresulting from ineffectiveness are shown in LG&E’s Statements of Income inother (income) expense – net. Upon completion of the underlying hedgetransaction, the amount recorded in other comprehensive income is recorded inearnings. No material pre-tax gains and losses resulted from these cash flowhedges in 2005, 2004 and 2003.  See Note14, Accumulated Other Comprehensive Income.

 

**Accounts Receivable Securitization.**LG&Eterminated its accounts receivable securitization program in January 2004,and in May 2004, LG&E dissolved its inactive accounts receivablesecuritization-related subsidiary, LG&E R. No material pre-tax gains andlosses resulted from the sale of the receivables in 2004 and 2003. LG&E’snet cash flows from LG&E R were reduced by $58.1 million and $6.2 millionfor 2004 and 2003, respectively. The allowance for doubtful accounts associatedwith the eligible securitized receivables at December 31, 2003, was $1.4million. This allowance was based on historical experience of LG&E. Eachsecuritization facility contained a fully funded reserve for uncollectible receivables.LG&E was able to terminate this program at any time without penalty.

 

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**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. Concentrationsof credit risk (whether on- or off-balance sheet) relate to groups of customersor counterparties that have similar economic or industry characteristics thatwould cause their ability to meet contractual obligations to be similarlyaffected by changes in economic or other conditions.

 

LG&E’s customer receivables and gas and electric revenues arisefrom deliveries of natural gas to approximately 321,000 customers and electricityto approximately 394,000 customers in Louisville and adjacent areas in Kentucky.For the year ended December 31, 2005, 69% of total revenue was derivedfrom electric operations and 31% from natural gas operations. For the yearended December 31, 2004, 70% of total revenue was derived from electricoperations and 30% from natural gas operations.

 

In November 2005, LG&E and IBEW Local 2100 employees, thatrepresent approximately 69% of LG&E’s workforce, entered into a three-yearcollective bargaining agreement with annual benefits re-openers.

 

**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 coversubstantially all of its employees. The healthcare plans are contributory withparticipants’ contributions adjusted annually. LG&E uses December 31as the measurement date for its plans.

 

**Obligations and Funded Status.**Thefollowing tables provide a reconciliation of the changes in the plan’s benefitobligations and fair value of assets over the three-year period ending December 31,2005, and a statement of the funded status as of December 31, 2005, 2004and 2003 for LG&E’s sponsored defined benefit plan:

 
| **(in millions)**                             | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|----------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Pension  Plans:                                    |       |     |       |     |       |     |       |
| Change in  projected benefit obligation            |       |     |       |     |       |     |       |
| Projected  benefit obligation at beginning of year |       | $        | 402.4      |     | $          | 378.7    |       | $ | 364.8 |   |
| Service cost                                       |       | 3.7      |       | 2.8      |       | 1.7      |       |
| Interest  cost                                     |       | 22.3     |       | 22.7     |       | 23.2     |       |
| Plan amendments                                    |       | 3.2      |       | 3.3      |       | 4.0      |       |
| Change due  to transfers                           |       | 0.3      |       | (1.1     | )          | (2.8     | )          |
| Benefits  paid                                     |       | (29.9    | )          | (30.5    | )          | (33.5    | )          |
| Actuarial  (gain) or loss and other                |       | 24.7     |       | 26.5     |       | 21.3     |       |
| Projected  benefit obligation at end of year       |       | $        | 426.7      |     | $          | 402.4    |       | $ | 378.7 |   |
|                                               |       |     |       |     |       |     |       |
| Change in  plan assets                             |       |     |       |     |       |     |       |
| Fair value  of plan assets at beginning of year    |       | $        | 338.2      |     | $          | 297.8    |       | $ | 196.3 |   |
| Actual  return on plan assets                      |       | 26.6     |       | 39.3     |       | 47.2     |       |
| Employer  contributions                            |       | —   |       | 34.5     |       | 89.1     |       |
| Change due  to transfers                           |       | —   |       | (1.1     | )          | 0.2      |       |
| Benefits paid                                      |       | (29.9    | )          | (30.5    | )          | (33.5    | )          |
| Administrative  expenses                           |       | (1.8     | )          | (1.8     | )          | (1.5     | )          |
| Fair value  of plan assets at end of year          |       | $        | 333.1      |     | $          | 338.2    |       | $ | 297.8 |   |
|                                               |       |     |       |     |       |     |       |
| Reconciliation  of funded status                   |       |     |       |     |       |     |       |
| Funded  status                                     |       | $        | (93.6      | )        | $          | (64.2    | )          | $ | (80.9 | ) |
| Unrecognized  actuarial (gain) or loss             |       | 94.7     |       | 70.3     |       | 56.2     |       |
| Unrecognized  transition (asset) or obligation     |       | (0.7     | )          | (1.5     | )          | (2.2     | )          |
| Unrecognized  prior service cost                   |       | 30.4     |       | 31.5     |       | 32.3     |       |
| Net amount  recognized at end of year              |       | $        | 30.8       |     | $          | 36.1     |       | $ | 5.4 |   |

 

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| Other  Benefits:                                |   |   |   |   |   |   |   |
|-------------------------------------------------|--------|--------|--------|--------|--------|--------|--------|
| Change in  benefit obligation                   |   |   |   |   |   |   |   |
| Benefit  obligation at beginning of year        |   | $      | 113.0  |   | $      | 108.0  |   | $ | 93.2 |   |
| Service cost                                    |   | 1.0    |   | 0.9    |   | 0.6    |   |
| Interest  cost                                  |   | 5.6    |   | 6.5    |   | 6.9    |   |
| Plan amendments                                 |   | 2.2    |   | 0.4    |   | 7.4    |   |
| Benefits  paid                                  |   | (8.1   | )      | (7.1   | )      | (9.3   | )      |
| Actuarial  (gain) or loss                       |   | (7.5   | )      | 4.3    |   | 9.2    |   |
| Benefit  obligation at end of year              |   | $      | 106.2  |   | $      | 113.0  |   | $ | 108.0 |   |
|                                            |   |   |   |   |   |   |   |
| Change in  plan assets                          |   |   |   |   |   |   |   |
| Fair value  of plan assets at beginning of year |   | $      | 0.8    |   | $      | 0.7    |   | $ | 1.5 |   |
| Actual  return on plan assets                   |   | 0.2    |   | (2.0   | )      | 2.1    |   |
| Employer  contributions                         |   | 9.8    |   | 9.3    |   | 6.4    |   |
| Change due  to transfers                        |   | — |   | (0.1   | )      | — |   |
| Benefits  paid                                  |   | (8.1   | )      | (7.1   | )      | (9.3   | )      |
| Fair value  of plan assets at end of year       |   | $      | 2.7    |   | $      | 0.8    |   | $ | 0.7 |   |
|                                            |   |   |   |   |   |   |   |
| Reconciliation  of funded status                |   |   |   |   |   |   |   |
| Funded  status                                  |   | $      | (103.5 | )      | $      | (112.2 | )      | $ | (107.3 | ) |
| Unrecognized  actuarial (gain) or loss          |   | 21.5   |   | 29.4   |   | 23.7   |   |
| Unrecognized  transition (asset) or obligation  |   | 4.7    |   | 5.4    |   | 6.0    |   |
| Unrecognized  prior service cost                |   | 10.4   |   | 10.0   |   | 11.5   |   |
| Net amount  recognized at end of year           |   | $      | (66.9  | )      | $      | (67.4  | )      | $ | (66.1 | ) |

 

**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, 2005, 2004 and2003:

 
| **(in millions)**                                                                                     | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|------------------------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Pension  Plans:                                                                                            |       |     |       |     |       |     |       |
| Amounts  recognized in the balance sheet consisted of:                                                     |       |     |       |     |       |     |       |
| Accrued  benefit liability                                                                                 |       | $        | (76.6      | )        | $          | (53.2    | )          | $ | (74.5 | ) |
| Intangible  asset                                                                                          |       | 30.4     |       | 31.5     |       | 32.3     |       |
| Accumulated  other comprehensive income                                                                    |       | 77.0     |       | 57.8     |       | 47.6     |       |
| Net amount  recognized at year-end                                                                         |       | $        | 30.8       |     | $          | 36.1     |       | $ | 5.4 |   |
|                                                                                                       |       |     |       |     |       |     |       |   |   |   |
| Increase  (decrease) in minimum liability included in other comprehensive income                           |       | $        | 19.2       |     | $          | 10.2     |       | $ | (3.1 | ) |
|                                                                                                       |       |     |       |     |       |     |       |
| Additional  year-end information for plans with accumulated benefit obligations in excess  of plan assets: |       |     |       |     |       |     |       |
| Projected  benefit obligation                                                                              |       | $        | 426.7      |     | $          | 402.4    |       | $ | 378.7 |   |
| Accumulated  benefit obligation                                                                            |       | 409.7    |       | 391.4    |       | 372.3    |       |
| Fair value  of plan assets                                                                                 |       | 333.1    |       | 338.2    |       | 297.8    |       |
|                                                                                                       |       |     |       |     |       |     |       |
| Other  Benefits:                                                                                           |       |     |       |     |       |     |       |
| Amounts  recognized in the balance sheet consisted of:                                                     |       |     |       |     |       |     |       |
| Accrued  benefit liability                                                                                 |       | $        | (66.9      | )        | $          | (67.4    | )          | $ | (66.1 | ) |
|                                                                                                       |       |     |       |     |       |     |       |
| Additional  year-end information for plans with benefit obligations in excess of plan  assets:             |       |     |       |     |       |     |       |
| Benefit  obligation                                                                                        |       | $        | 106.2      |     | $          | 113.0    |       | $ | 108.0 |   |
| Fair value  of plan assets                                                                                 |       | 2.7      |       | 0.8      |       | 0.7      |       |

 

**Components of Net Periodic Benefit Cost.**Thefollowing table provides the components of net periodic

 

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benefit cost for the plans for 2005, 2004 and 2003:

 
| **(in millions)**                            | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|---------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Pension  Plans:                                   |       |     |       |     |       |     |       |
| Components  of net periodic benefit cost          |       |     |       |     |       |     |       |
| Service cost                                      |       | $        | 3.7        |     | $          | 2.8      |       | $ | 1.8 |   |
| Interest  cost                                    |       | 22.3     |       | 22.7     |       | 23.2     |       |
| Expected  return on plan assets                   |       | (26.5    | )          | (27.0    | )          | (22.8    | )          |
| Amortization  of prior service cost               |       | 4.3      |       | 4.1      |       | 3.8      |       |
| Amortization  of transition (asset) or obligation |       | (0.7     | )          | (0.7     | )          | (1.0     | )          |
| Amortization  of actuarial (gain) or loss         |       | 2.3      |       | 1.9      |       | 2.2      |       |
| Net periodic  benefit cost                        |       | $        | 5.4        |     | $          | 3.8      |       | $ | 7.2 |   |
|                                              |       |     |       |     |       |     |       |
| Other  Benefits:                                  |       |     |       |     |       |     |       |
| Components  of net periodic benefit cost          |       |     |       |     |       |     |       |
| Service cost                                      |       | $        | 1.0        |     | $          | 0.9      |       | $ | 0.6 |   |
| Interest  cost                                    |       | 5.6      |       | 6.5      |       | 6.9      |       |
| Expected  return on plan assets                   |       | —   |       | —   |       | (0.1     | )          |
| Amortization  of prior service cost               |       | 1.8      |       | 1.8      |       | 1.8      |       |
| Amortization  of transition (asset) or obligation |       | 0.7      |       | 0.7      |       | 0.7      |       |
| Amortization  of actuarial (gain) or loss         |       | 0.3      |       | 0.7      |       | 0.5      |       |
| Net periodic  benefit cost                        |       | $        | 9.4        |     | $          | 10.6     |       | $ | 10.4 |   |

 

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

 
| ** **                                            | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|-------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
|                                                  |       |     |       |     |       |     |       |
| Weighted-average  assumptions as of December 31: |       |     |       |     |       |     |       |
| Discount  rate                                        |       | 5.50     | %          | 5.75     | %          | 6.25     | %          |
| Rate of  compensation increase                        |       | 5.25     | %          | 4.50     | %          | 3.00     | %          |

 

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

 
| ** **                                | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|-------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
|                                      |       |     |       |     |       |     |       |
| Discount rate                             |       | 5.75     | %          | 6.25     | %          | 6.75     | %          |
| Expected  long-term return on plan assets |       | 8.25     | %          | 8.50     | %          | 9.00     | %          |
| Rate of  compensation increase            |       | 4.50     | %          | 3.50     | %          | 3.75     | %          |

 

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. Theexpected return for each asset class was then weighted based on the targetasset allocation to develop the expected long-term rate of return on assetsassumption for the portfolio.

 

**Assumed Healthcare Cost Trend Rates.**Formeasurement purposes, an 11.0% annual increase in the per capita cost ofcovered healthcare benefits was assumed for 2005. The rate was assumed todecrease gradually to 5.0% by 2015 and remain at that 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:

 

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| **(in millions)**                                            | ** ** | **1% Decrease** | ** ** | **1% Increase** | ** ** |
|-------------------------------------------------------------------|------------|----------------------|------------|----------------------|------------|
| Effect on  total of service and interest cost components for 2005 |       | $                    | (0.2       | )                    | $          | 0.3 |   |
| Effect on  year-end 2005 postretirement benefit obligations       |       | $                    | (2.8       | )                    | $          | 3.1 |   |

 

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

 
| ** **             | ** ** | **Pension** | ** ** | **Other**    | ** ** |
|------------------------|------------|-------------|------------|--------------|------------|
| **(in millions)** | ** ** | **Plans**   | ** ** | **Benefits** | ** ** |
| 2006                   |       | $           | 29.0       |         | $          | 7.7 |   |
| 2007                   |       | $           | 28.3       |         | $          | 8.0 |   |
| 2008                   |       | $           | 27.6       |         | $          | 8.1 |   |
| 2009                   |       | $           | 26.7       |         | $          | 8.3 |   |
| 2010                   |       | $           | 25.9       |         | $          | 8.4 |   |
| 2011-2015              |       | $           | 123.4      |         | $          | 42.7 |   |

 

**Plan Assets.**The followingtable shows LG&E’s weighted-average asset allocation by asset category at December 31:

 
| ** **         | ** ** | **Target Range** | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|--------------------|------------|-----------------------|------------|----------|------------|----------|------------|----------|------------|
| Pension  Plans:    |       |                  |       |     |       |     |       |     |       |
| Equity  securities |       | 45% - 75              | %          | 57       | %          | 66       | %          | 66       | %          |
| Debt  securities   |       | 30% - 50              | %          | 42       | %          | 33       | %          | 33       | %          |
| Other              |       | 0% - 10               | %          | 1        | %          | 1        | %          | 1        | %          |
| 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 ofthe investment policy is to preserve the capital of the fund and maximizeinvestment earnings. The return objective is to exceed the benchmark return forthe policy index comprised of the following: Russell 3000 Index, MSCI-EAFE Index, Lehman Aggregate, and Lehman LongDuration Gov/Corporate Bond Index in proportions equal to the targeted assetallocation.

 

**Evaluationof performance focuses on a long-term investment time horizon of at least threeto five years or a complete market cycle. The assets of the pension plans arebroadly diversified within different asset classes (equities, fixed incomesecurities 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. The equity portion of the fund is diversifiedamong the market’s various subsections to diversify risk, maximize returns andavoid undue exposure to any single economic sector, industry group orindividual security. The equity subsectors include, but are not limited to,growth, value, small capitalization and international.

 

In addition, theoverall fixed income portfolio holdings may have an average weightedduration, or interest rate sensitivity which is within +/- 20% of the durationof the overall fixed income benchmark. Foreign bonds in the aggregate shall notexceed 10% of the total fund. The portfolio may include a limitedinvestment of up to 20% in below investment grade securities provided that theoverall average portfolio quality remains “AA” or better. The below investmentgrade securities include, but are not limited to, medium-term notes, corporatedebt, non-dollar and emerging market debt and asset backed securities. The cashinvestments should be in securities that

 

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either are ofshort maturities (not to exceed 180 days) or readily marketable with modestrisk.

 

Derivative securities are permitted only to improve the portfolio’srisk/return profile, modify the portfolio’s duration or to reduce transactioncosts and must be used in conjunction with underlying physical assets in theportfolio. Derivative securities that involve speculation, leverage, interestrate anticipation, or any undue risk whatsoever are not deemed appropriateinvestments.

 

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 postretirement funds are invested in a prime cash money market fund that investsprimarily in a portfolio of short-term, high-quality fixed income securitiesissued by banks, corporations and the U.S. government.

 

**Contributions.**LG&Emade discretionary contributions to the pension plan of $89.1 million during2003 and $34.5 million in January 2004. LG&E made a discretionary contributionto the pension plan for $17.5 million in January 2006. There were nocontributions during 2005.

 

**FSP 106-2.**FSP106-2, which provided guidance on accounting for subsidies provided under theMedicare Act, was effective for the first interim or annual period beginningafter June 15, 2004. The following table reflects the impact of thesubsidy in 2004:

 
| **(in millions)**                                                                     | ** ** | ** ** | ** ** |
|--------------------------------------------------------------------------------------------|------------|------------|------------|
| Reduction in  APBO                                                                         |       | $          | 3.2        |   |
|                                                                                       |       |
| Effect of the subsidy on the measurement of  the net periodic postretirement benefit cost: |       |
|                                                                                       |       |
| Amortization  of the actuarial experience gain/(loss)                                      |       | $          | 0.2        |   |
| Reduction in  service cost due to the subsidy                                              |       | —     |       |
| Resulting  reduction in interest cost on the APBO                                          |       | 0.2        |       |
| Total                                                                                      |       | $          | 0.4        |   |

 

**Thrift Savings Plans.**LG&Ehas a thrift savings plan under section 401(k) of the Internal RevenueCode. Under the plan, eligible employees may defer and contribute to theplan a portion of current compensation in order to provide future retirementbenefits. LG&E makes contributions to the plan by matching a portion of theemployee contributions. The costs of this matching were approximately $1.3million for 2005, $1.4 million for 2004 and $1.8 million for 2003.

 

**Note 7 - Income Taxes**

 

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

 
| **(in millions)**                 | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|----------------------------------------|------------|----------|------------|----------|------------|----------|------------|
|                                   |       |     |       |     |       |     |       |
| Current    - federal         |       | $        | 73.2       |     | $          | 33.9     |       | $ | 25.8 |   |
| - state                                |       | 10.1     |       | 13.0     |       | 10.0     |       |
| Deferred -  federal – net         |       | (12.6    | )          | 11.4     |       | 16.8     |       |
| - state –  net                    |       | (1.7     | )          | (0.8     | )          | 1.7      |       |
| Amortization  of investment tax credit |       | (4.1     | )          | (4.2     | )          | (4.2     | )          |
| Total income  tax expense              |       | $        | 64.9       |     | $          | 53.3     |       | $ | 50.1 |   |

 

Deferred federal income tax expense during 2003 and 2004 includedsignificant deductions attributable to federal bonus depreciation that endedafter December 2004.

 

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

 
| **(in millions)**                      | ** ** | **2005** | ** ** | **2004** | ** ** |
|---------------------------------------------|------------|----------|------------|----------|------------|
| Deferred tax  liabilities:                  |       |     |       |     |       |
| Depreciation  and other plant-related items |       | $        | 390.9      |     | $          | 397.8 |   |
| Regulatory  assets and other                |       | 22.5     |       | 33.3     |       |
| Total  deferred tax liabilities             |       | 413.4    |       | 431.1    |       |
|                                        |       |     |       |     |       |
| Deferred tax  assets:                       |       |     |       |     |       |
| Investment  tax credit                      |       | 16.6     |       | 18.6     |       |
| Income taxes  due to customers              |       | 16.5     |       | 15.0     |       |
| Pensions and  related benefits              |       | 39.2     |       | 32.2     |       |
| Liabilities  and other                      |       | 19.4     |       | 18.1     |       |
| Total  deferred tax assets                  |       | 91.7     |       | 83.9     |       |
|                                        |       |     |       |     |       |
| Net deferred  income tax liability          |       | $        | 321.7      |     | $          | 347.2 |   |

 

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

 
| ** **                                  | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|---------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Statutory  federal income tax rate          |       | 35.0     | %          | 35.0     | %          | 35.0     | %          |
| State income  taxes, net of federal benefit |       | 4.1      |       | 5.3      |       | 5.4      |       |
| Reduction of  income tax accruals           |       | (1.9     | )          | (0.7     | )          | (0.4     | )          |
| Investment  and other credits               |       | (2.1     | )          | (3.6     | )          | (3.0     | )          |
| Other differences                           |       | (1.6     | )          | (0.2     | )          | (1.5     | )          |
| Effective  income tax rate                  |       | 33.5     | %          | 35.8     | %          | 35.5     | %          |

 

On September 19, 2005, LG&E received notice from theCongressional Joint Committee on Taxation approving the Internal RevenueService’s audit of LG&E’s income tax returns for the periods December 1999through December 2003. As a result of resolving numerous tax mattersduring these periods, LG&E reduced income tax accruals by $3.8 millionduring 2005.

 

Kentucky HouseBill 272, also known as “Kentucky’s Tax Modernization Plan”, was signed into lawin March 2005. This bill contains a number of changes in Kentucky’s taxsystem, including the reduction of the Corporate income tax rate from 8.25% to7% effective January 1, 2005, and a further reduction to 6% effective January 1,2007. As a result of the income tax rate change, LG&E’s deferred taxreserve amount will exceed its actual deferred tax liability attributable toexisting temporary differences since the new statutory rates are lower than therates were when the deferred tax liability originated. This excess amount isreferred to as excess deferred income taxes. In June 2005, LG&Ereceived approval from the Kentucky Commission to establish and amortize aregulatory liability ($16.3 million) for its net excess deferred income taxbalances. Under the accounting treatment, LG&E will amortize itsdepreciation-related excess deferred income tax balances under the average rateassumption method. The average rate assumption method matches the amortizationof the excess deferred income taxes with the life of the timing differences towhich they relate. Excess deferred income tax balances related tonon-depreciation timing differences will be expensed in the current year due totheir immaterial amount.

 

LG&E expects to have adequate levels of taxable income to realizeits recorded deferred taxes.

 

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**Note 8 - Long-Term Debt**

 

As of December 31, 2005, long-term debt and the current portion oflong-term debt consist primarily of pollution control bonds and long-term loansfrom affiliated companies as summarized below.

 
| **(in millions)**                  | ** ** | **Stated  Interest Rates** | ** ** | **Maturities** | ** ** | **Principal  Amounts** | ** ** |
|-----------------------------------------|------------|---------------------------------|------------|----------------|------------|------------------------|------------|
| Outstanding  at December 31, 2005: |       |                            |       |           |       |                   |       |
| Noncurrent  portion                     |       | Variable - 5.90%                |       | 2008-2035      |       | $                      | 573.1      |   |
| Current  portion                        |       | Variable                        |       | 2006-2027      |       | 247.5                  |       |
|                                    |       |                            |       |           |       |                   |       |
| Outstanding  at December 31, 2004: |       |                            |       |           |       |                   |       |
| Noncurrent portion                      |       | Variable -  5.90%               |       | 2008-2033      |       | $                      | 574.4      |   |
| Current portion                         |       | Variable                        |       | 2005-2027      |       | 297.4                  |       |

 

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 tenderfor purchase at the option of the holder and to mandatory tender for purchaseupon the occurrence of certain events, causing the bonds to be classified ascurrent portion of long-term debt in the balance sheets. The average annualizedinterest rate for these bonds during 2005 and 2004 was 2.50% and 1.29%,respectively.

 

Pollutioncontrol series bonds are first mortgage bonds that have been issued byLG&E in connection with tax-exempt pollution control revenue bonds issuedby various governmental entities, principally counties in Kentucky. A loanagreement obligates LG&E to make debt service payments to the county thatequate to the debt service due from the county on the related pollution controlrevenue bonds. The county’s debt is also secured by an equal amount of LG&E’sfirst mortgage bonds (the pollution control series bonds) that are pledgedto the trustee for the pollution control revenue bonds, and that match theterms and conditions of the county’s debt, but require no payment of principaland interest unless LG&E defaults on the loan agreement.

 

Substantially all of LG&E’s utility assets are pledged as securityfor its first mortgage bonds. LG&E’s first mortgage bond indenture, assupplemented, provides that portions of retained earnings will not be availablefor the payment of dividends on common stock, under certain specifiedconditions. No portion of retained earnings was restricted by this provision asof either December 31, 2005 or 2004.

 

Interest rate swaps are used to hedge LG&E’s underlyingvariable-rate debt obligations. These swaps hedge specific debt issuances and,consistent with management’s designation, are accorded hedge accountingtreatment. The swaps exchange floating-rate interest payments for fixed rateinterest payments to reduce the impact of interest rate changes on LG&E’spollution control bonds.  As of December 31,2005 and 2004, LG&E had swaps with a combined notional value of $211.3million and $228.3 million, respectively. See Note 4, Financial Instruments.

 

Redemptions and maturities of long-term debt for 2005, 2004 and 2003are summarized below:

 
| ($ in millions) | ** ** | ** **                             | ** ** | ** **    | ** ** | ** ** | ** ** | ** **    | ** ** | ** **   | ** ** |
|---------------------------|------------|----------------------------------------|------------|---------------|------------|------------|------------|---------------|------------|--------------|------------|
|                      | ** ** | ** **                             | ** ** | ** **    | ** ** | ** ** | ** ** | ** **    | ** ** | ** **   | ** ** |
| ** **                | ** ** | ** **                             | ** ** | **Principal** | ** ** | ** ** | ** ** | **Secured/**  | ** ** | ** **   | ** ** |
| **Year**                  | ** ** | **Description**                        | ** ** | **Amount**    | ** ** | **Rate**   | ** ** | **Unsecured** | ** ** | **Maturity** | ** ** |
| 2005                      |       | Pollution control bonds                |       | $             | 40.0       |       | 5.90       | %             | Secured    |         | Apr 2023   |   |
| 2005                      |       | Due to Fidelia                         |       | $             | 50.0       |       | 1.53       | %             | Secured    |         | Jan 2005   |   |
| 2005                      |       | Mandatorily Redeemable Preferred Stock |       | $             | 1.3        |       | 5.875      | %             | Unsecured  |         | Jul 2005   |   |
| 2004                      |       | Due to Fidelia                         |       | $             | 50.0       |       | 1.53       | %             | Secured    |         | Jan 2005   |   |
| 2004                      |       | Mandatorily Redeemable Preferred Stock |       | $             | 1.3        |       | 5.875      | %             | Unsecured  |         | Jul 2004   |   |
| 2003                      |       | Pollution control bonds                |       | $             | 102.0      |       | 5.625      | %             | Secured    |         | Aug 2019   |   |
| 2003                      |       | Pollution control bonds                |       | $             | 26.0       |       | 5.45       | %             | Secured    |         | Oct 2020   |   |
| 2003                      |       | First mortgage bonds                   |       | $             | 42.6       |       | 6.00       | %             | Secured    |         | Aug 2003   |   |
| 2003                      |       | Mandatorily Redeemable Preferred Stock |       | $             | 1.3        |       | 5.875      | %             | Unsecured  |         | Jul 2003   |   |

 

 

 

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Issuances of long-term debt for 2005, 2004 and 2003 are summarizedbelow:

 
| ($ in millions) | ** ** | ** **              | ** ** | ** **    | ** ** | ** ** | ** ** | ** **    | ** ** |
|---------------------------|------------|-------------------------|------------|---------------|------------|------------|------------|---------------|------------|
| ** **                | ** ** | ** **              | ** ** | ** **    | ** ** | ** ** | ** ** | ** **    | ** ** | ** ** | ** ** |
| ** **                | ** ** | ** **              | ** ** | **Principal** | ** ** | ** ** | ** ** | **Secured/**  | ** ** | ** ** | ** ** |
| **Year**                  | ** ** | **Description**         | ** ** | **Amount**    | ** ** | **Rate**   | ** ** | **Unsecured** | ** ** | **Maturity** | ** ** |
| 2005                      |       | Pollution control bonds |       | $             | 40.0       |       | Variable   |          | Secured    |   | Feb 2035 |   |
| 2004                      |       | Due to Fidelia          |       | $             | 25.0       |       | 4.33       | %             | Secured    |   | Jan 2012 |   |
| 2004                      |       | Due to Fidelia          |       | $             | 100.0      |       | 1.53       | %             | Secured    |   | Jan 2005 |   |
| 2003                      |       | Pollution control bonds |       | $             | 128.0      |       | Variable   |          | Secured    |   | Oct 2033 |   |
| 2003                      |       | Due to Fidelia          |       | $             | 100.0      |       | 4.55       | %             | Unsecured  |   | Apr 2013 |   |
| 2003                      |       | Due to Fidelia          |       | $             | 100.0      |       | 5.31       | %             | Secured    |   | Aug 2013 |   |

 

LG&E has existing $5.875 series mandatorily redeemablepreferred stock outstanding having a current redemption price of $100 pershare. The preferred stock has a sinking fund requirement sufficient to retirea minimum of 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 per share.LG&E redeemed 12,500 shares in accordance with these provisions on July 15,2005, 2004 and 2003, leaving 212,500 shares currently outstanding. Beginningwith the three months ended September 30, 2003, LG&E reclassified its$5.875 series preferred stock as long-term debt with the minimum sharesmandatorily redeemable within one year classified as current.

 

Long-term debt maturities forLG&E are shown in the following table:

 
| **(in millions)** | ** ** | ** ** | ** ** |
|------------------------|------------|------------|------------|
| 2006                   |       | $          | 1.3        |   |
| 2007                   |       |       | 1.3        |   |
| 2008                   |       |       | 18.7       |   |
| 2009                   |       |       | —     |   |
| 2010                   |       |       | —     |   |
| Thereafter             |       |       | 799.3      | (a) |
| Total                  |       | $          | 820.6      |   |

 

----

(a)  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 2006.

 

# **Note 9 - Notes Payableand Other Short-Term Obligations**

# ** **

LG&E participates in an intercompany money pool agreement whereinE.ON U.S. and/or KU make funds available to LG&E at market-based rates(based on an index of highly rated commercial paper issues) up to $400.0million.

 
| ** **                    | ** ** | **Total Money**    | ** ** | **Amount**      | ** ** | **Balance**   | ** ** | **Average**            | ** ** |
|-------------------------------|------------|-------------------------|------------|-----------------|------------|---------------|------------|------------------------|------------|
| **($ in millions)** | ** ** | **Pool Available** | ** ** | **Outstanding** | ** ** | **Available** | ** ** | **Interest Rate** | ** ** |
| December 31,  2005       |       | $                       | 400.0      |            | $          | 141.2         |       | $                      | 258.8      |   | 4.21 | % |
| December 31,  2004       |       | $                       | 400.0      |            | $          | 58.2          |       | $                      | 341.8      |   | 2.22 | % |

 

E.ON U.S. maintains a revolving credit facility totaling $200.0 millionwith an affiliated company, E.ON North America, Inc., to ensure fundingavailability for the money pool. The balance outstanding on this facility at December 31,2005, was $104.7 million, leaving $95.3 million available. At December 31,2004, the facility totaled $150.0 million with a balance of $65.4 millionoutstanding, leaving $84.6 million available.

 

During June 2005, LG&E renewed five revolving lines of creditwith banks totaling $185.0 million. These credit facilities expire in June 2006,and there was no outstanding balance under any of these facilities at December 31,2005.

 

The covenants under these revolving lines of credit include:

 

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•                  Thedebt/total capitalization ratio must be less than 70%;

 

•                  E.ONAG must own at least 66.667% of voting stock of LG&E directly orindirectly;

 

•                  Thecorporate credit rating of the company must be at or above BBB- and Baa3; and

 

•                  Alimitation on disposing of assets aggregating more than 15% of total assets asof December 31, 2004.

 

**Note 10 - Commitments and Contingencies**

 

**Operating Leases.**LG&Eleases office space, office equipment and vehicles and accounts for theseleases as operating leases. Total lease expense for 2005, 2004 and 2003, lessamounts contributed by affiliated companies occupying a portion of the officespace leased by LG&E, was $3.0 million, $2.8 million and $2.2 million,respectively. The future minimum annual lease payments under LG&E’s officespace lease agreement for years subsequent to December 31, 2005, are shownin the following table:

 
| **(in millions)** | ** ** | ** ** | ** ** |
|------------------------|------------|------------|------------|
| 2006                   |       | $          | 3.5        |   |
| 2007                   |       |       | 3.6        |   |
| 2008                   |       |       | 3.7        |   |
| 2009                   |       |       | 3.8        |   |
| 2010                   |       |       | 3.8        |   |
| Thereafter             |       |       | 18.5       |   |
| Total                  |       | $          | 36.9       |   |

 

**Sale andLeaseback Transaction.**LG&E is a participant in asale and leaseback transaction involving its 38% interest in two jointly-ownedCTs at KU’s E.W. Brown generating station (Units 6 and 7). 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 fully defease the lease, 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 LG&E had retained its ownership. Theleasing transaction was entered into following receipt of required state andfederal regulatory approvals.

 

In case ofdefault under the lease, LG&E is obligated to pay to the lessor its shareof

 

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certain feesor amounts. Primary events of default include loss or destruction of the CTs,failure to insure or maintain the CTs and unwinding of the transaction due togovernmental actions. No events of default currently exist with respect to thelease. Upon any termination of the lease, whether by default or expiration ofits term, title to the CTs reverts jointly to LG&E and KU.

 

At December 31,2005, the maximum aggregate amount of default fees or amounts, which decreaseover the term of the lease, was $8.2 million, of which LG&E would beresponsible for $3.1 million (38%). LG&E has made arrangements with E.ONU.S., via guarantee and regulatory commitment, for E.ON U.S. to pay LG&E’sfull portion of any default fees or amounts.

 

**Letters ofCredit.**LG&E has provided letters of credittotaling $3.0 million to support certain obligations related to landfillreclamation.

 

**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. 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%. ThroughMarch 2006, LG&E is entitled to purchase 7% of OVEC’s output, andthereafter is entitled to purchase 5.63%, representing approximately 124 Mw ofgeneration capacity. In April 2004, OVEC and its shareholders, includingLG&E, entered into an Amended and Restated Inter-Company Power Agreement,to be effective beginning March 2006, upon the expiration of the currentpower contract among the parties. The parties received SEC approval under PUHCA1935 of the Amended and Restated Inter-Company Power Agreement in February 2005.Future obligations for power purchases are shown in the following table:

 
| **(in millions)** | ** ** | ** ** | ** ** |
|------------------------|------------|------------|------------|
| 2006                   |       | $          | 11.1       |   |
| 2007                   |       |       | 10.9       |   |
| 2008                   |       |       | 11.0       |   |
| 2009                   |       |       | 11.3       |   |
| 2010                   |       |       | 11.5       |   |
| Thereafter             |       |       | 215.1      |   |
| Total                  |       | $          | 270.9      | (a) |

 

----

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

 

**Construction Program.**LG&Ehad approximately $23.0 million of commitments in connection with its constructionprogram at December 31, 2005. Construction expenditures for the three yearperiod ending December 31, 2008, are estimated to total approximately$530.0 million, although all of this amount is not currently committed,including future expenditures related to the construction of Trimble CountyUnit 2.

 

**Environmental Matters.**LG&Eis subject to SO2 and NOx emission limits on its electric generatingunits pursuant to the Clean Air Act. LG&E was exempt from Phase I SO2requirements due to its low emission rates. LG&E opted into the Phase I NOxprogram to take advantage of the less stringent requirements and installedburner modifications as needed to meet these limitations. LG&E’s strategy for Phase II SO2reductions, which commenced January 1, 2000, is to increase FGDremoval efficiency to delay additional capital expenditures and may alsoinclude fuel switching or upgrading FGDs. LG&E met the initial NOx emissionrequirements of the Act through installation of low-NOx burner systems. LG&E’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. LG&E will continue to monitor these developmentsto ensure that its environmental obligations are met in the most efficient andcost-effective manner.

 

In September 1998, the EPA announced its final “NOx SIP Call” rule requiringstates to impose significant additional reductions in NOx emissions by May 2003,in order to mitigate alleged ozone transport impacts on the Northeast region. TheCommonwealth of Kentucky SIP, which was approved by the EPA on June 24,2003, requires reductions in NOx emissions from coal-fired generating units tothe 0.15 lb./MMBtu level on a system-wide basis. In related proceedings inresponse to petitions filed by various Northeast states, in December 1999,the EPA issued a final rule pursuant to Section 126 of the Clean AirAct directing similar NOx reductions from a number of specifically targetedgenerating units including all LG&E units. As a result of appeals to bothrules, the compliance date was extended to May 31, 2004. All LG&Egenerating units are in compliance with these NOx emissions reduction rules.

 

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LG&E has added significant NOx controls to its generating unitsthrough the installation of SCR systems, advanced low-NOx burners and neuralnetworks. The NOx control project commenced in late 2000 with the controlsbeing placed into operation prior to the 2004 summer ozone season. As ofDecember 31, 2005, LG&E incurred total capital costs of approximately$188.0 million to reduce its NOx emissions below the 0.15 lb./MMBtu level on acompany-wide basis. In addition, LG&E will incur additional operating andmaintenance costs in operating new NOx controls. LG&E believes its costs inthis regard to be comparable to those of similarly situated utilities with likegeneration assets. LG&E 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 April 2001, the Kentucky Commission grantedrecovery of these costs for LG&E.

 

On March 10, 2005, the EPA issued the final CAIR which requiressubstantial additional reductions in SO2 and NOx emissions fromelectric generating units. The CAIR provides for a two-phased reduction programwith Phase I reductions in NOx and SO2 emissions in 2009 and 2010,respectively, and Phase II reductions in 2015. On March 15, 2005, the EPAissued a related regulation, the final CAMR, which requires substantial mercuryreductions from electric generating units. CAMR also provides for a two-phasedreduction, with the Phase I target in 2010 achieved as a “co-benefit” of thecontrols installed to meet CAIR. Additional control measures will be requiredto meet the Phase II target in 2018. Both CAIR and CAMR establish a cap andtrade framework, in which a limit is set on total emissions and allowances canbe bought or sold on the open market to be used for compliance, unless thestate chooses another approach. LG&E currently has FGDs on all its unitsbut will continue to evaluate improvements to further reduce SO2emissions.

 

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 and measures to implement the EPA’sCAVR. From time to time, LG&E has conducted negotiations with the relevantregulatory authorities to address various environmental matters, includingremedial measures aimed at controlling particulate matter emissions from itsMill Creek plant. LG&E previously settled a number of property damageclaims from residents adjacent to the plant and completed significant remedialmeasures as part of its ongoing capital construction program. LG&E hasconverted the Mill Creek Station to wet stack operation in an effort to resolveall outstanding issues related to particulate matter emissions. In addition,LG&E has periodically conducted negotiations with the relevant regulatoryauthorities to resolve potential liability for cleanup of off-site facilitiesthat allegedly handled materials associated with company operations.

 

LG&E owns or formerly owned three properties which are the locationof past MGP operations. Various contaminants are typically found at such formerMGP sites and environmental remediation measures are frequently required. Withrespect to the sites, LG&E has substantially completed cleanups, obtainedregulatory approval of site management plans, or reached agreements for otherparties to assume responsibility for cleanup. Based on currently availableinformation, management estimates that it could incur additional costs of $0.4million for additional cleanup. Accordingly, an accrual for this amount hasbeen recorded in the accompanying financial statements at December 31,2005 and 2004.

 

**Note 11 - Jointly Owned Electric Utility Plant**

 

LG&E owns a 75% undivided interest in Trimble County Unit 1 whichthe Kentucky Commission has allowed to be reflected in customer rates. Of theremaining 25% of the Unit, IMEA owns a 12.12% undivided interest, and IMPA ownsa 12.88% undivided interest. Each company is responsible for its proportionateownership share of fuel cost, operation and maintenance expenses, andincremental assets. The following data represent shares of the jointly ownedproperty:

 

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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  millions)**                              | ** ** | ** **   | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Cost                                            |       | $            | 599.2      |       |       |       |       |       |       |   |
| Accumulated depreciation                        |       | (221.1       | )          |       |       |       |       |       |       |
| Net book value                                  |       | $            | 378.1      |       |       |       |       |       |       |   |
|                                            |       |         |       |       |       |       |       |       |       |
| Construction work in progress (included  above) |       | $            | 9.1        |       |       |       |       |       |       |   |

 

LG&E and KU jointly own the following combustion turbines:

 
| **($ in millions)** | ** ** | ** **      | ** ** | **LG&E** | ** ** | **KU** | ** ** | **Total** | ** ** |
|-------------------------------|------------|-----------------|------------|--------------|------------|--------|------------|-----------|------------|
| Paddy’s Run 13           |       | Ownership %     |       | 53           | %          | 47     | %          | 100       | %          |
|                          |       | Mw capacity     |       | 84           |       | 74     |       | 158       |       |
|                          |       | Cost            |       | $            | 34.0       |   | $          | 30.1      |       | $ | 64.1 |   |
|                          |       | Depreciation    |       | (5.2         | )          | (4.6   | )          | (9.8      | )          |
|                          |       | Net book  value |       | $            | 28.8       |   | $          | 25.5      |       | $ | 54.3 |   |
|                          |       |            |       |         |       |   |       |      |       |
| E.W. Brown 5                  |       | Ownership %     |       | 53           | %          | 47     | %          | 100       | %          |
|                          |       | Mw capacity     |       | 62           |       | 55     |       | 117       |       |
|                          |       | Cost            |       | $            | 24.0       |   | $          | 20.2      |       | $ | 44.2 |   |
|                          |       | Depreciation    |       | (3.5         | )          | (3.0   | )          | (6.5      | )          |
|                          |       | Net book  value |       | $            | 20.5       |   | $          | 17.2      |       | $ | 37.7 |   |
|                          |       |            |       |         |       |   |       |      |       |
| E.W. Brown 6                  |       | Ownership %     |       | 38           | %          | 62     | %          | 100       | %          |
|                          |       | Mw capacity     |       | 59           |       | 95     |       | 154       |       |
|                          |       | Cost            |       | $            | 25.3       |   | $          | 38.9      |       | $ | 64.2 |   |
|                          |       | Depreciation    |       | (4.2         | )          | (7.9   | )          | (12.1     | )          |
|                          |       | Net book  value |       | $            | 21.1       |   | $          | 31.0      |       | $ | 52.1 |   |
|                          |       |            |       |         |       |   |       |      |       |
| E.W. Brown 7                  |       | Ownership %     |       | 38           | %          | 62     | %          | 100       | %          |
|                          |       | Mw capacity     |       | 59           |       | 95     |       | 154       |       |
|                          |       | Cost            |       | $            | 24.9       |   | $          | 39.7      |       | $ | 64.6 |   |
|                          |       | Depreciation    |       | (6.4         | )          | (8.2   | )          | (14.6     | )          |
|                          |       | Net book  value |       | $            | 18.5       |   | $          | 31.5      |       | $ | 50.0 |   |
|                          |       |            |       |         |       |   |       |      |       |
| Trimble 5                     |       | Ownership %     |       | 29           | %          | 71     | %          | 100       | %          |
|                          |       | Mw capacity     |       | 46           |       | 114    |       | 160       |       |
|                          |       | Cost            |       | $            | 16.4       |   | $          | 39.7      |       | $ | 56.1 |   |
|                          |       | Depreciation    |       | (1.9         | )          | (4.7   | )          | (6.6      | )          |
|                          |       | Net book  value |       | $            | 14.5       |   | $          | 35.0      |       | $ | 49.5 |   |
|                          |       |            |       |         |       |   |       |      |       |
| Trimble 6                     |       | Ownership %     |       | 29           | %          | 71     | %          | 100       | %          |
|                          |       | Mw capacity     |       | 46           |       | 114    |       | 160       |       |
|                          |       | Cost            |       | $            | 16.2       |   | $          | 39.7      |       | $ | 55.9 |   |
|                          |       | Depreciation    |       | (1.9         | )          | (4.7   | )          | (6.6      | )          |
|                          |       | Net book  value |       | $            | 14.3       |   | $          | 35.0      |       | $ | 49.3 |   |
|                          |       |            |       |         |       |   |       |      |       |
| Trimble 7                     |       | Ownership %     |       | 37           | %          | 63     | %          | 100       | %          |
|                          |       | Mw capacity     |       | 59           |       | 101    |       | 160       |       |
|                          |       | Cost            |       | $            | 19.3       |   | $          | 33.3      |       | $ | 52.6 |   |
|                          |       | Depreciation    |       | (1.0         | )          | (1.7   | )          | (2.7      | )          |
|                          |       | Net book  value |       | $            | 18.3       |   | $          | 31.6      |       | $ | 49.9 |   |

 

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| Trimble 8             |   | Ownership %     |   | 37     | %         | 63     | %      | 100       | %      |
|-----------------------|--------|-----------------|--------|--------|-----------|--------|--------|-----------|--------|
|                  |   | Mw capacity     |   | 59     |      | 101    |   | 160       |   |
|                  |   | Cost            |   | $      | 19.2      |   | $      | 32.8      |   | $ | 52.0 |   |
|                  |   | Depreciation    |   | (1.0   | )         | (1.7   | )      | (2.7      | )      |
|                  |   | Net book  value |   | $      | 18.2      |   | $      | 31.1      |   | $ | 49.3 |   |
|                  |   |            |   |   |      |   |   |      |   |
| Trimble 9             |   | Ownership %     |   | 37     | %         | 63     | %      | 100       | %      |
|                  |   | Mw capacity     |   | 59     |      | 101    |   | 160       |   |
|                  |   | Cost            |   | $      | 19.2      |   | $      | 32.8      |   | $ | 52.0 |   |
|                  |   | Depreciation    |   | (1.0   | )         | (1.6   | )      | (2.6      | )      |
|                  |   | Net book  value |   | $      | 18.2      |   | $      | 31.2      |   | $ | 49.4 |   |
|                  |   |            |   |   |      |   |   |      |   |
| Trimble 10            |   | Ownership %     |   | 37     | %         | 63     | %      | 100       | %      |
|                  |   | Mw capacity     |   | 59     |      | 101    |   | 160       |   |
|                  |   | Cost            |   | $      | 19.1      |   | $      | 32.8      |   | $ | 51.9 |   |
|                  |   | Depreciation    |   | (0.9   | )         | (1.6   | )      | (2.5      | )      |
|                  |   | Net book  value |   | $      | 18.2      |   | $      | 31.2      |   | $ | 49.4 |   |
|                  |   |            |   |   |      |   |   |      |   |
| Trimble CT Pipeline   |   | Ownership %     |   | 29     | %         | 71     | %      | 100       | %      |
|                  |   | Cost            |   | $      | 2.0       |   | $      | 4.9       |   | $ | 6.9 |   |
|                  |   | Depreciation    |   | (0.2   | )         | (0.6   | )      | (0.8      | )      |
|                  |   | Net book  value |   | $      | 1.8       |   | $      | 4.3       |   | $ | 6.1 |   |
|                  |   |            |   |   |      |   |   |      |   |
| Trimble CT Substation |   | Ownership %     |   | 29     | %         | 71     | %      | 100       | %      |
| 5 & 6             |   | Cost            |   | $      |  1.5 |   | $      |  3.6 |   | $ | 5.1 |   |
|                  |   | Depreciation    |   | (0.1   | )         | (0.3   | )      | (0.4      | )      |
|                  |   | Net book  value |   | $      | 1.4       |   | $      | 3.3       |   | $ | 4.7 |   |
|                  |   |            |   |   |      |   |   |      |   |
| Trimble CT Substation |   | Ownership %     |   | 37     | %         | 63     | %      | 100       | %      |
| 7 - 10                |   | Cost            |   | $      |  3.1 |   | $      |  4.9 |   | $ | 8.0 |   |
|                  |   | Depreciation    |   | (0.1   | )         | (0.2   | )      | (0.3      | )      |
|                  |   | Net book  value |   | $      | 3.0       |   | $      | 4.7       |   | $ | 7.7 |   |

 

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 12 - Segments of Business and Related Information**

 

LG&E is a regulated public utility engaged in the generation,transmission, distribution and sale of electricity and the storage,distribution and sale of natural gas. LG&E is regulated by the KentuckyCommission and files electric and natural gas financial information separatelywith the Kentucky Commission. The Kentucky Commission establishes ratesspecifically for the electric and natural gas businesses. Therefore, managementreports and analyzes financial performance based on the electric and naturalgas segments of the business. Financial data for business segments follow:

 

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| **(in millions)**        | ** ** | **Electric** | ** ** | **Gas** | ** ** | **Total** | ** ** |
|-------------------------------|------------|--------------|------------|---------|------------|-----------|------------|
| 2005                          |       |         |       |    |       |      |       |
| Operating revenues            |       | $            | 987.4      |    | $          | 436.9     |       | $ | 1,424.3 |   |
| Depreciation and amortization |       | 106.2        |       | 17.9    |       | 124.1     |       |
| Income taxes                  |       | 60.0         |       | 4.9     |       | 64.9      |       |
| Interest income               |       | 0.5          |       | 0.1     |       | 0.6       |       |
| Interest expense              |       | 30.3         |       | 6.5     |       | 36.8      |       |
| Net income                    |       | 119.4        |       | 9.5     |       | 128.9     |       |
| Total assets                  |       | 2,475.0      |       | 671.4   |       | 3,146.4   |       |
| Construction expenditures     |       | 96.5         |       | 42.4    |       | 138.9     |       |
|                          |       |         |       |    |       |      |       |
| 2004                          |       |         |       |    |       |      |       |
| Operating revenues            |       | $            | 815.7      |    | $          | 357.1     |       | $ | 1,172.8 |   |
| Depreciation and amortization |       | 100.0        |       | 16.6    |       | 116.6     |       |
| Income taxes                  |       | 48.3         |       | 5.0     |       | 53.3      |       |
| Interest income               |       | 0.2          |       | —  |       | 0.2       |       |
| Interest expense              |       | 27.3         |       | 5.5     |       | 32.8      |       |
| Net income                    |       | 87.2         |       | 8.4     |       | 95.6      |       |
| Total assets                  |       | 2,416.5      |       | 550.0   |       | 2,966.5   |       |
| Construction expenditures     |       | 113.4        |       | 34.9    |       | 148.3     |       |
|                          |       |         |       |    |       |      |       |
| 2003                          |       |         |       |    |       |      |       |
| Operating revenues            |       | $            | 768.2      |    | $          | 325.3     |       | $ | 1,093.5 |   |
| Depreciation and amortization |       | 96.5         |       | 16.8    |       | 113.3     |       |
| Income taxes                  |       | 44.7         |       | 5.4     |       | 50.1      |       |
| Interest income               |       | —       |       | —  |       | —    |       |
| Interest expense              |       | 25.7         |       | 5.0     |       | 30.7      |       |
| Net income                    |       | 80.6         |       | 10.2    |       | 90.8      |       |
| Total assets                  |       | 2,338.9      |       | 543.2   |       | 2,882.1   |       |
| Construction expenditures     |       | 178.0        |       | 35.0    |       | 213.0     |       |

 

**Note 13 -****Related Party Transactions**

 

LG&E, subsidiaries of E.ON U.S. and other subsidiaries of E.ONengage in related party transactions. Transactions between LG&E and itssubsidiary LG&E R are eliminated upon consolidation with LG&E. Transactionsbetween LG&E and E.ON U.S. subsidiaries are eliminated upon consolidationof E.ON U.S. Transactions between LG&E and E.ON subsidiaries are eliminatedupon consolidation of E.ON. These transactions are generally performed at costand are in accordance with the prior SEC regulations under PUHCA 1935 and theapplicable FERC and Kentucky Commission regulations. Amounts payable to and receivablefrom related parties are netted and presented as accounts payable to affiliatedcompanies on the balance sheet of LG&E, as allowed due to the right ofoffset. Obligations related to intercompany debt arrangements with E.ON U.S.and 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&Esells energy to LEM, a subsidiary of E.ON U.S. These sales and purchases areincluded in the Statements of Income as Electric Operating Revenues andPurchased Power Operating Expense. LG&E intercompany electric revenues andpurchased power expense for the years ended December 31, 2005, 2004 and 2003were as follows:

 
| **(in millions)**               | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|--------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Electric operating revenues from KU  |       | $        | 91.6       |     | $          | 58.7     |       | $ | 53.7 |   |
| Electric operating revenues from LEM |       | —   |       | 0.4      |       | 9.4      |       |
| Purchased power from KU              |       | 95.5     |       | 61.7     |       | 46.7     |       |
|                                      |            |          |            |          |            |          |            |  |  |  |

 

Interest Charges

 

See Note 9, Notes Payable and Other Short-Term Obligations, for detailsof intercompany borrowing arrangements. Intercompany agreements do not requireinterest payments for receivables related to services provided when settledwithin 30 days.

 

102

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LG&E’s intercompany interest income and expense for the years endedDecember 31, 2005, 2004 and 2003 were as follows:

 
| **(in millions)**       | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Interest on money pool loans |       | $        | 1.8        |     | $          | 0.3      |       | $ | 1.8 |   |
| Interest on Fidelia loans    |       | 10.9     |       | 11.9     |       | 5.0      |       |
|                              |            |          |            |          |            |          |            |  |  |  |

 

Other Intercompany Billings

 

E.ON U.S. Services provides LG&E with a variety of centralizedadministrative, management and support services. These charges include payrolltaxes paid by E.ON U.S. on behalf of LG&E, labor and burdens of E.ON U.S.Services employees performing services for LG&E and vouchers paid by E.ONU.S. Services on behalf of LG&E. The cost of these services are directlycharged to LG&E, or for general costs which cannot be directly attributed,charged based on predetermined allocation factors, including the followingratios: number of customers, total assets, revenues, number of employees andother statistical information. These costs are charged on an actual cost basis.

 

In addition, LG&E and KU provide services to each other and to E.ONU.S. Services. Billings between LG&E and KU relate to labor and overheadsassociated with union employees performing work for the other utility, chargesrelated to jointly-owned combustion turbines, and other miscellaneous charges. Billingsfrom LG&E to E.ON U.S. Services related to information technology-relatedservices provided by LG&E employees, cash received by E.ON U.S. Services onbehalf of LG&E and services provided by LG&E to other non-regulatedbusinesses which are paid through E.ON U.S. Services.

 

Intercompany billings to and from LG&E for the years ended December31, 2005, 2004 and 2003 were as follows:

 
| **(in millions)**                  | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|-----------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| E.ON U.S. Services billings to LG&E |       | $        | 208.4      |     | $          | 190.7    |       | $ | 196.1 |   |
| LG&E billings to KU                 |       | 100.5    |       | 59.5     |       | 77.2     |       |
| KU billings to LG&E                 |       | 28.6     |       | 7.2      |       | 16.6     |       |
| LG&E billings to E.ON U.S. Services |       | 8.2      |       | 12.5     |       | 23.7     |       |
|                                         |            |          |            |          |            |          |            |  |  |  |

 

Theincrease in 2005 billings between LG&E and KU is largely due to theincrease in the unit cost of purchased power resulting from the 2005 increasesin fuel costs.

 

**Note 14 – Accumulated Other Comprehensive Income**

 

Accumulated other comprehensive income (loss) consisted of thefollowing:

 
| ** **                                                                                           | ** ** | **Minimum**    | ** ** | ** **                 | ** ** | ** **  | ** ** | ** ** | ** ** | ** ** | ** ** |
|------------------------------------------------------------------------------------------------------|------------|----------------|------------|----------------------------|------------|-------------|------------|------------|------------|------------|------------|
| ** **                                                                                           | ** ** | **Pension**    | ** ** | **Accumulated**            | ** ** | ** **  | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **                                                                                           | ** ** | **Liability**  | ** ** | **Derivative**             | ** ** | ** **  | ** ** | **Income** | ** ** | ** ** | ** ** |
| **(in millions)**                                                                               | ** ** | **Adjustment** | ** ** | **Gain or Loss** | ** ** | **Pre-Tax** | ** ** | **Taxes**  | ** ** | **Net**    | ** ** |
| Balance at December 31, 2002                                                                         |       | $              | (50.7      | )                          | $          | (17.2       | )          | $          | (67.9      | )          | $          | 27.4 |   | $ | (40.5 | ) |
|                                                                                                 |       |           |       |                       |       |        |       |       |       |       |       |
| Minimum pension liability adjustment                                                                 |       | 3.1            |       | —                     |       | 3.1         |       | (1.2       | )          | 1.9        |       |
| Gains (losses) on derivative instruments designated  and qualifying as cash flow hedging instruments |       | —         |       | 0.9                        |       | 0.9         |       | (0.4       | )          | 0.5        |       |
| Balance at December 31, 2003                                                                         |       | (47.6          | )          | (16.3                      | )          | (63.9       | )          | 25.8       |       | (38.1      | )          |
| Minimum pension liability adjustment                                                                 |       | (10.2          | )          | —                     |       | (10.2       | )          | 4.1        |       | (6.1       | )          |
| Gains (losses) on derivative instruments designated  and qualifying as cash flow hedging instruments |       | —         |       | (2.3                       | )          | (2.3        | )          | 0.9        |       | (1.4       | )          |
| Balance at December 31, 2004                                                                         |       | $              | (57.8      | )                          | $          | (18.6       | )          | $          | (76.4      | )          | $          | 30.8 |   | $ | (45.6 | ) |
|                                                                                                 |       |           |       |                       |       |        |       |       |       |       |       |
| Minimum pension liability adjustment                                                                 |       | (19.2          | )          | —                     |       | (19.2       | )          | 6.7        |       | (12.5      | )          |
| Gains (losses) on derivative instruments designated  and qualifying as cash flow hedging instruments |       | —         |       | (0.1                       | )          | (0.1        | )          | —     |       | (0.1       | )          |
| Balance at December 31, 2005                                                                         |       | $              | (77.0      | )                          | $          | (18.7       | )          | $          | (95.7      | )          | $          | 37.5 |   | $ | (58.2 | ) |

 

103

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**Note 15 - Selected Quarterly Data (Unaudited)**

 

Selected financial data for the four quarters of 2005 and 2004 areshown below. Because of seasonal fluctuations in temperature and other factors,results for quarters may fluctuate throughout the year.

 
| ** **             | ** ** | **Quarters Ended** | ** ** |
|------------------------|------------|-------------------------|------------|
| **(in millions)** | ** ** | **March**               | ** ** | **June** | ** ** | **September** | ** ** | **December** | ** ** |
| 2005                   |       |                    |       |   |   |   |   |   |   |
| Operating revenues     |       | $                       | 402.4      |   | $ | 280.7 |   | $ | 318.6 |   | $ | 422.6 |   |
| Net operating income   |       | 61.6                    |       | 52.5 |   | 65.9 |   | 49.9 |   |
| Net income             |       | 33.9                    |       | 28.0 |   | 42.0 |   | 25.0 |   |
|                   |       |                    |       |   |   |   |   |   |   |
| 2004                   |       |                    |       |   |   |   |   |   |   |
| Operating revenues     |       | $                       | 362.0      |   | $ | 236.2 |   | $ | 261.8 |   | $ | 312.8 |   |
| Net operating income   |       | 47.6                    |       | 34.6 |   | 62.8 |   | 40.0 |   |
| Net income             |       | 24.2                    |       | 17.1 |   | 32.5 |   | 21.8 |   |

 

**Note 16 - Subsequent Events**

 

On January 20, 2006, LG&E made a discretionary contribution to thepension plan in the amount of $17.5 million.

 

On February 27, 2006, the AG, KIUC, LG&E and KU reached asettlement agreement on the future ratemaking treatment of the VDT surcreditsand costs and subsequently submitted a joint motion to the Kentucky Commissionto approve the unanimous settlement agreement. Under the terms of thesettlement agreement, the VDT surcredit will continue at the current leveluntil such time as LG&E files for a change in electric or gas base rates. TheKentucky Commission held a public hearing in the proceeding on March 21, 2006and issued an order thereafter approving the settlement agreement.

 

On March 17, 2006 the FERCissued an order conditionally approving the request of LG&E and KU to exitthe MISO.

 

The Companies must satisfy anumber of conditions to effect their exit from the MISO including:

 

•      Submissionof various compliance filings addressing:

 

•      theCompanies’ hold-harmless obligations under the MISO Transmission Owners’Agreement, and the amount of the MISO exit fee to be paid by the Companies ascalculated under the approved methodology;

 

•      theCompanies’ anticipated arrangements with SPP and TVA, including revisions toaddress certain independence and transmission planning considerations, andreciprocity arrangements to ensure certain KU requirements customers do notincur pancaked rates for transmission and ancillary services;

 

•      theCompanies’ proposed OATT, as revised to address possible capacity hoarding,available transmission calculation methodology, curtailment priority andpricing, among other matters; and

 

•      theCompanies’ finalized arrangements with the SPP and TVA.

 

•      TheCompanies must also file an application of the proposed OATT under Section 205of the Federal Power Act including a proposed return on equity.

 

While LG&E and KU believethey can reasonably achieve all of the conditions imposed by the FERC order,completion of a number of the conditions is dependent upon the actions oragreement of third parties. There is also a risk that the FERC decision will bechallenged by intervenors with a request for rehearing, which could happenwithin 30 days of the decision. The Companies are currently unable to estimatethe time period, if any, in which the conditions of the FERC order might be satisfied,the Companies might receive Kentucky Commission approval and, thereafter, exitthe MISO.

 

104

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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 beenprepared in accordance with accounting principles generally accepted in theUnited States applied on a consistent basis and, necessarily, include amountsthat reflect the best estimates and judgment of management.

 

LG&E’s financial statements for the three years ended December 31,2005, have been audited by PricewaterhouseCoopers LLP, an independentregistered public accounting firm. Management made available to PricewaterhouseCoopersLLP all LG&E’s financial records and related data as well as the minutes ofshareholders’ 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. Management believes that an adequate system of internalcontrols is maintained through the selection and training of personnel,appropriate division of responsibility, establishment and communication ofpolicies and procedures and by regular reviews of internal accounting controlsby 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. Theserecommendations for the year ended December 31, 2005, did not identify anymaterial weaknesses in the design and operation of LG&E’s internal controlstructure.

 

LG&E isnot an accelerated filer under the Sarbanes-Oxley Act of 2002 and associatedrules (the “Act”) and consequently anticipates issuing Management’s Report onInternal Controls over Financial Reporting pursuant to Section 404 of the Actin its first periodic report covering the fiscal year ended December 31, 2007,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 registered public accounting firm, internal auditors andmanagement. The Board of Directors reviews the results of the independentregistered public accounting firm’s audit of the financial statements and theiraudit procedures, and discusses the adequacy of internal accounting controls. TheBoard of Directors also approves the annual internal auditing program andreviews the activities and results of the internal 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

 

Date: March 29, 2006  

 

105

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Report of IndependentRegistered Public Accounting Firm

 

To the Shareholder of Louisville Gas and Electric Company:

 

In our opinion, the accompanying balance sheet and the relatedstatement of capitalization, income, retained earnings, cash flows andcomprehensive income present fairly, in all material respects, the financialposition of Louisville Gas and Electric Company at December 31, 2005 and December 31,2004, and the results of its operations and its cash flows for each of thethree years in the period ended December 31, 2005 in conformity withaccounting principles generally accepted in the United States of America. Inaddition, in our opinion, the financial statement schedule listed in theindex appearing under Item 15(a)(2) present fairly, in all materialrespects, the information set forth therein when read in conjunction with therelated financial statements. These financial statements and financialstatement schedule are the responsibility of the Company’s management. Ourresponsibility is to express an opinion on these financial statements andfinancial statement schedule based on our audits. We conducted our audits ofthese statements in accordance with the standards of the Public CompanyAccounting Oversight Board (United States). Those standards require that weplan and perform the audit to obtain reasonable assurance about whetherthe financial statements are free of material misstatement. An audit includesexamining, on a test basis, evidence supporting the amounts and disclosures inthe financial statements, assessing the accounting principles used andsignificant estimates made by management, and evaluating the overall financialstatement presentation. We believe that our audits provide a reasonable basisfor our opinion.

 

As discussed in Note 1 to the financial statements, effective December31, 2005, Louisville Gas and Electric Company adopted Statement of FinancialAccounting Standards Board Interpretation No. 47, *Accountingfor Conditional Asset Retirement Obligations.*

 

/s/ PricewaterhouseCoopers LLP

Louisville, Kentucky

February 8, 2006

 

106

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INDEX OF ABBREVIATIONS

 
| AEP                 |   | American Electric Power Company, Inc.                                   |
|---------------------|--------|-------------------------------------------------------------------------|
| AFUDC               |   | Allowance for Funds Used During  Construction                           |
| AG                  |   | Attorney General of Kentucky                                            |
| APBO                |   | Accumulated Postretirement Benefit  Obligation                          |
| ARO                 |   | Asset Retirement Obligation                                             |
| CAIR                |   | Clean Air Interstate Rule                                               |
| CAMR                |   | Clean Air Mercury Rule                                                  |
| Capital Corp.       |   | E.ON U.S. Capital Corp. (formerly LG&E  Capital Corp.)              |
| CAVR                |   | Clean Air Visibility Rule                                               |
| Clean Air Act       |   | The Clean Air Act, as amended in 1990                                   |
| CCN                 |   | Certificate of Public Convenience and  Necessity                        |
| Company             |   | LG&E or KU, as applicable                                           |
| Companies           |   | LG&E and KU                                                         |
| CO2                 |   | Carbon Dioxide                                                          |
| CT                  |   | Combustion Turbines                                                     |
| CWIP                |   | Construction Work in Progress                                           |
| DOE                 |   | Department of Energy                                                    |
| DOJ                 |   | Department of Justice                                                   |
| 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                                                                 |
| E.ON U.S.           |   | E.ON U.S. LLC (formerly LG&E Energy LLC  and LG&E Energy Corp.) |
| E.ON U.S. Services  |   | E.ON U.S. Services Inc. (formerly LG&E  Energy Services Inc.)       |
| EPA                 |   | U.S. Environmental Protection Agency                                    |
| EPAct 2005          |   | Energy Policy Act of 2005                                               |
| ESM                 |   | Earnings Sharing Mechanism                                              |
| ERISA               |   | Employee Retirement Income Security Act of  1974, as amended            |
| Fidelia             |   | Fidelia Corporation (an E.ON affiliate)                                 |
| FAC                 |   | Fuel Adjustment Clause                                                  |
| FASB                |   | Financial Accounting Standards Board                                    |
| FERC                |   | Federal Energy Regulatory Commission                                    |
| FGD                 |   | Flue Gas Desulfurization                                                |
| FIN                 |   | FASB Interpretation                                                     |
| FPA                 |   | Federal Power Act                                                       |
| FSP                 |   | FASB Staff Position                                                     |
| FT and FT-A         |   | Firm Transportation                                                     |
| FTR                 |   | Financial Transmission Right                                            |
| GSC                 |   | Gas Supply Clause                                                       |
| GFA                 |   | Grandfathered Transmission Agreement                                    |
| IBEW                |   | International Brotherhood of Electrical  Workers                        |
| IMEA                |   | Illinois Municipal Electric Agency                                      |
| IMPA                |   | Indiana Municipal Power Agency                                          |
| IRC                 |   | Internal Revenue Code of 1986, as amended                               |
| IRP                 |   | Integrated Resource Plan                                                |
| ITP                 |   | Independent Transmission Provider                                       |
| 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.                                          |

 

107

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| LG&E            |   | Louisville Gas and Electric Company                          |
|---------------------|--------|--------------------------------------------------------------|
| LG&E Energy     |   | LG&E Energy LLC (now E.ON U.S. LLC)                      |
| LG&E R          |   | LG&E Receivables LLC                                     |
| LG&E Services   |   | LG&E Energy Services Inc. (now E.ON  U.S. Services Inc.) |
| LMP                 |   | Locational Marginal Pricing                                  |
| LNG                 |   | Liquefied Natural Gas                                        |
| Mcf                 |   | Thousand Cubic Feet                                          |
| MGP                 |   | Manufactured Gas Plant                                       |
| MISO                |   | Midwest Independent Transmission System  Operator, Inc.      |
| MMBtu               |   | Million British thermal units                                |
| Moody’s        |   | Moody’s Investor Services, Inc.                         |
| Mva                 |   | Megavolt-ampere                                              |
| 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 1935          |   | Public Utility Holding Company Act of 1935                   |
| PUHCA 2005          |   | Public Utility Holding Company Act of 2005                   |
| ROE                 |   | Return on Equity                                             |
| RTO                 |   | Regional Transmission Organization                           |
| RTOR                |   | Regional Through and Out Rates                               |
| 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                                               |
| SPP                 |   | Southwest Power Pool, Inc.                                   |
| TEMT                |   | Transmission and Energy Markets Tariff                       |
| Tennessee Gas       |   | Tennessee Gas Pipeline Company                               |
| Texas Gas           |   | Texas Gas Transmission LLC                                   |
| Trimble County      |   | LG&E’s Trimble County Unit 1                        |
| TVA                 |   | Tennessee Valley Authority                                   |
| 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                             |

 

108

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Kentucky Utilities Company

Statements of Income

(Millions of $)

 
| ** **                                          | ** ** | **Years Ended December 31** | ** ** |
|-----------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                          | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
|                                                |       |                                       |       |   |   |   |   |
| OPERATING REVENUES:                                 |       |                                       |       |   |   |   |   |
| Total operating revenues (Note 12)                  |       | $                                          | 1,206.6    |   | $ | 995.4 |   | $ | 891.8 |   |
|                                                |       |                                       |       |   |   |   |   |
| OPERATING EXPENSES:                                 |       |                                       |       |   |   |   |   |
| Fuel for electric generation                        |       | 384.1                                      |       | 292.5 |   | 266.4 |   |
| Power purchased (Notes 10 and 12)                   |       | 218.9                                      |       | 144.2 |   | 140.1 |   |
| Other operation and maintenance expenses            |       | 286.8                                      |       | 222.1 |   | 221.3 |   |
| Depreciation and amortization (Note 1)              |       | 114.7                                      |       | 108.7 |   | 101.8 |   |
| Total operating expenses                            |       | 1,004.5                                    |       | 767.5 |   | 729.6 |   |
|                                                |       |                                       |       |   |   |   |   |
| Net operating income                                |       | 202.1                                      |       | 227.9 |   | 162.2 |   |
|                                                |       |                                       |       |   |   |   |   |
| Other (income) – net                           |       | (5.0                                       | )          | (7.5 | ) | (4.5 | ) |
| Interest expense (Notes 8 and 9)                    |       | 15.0                                       |       | 11.3 |   | 19.3 |   |
| Interest expense to affiliated companies  (Note 12) |       | 16.0                                       |       | 14.2 |   | 5.9 |   |
|                                                |       |                                       |       |   |   |   |   |
| Net income before income taxes                      |       | 176.1                                      |       | 209.9 |   | 141.5 |   |
|                                                |       |                                       |       |   |   |   |   |
| Federal and state income taxes (Note 7)             |       | 64.0                                       |       | 76.4 |   | 50.1 |   |
|                                                |       |                                       |       |   |   |   |   |
| Net income                                          |       | $                                          | 112.1      |   | $ | 133.5 |   | $ | 91.4 |   |

 

The accompanying notes are an integral part of these financialstatements.

 

Statements of Retained Earnings

(Millions of $)

 
| ** **                                           | ** ** | **Years Ended December 31** | ** ** |
|------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                           | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
|                                                 |       |                                       |       |   |   |   |   |
| Balance January 1                                    |       | $                                          | 659.4      |   | $ | 591.2 |   | $ | 502.0 |   |
| Add net income                                       |       | 112.1                                      |       | 133.5 |   | 91.4 |   |
|                                                 |       | 771.5                                      |       | 724.7 |   | 593.4 |   |
|                                                 |       |                                       |       |   |   |   |   |
| Deduct: Cash dividends declared on stock  and other: |       |                                       |       |   |   |   |   |
| 4.75% cumulative preferred                           |       | 0.8                                        |       | 1.0 |   | 0.9 |   |
| 6.53% cumulative preferred                           |       | 1.0                                        |       | 1.3 |   | 1.3 |   |
| Common                                               |       | 50.0                                       |       | 63.0 |   | — |   |
| Call premium and expenses                            |       | 1.1                                        |       | — |   | — |   |
|                                                 |       | 52.9                                       |       | 65.3 |   | 2.2 |   |
|                                                 |       |                                       |       |   |   |   |   |
| Balance December 31                                  |       | $                                          | 718.6      |   | $ | 659.4 |   | $ | 591.2 |   |

 

The accompanying notes are an integral part of these financialstatements.

 

109

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Kentucky Utilities Company

Statements of Comprehensive Income

(Millions of $)

 
| ** **                                                                                                                                                                | ** ** | **Years Ended December 31** | ** ** |
|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                                                                                                                | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
|                                                                                                                                                                      |       |                                       |       |   |   |   |   |
| Net income                                                                                                                                                                |       | $                                          | 112.1      |   | $ | 133.5 |   | $ | 91.4 |   |
|                                                                                                                                                                      |       |                                       |       |   |   |   |   |
| Gain (loss) on derivative instruments and  hedging activities, net of tax benefit (expense) of $0, $(0.1) and $0.1 for  2005, 2004 and 2003, respectively (Notes 1 and 4) |       | —                                     |       | 0.2 |   | (0.2 | ) |
|                                                                                                                                                                      |       |                                       |       |   |   |   |   |
| Additional minimum pension liability  adjustment, net of tax benefit (expense) of $3.5, $5.0 and $(3.1) for 2005,  2004 and 2003, respectively (Note 6)                   |       | (6.0                                       | )          | (7.4 | ) | 4.6 |   |
|                                                                                                                                                                      |       |                                       |       |   |   |   |   |
| Other comprehensive income (loss), net of  tax (Note 13)                                                                                                                  |       | (6.0                                       | )          | (7.2 | ) | 4.4 |   |
|                                                                                                                                                                      |       |                                       |       |   |   |   |   |
| Comprehensive income                                                                                                                                                      |       | $                                          | 106.1      |   | $ | 126.3 |   | $ | 95.8 |   |

 

The accompanying notes are an integral part of these financialstatements.

 

110

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Kentucky Utilities Company

Balance Sheets

(Millions of $)

 
| ** **                                                                                    | ** ** | **December 31** | ** ** |
|-----------------------------------------------------------------------------------------------|------------|----------------------|------------|
| ** **                                                                                    | ** ** | **2005**             | ** ** | **2004** | ** ** |
|                                                                                          |       |                 |       |   |   |
| ASSETS:                                                                                       |       |                 |       |   |   |
| Current assets:                                                                               |       |                 |       |   |   |
| Cash and cash equivalents (Note 1)                                                            |       | $                    | 6.7        |   | $ | 4.6 |   |
| Restricted cash (Note 1)                                                                      |       | 21.6                 |       | — |   |
| Accounts receivable - less reserve of $1.5  million in 2005 and $0.6 million in 2004 (Note 4) |       | 167.0                |       | 112.6 |   |
| Materials and supplies (Note 1):                                                              |       |                 |       |   |   |
| Fuel (predominantly coal)                                                                     |       | 55.6                 |       | 52.2 |   |
| Other materials and supplies                                                                  |       | 32.3                 |       | 31.7 |   |
| Prepayments and other current assets                                                          |       | 5.0                  |       | 6.2 |   |
| Total current assets                                                                          |       | 288.2                |       | 207.3 |   |
|                                                                                          |       |                 |       |   |   |
| Other property and investments - less  reserve of $0.1 million in 2005 and 2004 (Note 1)      |       | 22.8                 |       | 20.5 |   |
|                                                                                          |       |                 |       |   |   |
| Utility plant, at original cost (Note 1)                                                      |       | 3,649.9              |       | 3,571.1 |   |
|                                                                                          |       |                 |       |   |   |
| Less: reserve for depreciation                                                                |       | 1,508.2              |       | 1,415.0 |   |
| Total utility plant, net                                                                      |       | 2,141.7              |       | 2,156.1 |   |
|                                                                                          |       |                 |       |   |   |
| Construction work in progress                                                                 |       | 197.0                |       | 141.0 |   |
| Total utility plant and construction work  in progress                                        |       | 2,338.7              |       | 2,297.1 |   |
|                                                                                          |       |                 |       |   |   |
| Deferred debits and other assets:                                                             |       |                 |       |   |   |
| Unamortized debt expense (Note 1)                                                             |       | 5.0                  |       | 4.7 |   |
| Regulatory assets (Note 3)                                                                    |       | 58.2                 |       | 61.4 |   |
| Long-term derivative asset                                                                    |       | 0.8                  |       | 6.1 |   |
| Cash surrender value of key man life  insurance (Note 8)                                      |       | 32.5                 |       | 3.6 |   |
| Other assets                                                                                  |       | 10.1                 |       | 9.7 |   |
| Total deferred debits and other assets                                                        |       | 106.6                |       | 85.5 |   |
|                                                                                          |       |                 |       |   |   |
| Total Assets                                                                                  |       | $                    | 2,756.3    |   | $ | 2,610.4 |   |

 

The accompanying notes are an integral part of these financialstatements.

 

111

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Kentucky Utilities Company

Balance Sheets (continued)

(Millions of $)

 
| ** **                                                                                     | ** ** | **December 31** | ** ** |
|------------------------------------------------------------------------------------------------|------------|----------------------|------------|
| ** **                                                                                     | ** ** | **2005**             | ** ** | **2004** | ** ** |
|                                                                                           |       |                 |       |   |   |
| LIABILITIES AND EQUITY:                                                                        |       |                 |       |   |   |
| Current liabilities:                                                                           |       |                 |       |   |   |
| Current portion of long-term debt:                                                             |       |                 |       |   |   |
| Current portion of long-term bonds (Note 8)                                                    |       | $                    | 123.1      |   | $ | 87.1 |   |
| Current portion of long-term notes to  affiliated company                                      |       | —               |       | 75.0 |   |
| Total current portion of long-term debt                                                        |       | 123.1                |       | 162.1 |   |
|                                                                                           |       |                 |       |   |   |
| Notes payable to affiliated company (Notes  9 and 12)                                          |       | 69.7                 |       | 34.8 |   |
| Accounts payable                                                                               |       | 88.6                 |       | 77.9 |   |
| Accounts payable to affiliated companies  (Note 12)                                            |       | 52.6                 |       | 32.8 |   |
| Accrued income taxes                                                                           |       | 12.9                 |       | 5.9 |   |
| Customer deposits                                                                              |       | 17.3                 |       | 15.0 |   |
| Other current liabilities                                                                      |       | 18.5                 |       | 15.4 |   |
| Total current liabilities                                                                      |       | 382.7                |       | 343.9 |   |
|                                                                                           |       |                 |       |   |   |
| Long-term debt:                                                                                |       |                 |       |   |   |
| Long-term bonds (Note 8)                                                                       |       | 240.5                |       | 306.1 |   |
| Long-term notes to affiliated company (Note  8)                                                |       | 383.0                |       | 258.0 |   |
| Total long-term debt                                                                           |       | 623.5                |       | 564.1 |   |
|                                                                                           |       |                 |       |   |   |
| Deferred credits and other liabilities:                                                        |       |                 |       |   |   |
| Accumulated deferred income taxes (Note 7)                                                     |       | 273.8                |       | 282.6 |   |
| Investment tax credit, in process of  amortization                                             |       | 2.1                  |       | 3.8 |   |
| Accumulated provision for pensions and  related benefits (Note 6)                              |       | 91.7                 |       | 77.9 |   |
| Asset retirement obligations                                                                   |       | 26.8                 |       | 21.0 |   |
| Regulatory liabilities (Note 3):                                                               |       |                 |       |   |   |
| Accumulated cost of removal of utility  plant                                                  |       | 280.9                |       | 266.8 |   |
| Regulatory liability deferred income taxes                                                     |       | 23.0                 |       | 19.3 |   |
| Other regulatory liabilities                                                                   |       | 11.3                 |       | 5.4 |   |
| Other liabilities                                                                              |       | 18.4                 |       | 17.0 |   |
| Total deferred credits and other  liabilities                                                  |       | 728.0                |       | 693.8 |   |
|                                                                                           |       |                 |       |   |   |
| Commitments and contingencies (Note 10)                                                        |       |                 |       |   |   |
|                                                                                           |       |                 |       |   |   |
| Cumulative preferred stock                                                                     |       | —               |       | 39.7 |   |
|                                                                                           |       |                 |       |   |   |
| COMMON EQUITY:                                                                                 |       |                 |       |   |   |
| Common stock, without par value - Authorized  80,000,000 shares, outstanding 37,817,878 shares |       | 307.8                |       | 307.8 |   |
| Additional paid-in-capital                                                                     |       | 15.0                 |       | 15.0 |   |
| Accumulated other comprehensive income  (Note 13)                                              |       | (19.3                | )          | (13.3 | ) |
| Retained earnings                                                                              |       | 704.2                |       | 647.3 |   |
| Undistributed subsidiary earnings                                                              |       | 14.4                 |       | 12.1 |   |
| Total retained earnings                                                                        |       | 718.6                |       | 659.4 |   |
| Total common equity                                                                            |       | 1,022.1              |       | 968.9 |   |
|                                                                                           |       |                 |       |   |   |
| Total Liabilities and Equity                                                                   |       | $                    | 2,756.3    |   | $ | 2,610.4 |   |

 

The accompanying notes are an integral part of these financialstatements.

 

112

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KentuckyUtilities Company

Statements of Cash Flows

(Millions of $)

 
| ** **                                                  | ** ** | **Years Ended December 31** | ** ** |
|-------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                  | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| CASH FLOWS FROM OPERATING ACTIVITIES:                       |       |                                       |       |   |   |   |   |
| Net income                                                  |       | $                                          | 112.1      |   | $ | 133.5 |   | $ | 91.4 |   |
| Items not requiring cash currently:                         |       |                                       |       |   |   |   |   |
| Depreciation and amortization                               |       | 114.7                                      |       | 108.7 |   | 101.8 |   |
| Deferred income taxes - net                                 |       | (1.6                                       | )          | 16.6 |   | 15.3 |   |
| Investment tax credit - net                                 |       | (1.7                                       | )          | (2.1 | ) | (2.6 | ) |
| VDT amortization                                            |       | 11.8                                       |       | 11.7 |   | 12.0 |   |
| Deferred storm costs                                        |       | —                                     |       | (3.6 | ) | — |   |
| Other                                                       |       | 0.1                                        |       | (4.2 | ) | 16.1 |   |
| Change in certain current assets and  liabilities:          |       |                                       |       |   |   |   |   |
| Accounts receivable                                         |       | (54.4                                      | )          | (63.3 | ) | 0.3 |   |
| Materials and supplies                                      |       | (4.0                                       | )          | (3.1 | ) | (8.3 | ) |
| Accounts payable                                            |       | 30.5                                       |       | 14.3 |   | 1.0 |   |
| Accrued income taxes                                        |       | 7.0                                        |       | (1.2 | ) | 3.9 |   |
| Prepayments and other                                       |       | 6.6                                        |       | 1.3 |   | 5.3 |   |
| Pension funding                                             |       | (7.5                                       | )          | (43.4 | ) | (10.2 | ) |
| Earnings sharing mechanism receivable                       |       | 3.1                                        |       | 9.3 |   | 1.1 |   |
| Environmental cost recovery mechanism  refundable           |       | —                                     |       | (8.0 | ) | 6.2 |   |
| Litigation settlement                                       |       | —                                     |       | 11.4 |   | — |   |
| Other                                                       |       | 4.0                                        |       | 8.0 |   | 0.1 |   |
| Net cash provided by operating activities                   |       | 220.7                                      |       | 185.9 |   | 233.4 |   |
|                                                        |       |                                       |       |   |   |   |   |
| CASH FLOWS FROM INVESTING ACTIVITIES:                       |       |                                       |       |   |   |   |   |
| Construction expenditures                                   |       | (140.0                                     | )          | (157.6 | ) | (341.8 | ) |
| Change in restricted cash                                   |       | (21.6                                      | )          | — |   | — |   |
| Other                                                       |       | —                                     |       | — |   | 0.1 |   |
| Net cash used for investing activities                      |       | (161.6                                     | )          | (157.6 | ) | (341.7 | ) |
|                                                        |       |                                       |       |   |   |   |   |
| CASH FLOWS FROM FINANCING ACTIVITIES:                       |       |                                       |       |   |   |   |   |
| Long-term borrowings from affiliated  company               |       | 125.0                                      |       | 50.0 |   | 283.0 |   |
| Short-term borrowings from affiliated  company              |       | 716.0                                      |       | 497.8 |   | 655.2 |   |
| Repayment of short-term borrowings from  affiliated company |       | (681.1                                     | )          | (506.2 | ) | (731.5 | ) |
| Retirement of first mortgage bonds                          |       | (50.0                                      | )          | — |   | (95.0 | ) |
| Repayment of long-term borrowings from  affiliated company  |       | (75.0                                      | )          | — |   | — |   |
| Issuance of pollution control bonds                         |       | 26.5                                       |       | 50.0 |   | — |   |
| Retirement of pollution control bonds                       |       | —                                     |       | (54.8 | ) | — |   |
| Retirement of preferred stock (Note 8)                      |       | (40.8                                      | )          | — |   | — |   |
| Repayment of life insurance loans (Note 8)                  |       | (26.7                                      | )          | — |   | — |   |
| Payment of dividends                                        |       | (51.8                                      | )          | (65.3 | ) | (2.3 | ) |
| Other                                                       |       | 0.9                                        |       | (0.1 | ) | (1.6 | ) |
| Net cash (used for) provided by financing  activities       |       | (57.0                                      | )          | (28.6 | ) | 107.8 |   |
|                                                        |       |                                       |       |   |   |   |   |
| Change in cash and cash equivalents                         |       | 2.1                                        |       | (0.3 | ) | (0.5 | ) |
| Cash and cash equivalents at beginning of  year             |       | 4.6                                        |       | 4.9 |   | 5.4 |   |
|                                                        |       |                                       |       |   |   |   |   |
| Cash and cash equivalents at end of year                    |       | $                                          | 6.7        |   | $ | 4.6 |   | $ | 4.9 |   |
|                                                        |       |                                       |       |   |   |   |   |
| Supplemental disclosures of cash flow  information:         |       |                                       |       |   |   |   |   |
| Cash paid during the year for:                              |       |                                       |       |   |   |   |   |
| Income taxes                                                |       | $                                          | 59.3       |   | $ | 58.2 |   | $ | 37.2 |   |
| Interest on borrowed money                                  |       | 11.7                                       |       | 15.6 |   | 20.2 |   |
| Interest to affiliated companies on  borrowed money         |       | 14.6                                       |       | 13.2 |   | 3.5 |   |

 

The accompanying notes are an integral part of these financialstatements.

 

113

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Kentucky Utilities Company

Statements of Capitalization

(Millions of $)

 
| ** **                               | ** ** | **December 31** | ** ** |
|------------------------------------------|------------|----------------------|------------|
| ** **                               | ** ** | **2005**             | ** ** | **2004** | ** ** |
|                                     |       |                 |       |   |   |
| LONG-TERM DEBT (Note 8):                 |       |                 |       |   |   |
| First mortgage bonds:                    |       |                 |       |   |   |
| S due January 15, 2006, 5.99%            |       | $                    | 36.0       |   | $ | 36.0 |   |
| P due May 15, 2007, 7.92%                |       | 53.0                 |       | 53.0 |   |
| R due June 1, 2025, 7.55%                |       | —               |       | 50.0 |   |
| Pollution control series:                |       |                 |       |   |   |
| 10, due November 1, 2024, variable %     |       | 54.0                 |       | 54.0 |   |
| 11, due May 1, 2023, variable %          |       | 12.9                 |       | 12.9 |   |
| 12, due February 1, 2032, variable %     |       | 20.9                 |       | 20.9 |   |
| 13, due February 1, 2032, variable %     |       | 2.4                  |       | 2.4 |   |
| 14, due February 1, 2032, variable %     |       | 2.4                  |       | 2.4 |   |
| 15, due February 1, 2032, variable %     |       | 7.4                  |       | 7.4 |   |
| 16, due October 1, 2032, variable %      |       | 96.0                 |       | 96.0 |   |
| 17, due October 1, 2034, variable %      |       | 50.0                 |       | 50.0 |   |
| 18, due June 1, 2035, variable %         |       | 13.3                 |       | — |   |
| 19, due June 1, 2035, variable %         |       | 13.3                 |       | — |   |
| Notes payable to Fidelia:                |       |                 |       |   |   |
| Due December 19, 2005, 2.29%, secured    |       | —               |       | 75.0 |   |
| Due November 24, 2010, 4.24%, secured    |       | 33.0                 |       | 33.0 |   |
| Due January 16, 2012, 4.39%, unsecured   |       | 50.0                 |       | 50.0 |   |
| Due April 30, 2013, 4.55%, unsecured     |       | 100.0                |       | 100.0 |   |
| Due August 15, 2013, 5.31%, secured      |       | 75.0                 |       | 75.0 |   |
| Due July 8, 2015, 4.735%, unsecured      |       | 50.0                 |       | — |   |
| Due December 21, 2015, 5.36%, unsecured  |       | 75.0                 |       | — |   |
| Long-term debt marked to market (Note 4) |       | 2.0                  |       | 8.2 |   |
|                                     |       |                 |       |   |   |
| Total long-term debt outstanding         |       | 746.6                |       | 726.2 |   |
|                                     |       |                 |       |   |   |
| Less current portion of long-term debt   |       | 123.1                |       | 162.1 |   |
|                                     |       |                 |       |   |   |
| Long-term debt                           |       | 623.5                |       | 564.1 |   |
|                                          |            |                      |            |  |  |  |  |

 

CUMULATIVE PREFERRED STOCK (Note 8):

 
| ** **                                                                                                        | ** ** | **Shares**      | ** ** | **Current**               | ** ** | ** ** | ** ** | ** ** | ** ** |
|-------------------------------------------------------------------------------------------------------------------|------------|-----------------|------------|---------------------------|------------|------------|------------|------------|------------|
| ** **                                                                                                        | ** ** | **Outstanding** | ** ** | **Redemption Price** | ** ** | ** ** | ** ** | ** ** | ** ** |
|                                                                                                              |       |            |       |                      |       |       |       |       |       |
| Without par value, 5,300,000 shares  authorized - 4.75% series, $100 stated value redeemable 30 days notice by KU |       | —          |       | —                    |       | —     |       | 20.0       |       |
| 6.53% series, $100 stated value                                                                                   |       | —          |       | —                    |       | —     |       | 20.0       |       |
| Preferred stock expense                                                                                           |       |            |       |                      |       | —     |       | (0.3       | )          |
|                                                                                                              |       |            |       |                      |       | —     |       | 39.7       |       |

 
| COMMON EQUITY:                                                                                 |   |    |    |   |   |
|------------------------------------------------------------------------------------------------|--------|---------|---------|--------|--------|
| Common stock, without par value - Authorized  80,000,000 shares, outstanding 37,817,878 shares |   | 308.1   |    | 308.1  |   |
| Common stock expense                                                                           |   | (0.3    | )       | (0.3   | )      |
| Additional paid-in-capital                                                                     |   | 15.0    |    | 15.0   |   |
| Accumulated other comprehensive income  (Note 13)                                              |   | (19.3   | )       | (13.3  | )      |
|                                                                                           |   |    |    |   |   |
| Retained earnings                                                                              |   | 704.2   |    | 647.3  |   |
| Undistributed subsidiary earnings                                                              |   | 14.4    |    | 12.1   |   |
| Total retained earnings                                                                        |   | 718.6   |    | 659.4  |   |
| Total common equity                                                                            |   | 1,022.1 |    | 968.9  |   |
| Total capitalization                                                                           |   | $       | 1,645.6 |   | $      | 1,572.7 |   |
|                                                                                                |        |         |         |        |        |  |  |

 

The accompanying notes are an integral part of these financialstatements.

 

114

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Kentucky Utilities Company

Notes to Financial Statements

 

**Note 1 - Summary of Significant Accounting Policies**

 

KU, a subsidiary of E.ON U.S. (formerly LG&E Energy) and anindirect subsidiary of E.ON, is a regulated public utility engaged in thegeneration, transmission, distribution and sale of electric energy. E.ON U.S.is a public utility holding company with wholly owned subsidiaries includingLG&E, KU, Capital Corp., LEM and E.ON U.S. Services. All of KU’s commonstock is held by E.ON U.S. In May 2004, KU dissolved its accounts receivablesecuritization-related subsidiary, KU R. Prior to May 2004, the consolidatedfinancial statements included the accounts of KU and KU R with the eliminationof intercompany accounts and 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. Effective December 1, 2005, LG&E Energy LLC wasrenamed E.ON U.S. LLC.

 

Certain reclassification entries have been made to the previous years’financial statements to conform to the 2005 presentation with no impact on netassets, liabilities and capitalization or previously reported net income andcash flows.

 

During 2005, KU made out-of-period adjustments for estimated over/undercollection of ECR revenues to be billed in subsequent periods. The adjustmentswere related to the reporting periods of May 2003 through December 2004. As aresult, 2005 revenues for KU were reduced $2.9 million and net income wasreduced $1.7 million. KU revenues and net income for 2004 were overstated by$3.2 million and $1.9 million, respectively, and KU revenues and net income for2003 were understated by $0.3 million and $0.2 million, respectively.

 

**Regulatory Accounting.**KU is subject to SFASNo. 71, under which costs that would otherwise be charged to expense aredeferred as regulatory assets based on expected recovery from customers infuture rates. Likewise, credits that would otherwise be reflected as income aredeferred as regulatory liabilities based on expected return to customers infuture rates. KU’s current or expected recovery of deferred costs and expectedreturn of deferred credits is based on specific ratemaking decisions orprecedent for each item as prescribed by the FERC, the Kentucky Commission andthe Virginia Commission. See Note 3, Rates and Regulatory Matters, foradditional detail regarding regulatory assets and liabilities.

 

**Cash and Cash Equivalents.**KU considers alldebt instruments purchased with an original maturity of three months or less tobe cash equivalents.

 

**Restricted Cash.**Proceeds from two bondissuances for environmental equipment (primarily related to the installation ofFGDs) are held in trust pending expenditure for qualifying assets which isexpected to occur during 2006. The amount held in trust at December 31, 2005,was $21.6 million and is classified as restricted cash on KU’s Balance Sheet.

 

**Allowance for Doubtful Accounts.**The allowancefor doubtful accounts is based on the ratio of the amounts charged-off duringthe last twelve months to the retail revenues billed over the same periodmultiplied by the retail revenues billed over the last four months. Accountswith no payment activity are charged-off after four months, although collectionefforts continue thereafter.

 

**Materials and Supplies.**Fueland other materials and supplies inventories are accounted for using theaverage-cost method. Emission allowances are included in inventory at cost andare not currently traded by KU. At December 31, 2005 and 2004, the emissionallowances inventory was approximately $1.5 million and $3.7 million,respectively.

 

115

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**Other Property and Investments.**Other propertyand investments on the balance sheet consists of KU’s investment in EEI,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.

 

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. KU and 11 other electric utilities areparticipating owners of OVEC, located in Piketon, 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%, representingapproximately 55 Mw of generation capacity.

 

As of December 31, 2005 and 2004, KU’s investment in OVEC totaled $0.3million and is accounted for under the cost method of accounting. KU’s maximumexposure to loss as a result of its involvement with OVEC is limited to thevalue of its investment. In the event of the inability of OVEC to fulfill itspower provision requirements, KU would substitute such power supply with eitherowned generation or market purchases and would generally recover associatedincremental costs through regulatory rate mechanisms. See Note 10, Commitmentsand Contingencies, for further discussion of developments regarding KU’sownership 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. Previously, KU was entitledto take 20% of the available capacity of the station under a pricing formulacomparable to the cost of other power generated by KU. Such power equated toapproximately 9% of KU’s net generation system output in 2005. This contractgoverning the purchases from EEI terminated on December 31, 2005. Subsequent toDecember 31, 2005, EEI has sold power under general market-based pricing andterms. KU has not contracted with EEI for power under the new arrangements, butmaintains its 20% ownership in the common stock of EEI. Replacement power forthe EEI capacity has been largely provided by KU generation. See Note 10, Commitments and Contingencies.

 

KU’s investment in EEI is accounted for under the equity method ofaccounting and, as of December 31, 2005 and 2004 totaled $15.6 million and$13.4 million, respectively. KU’s portion of equity in EEI earnings for thelast three years was $2.3 million in 2005, $2.6 million in 2004 and $3.7million in 2003. KU’s direct exposure to loss as a result of its involvementwith EEI is generally limited to the value of its investment.

 

**Utility Plant.**KU’s utility plant is stated atoriginal cost, which includes payroll-related costs such as taxes, fringebenefits, and administrative and general costs. Construction work in progresshas been included in the rate base for determining retail customer rates inKentucky. KU has not recorded a significant 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 completeoperating units are disposed of, appropriate adjustments are made to thereserve for depreciation and gains and losses, if any, are recognized.

 

**Depreciation and Amortization.**Depreciation isprovided on the straight-line method over the estimated service lives of depreciableplant. The amounts provided were approximately 3.2% in 2005, 3.1% in 2004 and3.1% in 2003, of average depreciable plant. Of the amount provided for depreciationat December 31, 2005 and 2004, approximately 0.5% was related to theretirement, removal and disposal costs of long lived assets.

 

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**Unamortized Debt Expense.**Debt expense iscapitalized in deferred debits and amortized over the lives of the related bondissues.

 

**Income Taxes.**Income taxes are accounted forunder SFAS No. 109.  In accordance with this statement, deferred taxassets and liabilities are recognized for the future tax consequencesattributable to differences between the financial statementcarrying amounts of existing assets and liabilities and their respectivetax bases, as measured by enacted tax rates that are expected to be in effectin the periods when the deferred tax assets and liabilities are expected to besettled or realized. Significant judgment is required in determiningthe provision for income taxes, and there are transactions for whichthe ultimate tax outcome is uncertain.  To provide for these uncertaintiesor exposures, an allowance is maintained for tax contingencies based onmanagement’s best estimate of probable loss.  Tax contingencies areanalyzed periodically and adjustments are made when events occur towarrant a change. See Note 7, Income Taxes.

 

**Deferred Income Taxes.**Deferred income taxesare recognized at currently enacted tax rates for all material temporarydifferences between the financial reporting and income tax bases of assets andliabilities.

 

**Investment Tax Credits.**Investment tax creditsresulted from provisions of the tax law that permitted a reduction of KU’s taxliability based on credits for construction expenditures. Deferred investmenttax credits are being amortized to income over the estimated lives of therelated property that gave rise to the credits.

 

**Revenue Recognition.**Revenues are recordedbased on service rendered to customers through month-end. KU accrues anestimate for unbilled revenues from each meter reading date to the end of theaccounting period based on allocating the daily system net deliveries betweenbilled volumes and unbilled volumes. The allocation is based on a daily ratioof the number of meter reading cycles remaining in the month to the totalnumber of meter reading cycles in each month. 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. The unbilled revenueestimates included in accounts receivable were approximately $47.6 million and$47.5 million at December 31, 2005, and 2004, respectively.

 

**Fuel Costs.**The cost of fuel for electricgeneration is charged to expense as used.

 

**Management’s Use of Estimates.**The preparationof financial statements in conformity with generally accepted accountingprinciples requires management to make estimates and assumptions that affectthe reported assets and liabilities and disclosure of contingent items at thedate of the financial statements and the reported amounts of revenues andexpenses during the reporting period. Accrued liabilities, including legal andenvironmental, are recorded when they are probable and estimable. Actualresults could differ from those estimates.

 

**New Accounting Pronouncements.**Thefollowing accounting pronouncement was issued that affected KU in 2005:

 

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FIN 47

 

KU adopted FIN 47, effective December 31, 2005. FIN 47 expands the term“conditional asset retirement obligation” as used in SFAS No. 143, to refer toa legal obligation to perform an asset retirement activity in which the timingand/or method of settlement are conditional on a future event that may or maynot be within the control of the entity. The obligation to perform the assetretirement activity is unconditional even though uncertainty exists about thetiming and/or method of settlement. An entity is required to recognize a liabilityfor the fair value of a conditional asset retirement obligation if the fairvalue of the liability can be reasonably estimated. The fair value of aliability for the conditional asset retirement obligation should be recognizedwhen incurred; generally, upon acquisition, construction or development andthrough the normal operation of the asset.

 

As a result of the implementation of FIN 47, KU recorded additional AROnet assets and liabilities during the fourth quarter of 2005 in the amount of$0.5 million and $4.6 million, respectively. KU also recorded a cumulativeeffect adjustment in the amount of $4.1 million to reflect the accumulateddepreciation and accretion of ARO assets at the transition date less amountspreviously accrued under regulatory depreciation. KU recorded offsettingregulatory assets of $4.1 million, pursuant to regulatory treatment prescribedunder SFAS No. 71 as the costs of removal are allowed under Kentucky Commissionratemaking.

 

Had FIN 47 been in effect at the beginning of the 2004 reportingperiod, KU would have established asset retirement obligations as described inthe following table (in millions):

 
| ** **                         | ** ** | **2005** | ** ** | **2004** | ** ** |
|------------------------------------|------------|----------|------------|----------|------------|
| Provision at beginning of the year |       | $        | 4.3        |     | $          | 4.1 |   |
| Accretion expense                  |       | 0.3      |       | 0.2      |       |
| Provision at end of the year       |       | $        | 4.6        |     | $          | 4.3 |   |

 

# **Note 2 – Company Structure**

# ** **

On July 1,2002, E.ON completed its acquisition of Powergen, including E.ON U.S. (formerlyLG&E Energy), for approximately £5.1 billion ($7.3 billion). As a result ofthe acquisition, E.ON U.S. became a wholly owned subsidiary of E.ON and, as aresult, KU also became an indirect subsidiary of E.ON. KU has continued itsseparate identity and serves customers in Kentucky, Virginia and Tennesseeunder its existing name. The preferred stock and debt securities of KU were notaffected by this transaction and the Company continues to file SEC reports.

 

**Note 3 - Rates and Regulatory Matters**

 

Electric Rate Case

 

In December2003, KU filed an application with the Kentucky Commission requesting anadjustment in KU’s electric rates. KU asked for a general adjustment inelectric rates based on the twelve month test period ended September 30, 2003. Therevenue increase requested was $58.3 million. In June 2004, the Kentucky Commission issuedan order approving an increase in the electric base rates of KU ofapproximately $46.1 million (6.8%). The rate increase took effect on July 1,2004.

 

During2004 and 2005, the AG conducted an investigation of KU, as well as of theKentucky Commission and its staff, requesting information regarding allegedlyimproper communications between KU and the Kentucky Commission, particularlyduring the period covered by the rate case. Concurrently, the AG had filedpleadings with the Kentucky Commission requesting rehearing of the rate case oncomputational components of the increased rates, including income taxes, costof removal and depreciation amounts. In August 2004, the 

 

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KentuckyCommission denied the AG’s rehearing request on the cost of removal anddepreciation issues and granted rehearing on the income tax component. TheKentucky Commission further agreed to hold in abeyance further proceedings inthe rate case, until the AG filed its investigative report regarding theallegations of improper communication.

 

In January2005 and February 2005, the AG filed a motion summarizing its investigativereport as containing evidence of improper communications and record-keepingerrors by KU in its conduct of activities before the Kentucky Commission orother state governmental entities and forwarded such report to the KentuckyCommission under continued confidential treatment to allow it to consider thereport, including its impact, if any, on completing its investigation and anyremaining steps in the rate case. To date, KU has neither seen nor requestedcopies of the report or its contents.

 

In December 2005, theKentucky Commission issued an order noting completion of its inquiry, includingreview of the AG’s investigative report. The order concludes no impropercommunications occurred during the rate proceeding. The order furtherestablished a procedural schedule through the first quarter of 2006 forconsidering the sole issue for which rehearing was granted: state income taxrates used in calculating the granted rate increase. This issue is estimated atless than $1 million annually. Upon resolution of this issue on rehearing, theinitial rate increase order could be subject to judicial appeal.

 

KU believes no improprieties have occurred in its communications withthe Kentucky Commission and has cooperated with the proceedings before the AGand the Kentucky Commission. KU is currently unable to determine the ultimateimpact, if any, of, or any possible future actions of the AG or the KentuckyCommission arising out of, the AG’s report and investigation, including whetherthere will be further actions to appeal, review or otherwise challenge thegranted increase in rates.

 

Regulatory Assets and Liabilities

 

The following regulatory assets and liabilities were included in KU’sBalance Sheets as of December 31:

 
| **(in millions)**                        | ** ** | **2005**   | ** ** | **2004**   | ** ** |
|-----------------------------------------------|------------|------------|------------|------------|------------|
| ** **                                    | ** ** | ** ** | ** ** | ** ** | ** ** |
| VDT costs                                     |       | $          | 2.9        |       | $          | 14.7 |   |
| Unamortized loss on bonds                     |       | 11.0       |       | 11.4       |       |
| ARO                                           |       | 20.0       |       | 12.8       |       |
| Merger surcredit                              |       | 2.7        |       | 3.7        |       |
| ESM                                           |       | —     |       | 3.1        |       |
| FAC                                           |       | 12.2       |       | 9.4        |       |
| ECR                                           |       | 4.2        |       | —     |       |
| Deferred storm costs                          |       | 2.8        |       | 3.6        |       |
| Other                                         |       | 2.4        |       | 2.7        |       |
| Total regulatory assets                       |       | $          | 58.2       |       | $          | 61.4 |   |
|                                          |       |       |       |       |       |
| Accumulated cost of removal of utility  plant |       | $          | 280.9      |       | $          | 266.8 |   |
| Deferred income taxes - net                   |       | 23.0       |       | 19.3       |       |
| ECR                                           |       | 6.5        |       | 1.2        |       |
| DSM                                           |       | 2.1        |       | 1.6        |       |
| Other                                         |       | 2.7        |       | 2.6        |       |
| Total regulatory liabilities                  |       | $          | 315.2      |       | $          | 291.5 |   |

 

KU currently earns a return on all regulatory assets except for DSM andFAC, both of which are separate recovery mechanisms with recovery within twelvemonths. Additionally, no current return is earned on the ARO regulatory asset. Thisregulatory asset will be offset against the associated regulatory liability,ARO asset, 

 

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and ARO liability at the time the underlying asset is retired. See Note1, Summary of Significant Accounting Policies.

 

**VDT.**During the first quarter of 2001, KUrecorded a $64.0 million charge for a workforce reduction program. Primarycomponents of the charge were separation benefits, enhanced early retirementbenefits and healthcare benefits. The result of this workforce reduction wasthe elimination of approximately 300 positions, accomplished primarily througha voluntary enhanced severance program.

 

In December 2001, the Kentucky Commission issued an order approving asettlement agreement allowing KU to set up a regulatory asset of $54.0 millionfor the workforce reduction costs and begin amortizing these costs over afive-year period starting in April 2001. Some employees rescinded theirparticipation in the voluntary enhanced severance program and, along with thenon-recurring charge of $6.9 million for FERC and Virginia jurisdictions, whichthereby decreased the original charge to the regulatory asset from $64.0million to $54.0 million. The order reduced revenues by approximately $11.0million through a surcredit on bills to ratepayers over the same five-yearperiod. The surcredit represents savings, net of the amortization of the costs,stipulated by KU and shared 40% with ratepayers, with KU retaining 60% of thenet savings.

 

The five-year VDT amortization period is scheduled to expire in March2006. As part of the settlement agreements in the rate case, KU was required tofile, and did file on September 30, 2005, with the Kentucky Commission a plan forthe future ratemaking treatment of the VDT surcredit and costs. The surcreditwill remain in effect until the Commission enters an order on the futuredisposition of VDT-related issues.

 

On February 27, 2006, the AG, KIUC, LG&E and KU reached a settlementagreement on the future ratemaking treatment of the VDT surcredits and costsand subsequently submitted a joint motion to the Kentucky Commission to approvethe unanimous settlement agreement. Under the terms of the settlementagreement, the VDT surcredit will continue at the current level until such timeas KU files for a change in electric base rates. The Kentucky Commission held apublic hearing in the proceeding on March 21, 2006 and issued an orderthereafter approving the settlement agreement.

 

**Unamortized Loss on Bonds.**The****costs of early extinguishment of debt, including****call premiums, legal****and otherexpenses, and any unamortized balance of debt expense are amortized over thelife of either replacement debt (in the case of re-financing) or the originallife of the extinguished debt.

 

**ARO.**A summary of KU’s net ARO assets,regulatory assets, liabilities and cost of removal established under FIN 47 andSFAS No. 143 follows:

 
| **(in millions)**       | ** ** | **ARO Net  Assets** | ** ** | **ARO  Liabilities** | ** ** | **Regulatory  Assets** | ** ** | **Regulatory  Liabilities** | ** ** | **Accumulated  Cost of Removal** | ** ** | **Cost of Removal  Depreciation** | ** ** |
|------------------------------|------------|--------------------------|------------|----------------------|------------|------------------------|------------|-----------------------------|------------|--------------------------------------------|------------|---------------------------------------------|------------|
| As of December 31, 2003      |       | $                        | 6.9        |                 | $          | (19.7                  | )          | $                           | 11.3       |                                       | $          | (1.2                                        | )          | $ | 2.4 |   | $ | 0.3 |   |
| ARO accretion                |       | —                   |       | (1.3                 | )          | 1.3                    |       | —                      |       | —                                     |       | —                                      |       |
| ARO depreciation             |       | (0.2                     | )          | —               |       | 0.2                    |       | —                      |       | —                                     |       | —                                      |       |
| Removal cost incurred        |       | —                   |       | —               |       | —                 |       | —                      |       | —                                     |       | —                                      |       |
| Cost of removal depreciation |       | —                   |       | —               |       | —                 |       | (0.2                        | )          | —                                     |       | 0.2                                         |       |
| As of December 31, 2004      |       | 6.7                      |       | (21.0                | )          | 12.8                   |       | (1.4                        | )          | 2.4                                        |       | 0.5                                         |       |
| FIN 47 net asset additions   |       | 0.5                      |       | (4.6                 | )          | 4.1                    |       | —                      |       | —                                     |       | —                                      |       |
| ARO accretion                |       | —                   |       | (1.4                 | )          | 1.4                    |       | —                      |       | —                                     |       | —                                      |       |
| ARO depreciation             |       | (1.7                     | )          | —               |       | 1.7                    |       | —                      |       | —                                     |       | —                                      |       |
| Removal cost incurred        |       | —                   |       | 0.2                  |       | —                 |       | —                      |       | —                                     |       | —                                      |       |
| Cost of removal depreciation |       | —                   |       | —               |       | —                 |       | (0.3                        | )          | —                                     |       | 0.3                                         |       |
| As of December 31, 2005      |       | $                        | 5.5        |                 | $          | (26.8                  | )          | $                           | 20.0       |                                       | $          | (1.7                                        | )          | $ | 2.4 |   | $ | 0.8 |   |

 

Pursuant to regulatory treatment prescribed under SFAS No. 71, anoffsetting regulatory credit was recorded in 

 

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Depreciation and amortization in the income statement of $3.1 millionin 2005 and $1.5 million in 2004 for the ARO accretion and depreciationexpense. KU AROs are primarily related to the final retirement of assetsassociated with generating units. For assets associated with AROs, the removalcost accrued through depreciation under regulatory accounting is established asa regulatory asset or liability pursuant to regulatory treatment prescribedunder SFAS No. 71. For the years ended December 31, 2005 and 2004, KUrecorded $0.3 million and $0.2 million, respectively, in depreciation expenserelated to the cost of removal of ARO related assets. An offsetting regulatoryliability was established pursuant to regulatory treatment prescribed underSFAS 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 assetretirement obligations are recorded for transmission and distribution assets.

 

**Merger Surcredit**. As part of the LG&EEnergy merger with KU Energy in 1998, KU estimated non-fuel savings over aten-year period following the merger. Costs to achieve these savings weredeferred and amortized over a five-year period pursuant to regulatory orders.In approving the merger, the Kentucky Commission adopted KU’s proposal toreduce 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 provides that 50% of the net non-fuel costsavings estimated to be achieved from the merger be provided to ratepayersthrough a monthly bill credit, and 50% be retained by KU and LG&E, over afive-year period. The surcredit was allocated 53% to KU and 47% to LG&E. Inthat same order, the Commission required LG&E and KU, after the end of thefive-year period, to present a plan for sharing with ratepayers thethen-projected non-fuel savings associated with the merger. The Companiessubmitted this filing in January 2003, proposing to continue to share withratepayers, on a 50%/50% basis, the estimated fifth-year gross level ofnon-fuel savings associated with the merger. In October 2003, the KentuckyCommission issued an order approving a settlement agreement reached with theparties in the case. KU’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.**Prior to 2004, KU’s Kentucky retailelectric rates were subject to an ESM. The ESM, initially in place for threeyears beginning in 2000, set an upper (12.5%) and lower (10.5%) limit for rateof return on equity. If earnings were above the upper limit, the excessearnings 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. By order of the Kentucky Commission, ratechanges prompted by the ESM filing went into effect in April of each year subjectto a balancing adjustment in successive periods. There is no ESM for Virginiaretail electric rates.

 

In November2002, KU filed a revised ESM tariff which proposed continuance of the existingESM through December 2005. In addition, the Kentucky Commission initiated a focused management audit to review the ESMplan and reassess its reasonableness. KU filed its final 2003 ESMcalculations with the Kentucky Commission on March 1, 2004, and applied forrecovery of $16.2 million. Based upon estimates, KU previously accrued $9.3million for the 2003 ESM as of December 31, 2003. In June 2004, the KentuckyCommission issued an order largely accepting proposed settlement agreements byKU and all intervenors regarding the ESM. Under the ESM settlements, KU continuedto collect approximately $16.2 million of previously requested 2003 ESM revenueamounts through March 2005. As part of the settlement, the parties agreed to atermination of the ESM mechanism relating to all periods after 2003.

 

**FAC.**KU’sretail electric rates contain an FAC, whereby increases or decreases in thecost of fuel for electric 

 

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generation are reflected in the rates chargedto 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. A final report was issued in February2004. The report’s recommendations related to documentation and processimprovements. Management Audit Action Plans were agreed upon by KU and theKentucky Commission Staff in the second quarter of 2004. KU filed its firstAudit Progress Report with the Kentucky Commission Staff in November 2004. Asecond Audit Progress Report was filed in May 2005. The third Audit ProgressReport was filed in December 2005. In January 2006, the Kentucky Commissionstaff informed KU and LG&E that reporting on all of the originalrecommendations, but one, has been concluded. KU and LG&E are to fileanother Audit Progress Report on the remaining open recommendation on August15, 2006.

 

The KentuckyCommission requires public hearings at six-month intervals to examine past fueladjustments, and at two-year intervals to review past operations of the fuelclause and transfer of the then current fuel adjustment charge or credit to thebase charges. KU also employs an FAC mechanism for Virginia customers that usesan average fuel cost factor based primarily on projected fuel costs. The fuelcost factor may be adjusted annually for over or under collections of fuelcosts from the previous year. No significant issues have been identified as aresult of these reviews.

 

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. A public hearing on the matter was heldon March 17, 2005. An order by the Kentucky Commission was issued in May 2005approving KU’s base fuel component of 18.10 mills/kwh as filed. Revised tariffschedules for KU were filed to reflect the change in the base fuel component.

 

KU employs aLevelized Fuel Factor mechanism for Virginia customers that uses an averagefuel cost factor based primarily on projected fuel costs. The fuel cost factormay be adjusted annually for over- or under- collections of fuel costs from theprevious year. 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. KU implemented the increased fuel cost factor withApril 2005 billings and the Virginia Commission issued its final orderapproving the increase on April 29, 2005.

 

On February15, 2006, KU filed with the Virginia Commission an application seeking approvalof an increase in its fuel cost factor to reflect higher fuel costs incurredduring 2005 and anticipated to be incurred in 2006.

 

On July 7, 2005, the Kentucky Commissioninitiated the six-month review of the KU fuel adjustment clause for the periodof November 2004 through April 2005. During November 2005, the KentuckyCommission approved the charges and credits billed and the fuel procurementpractices of KU.

 

On December 27, 2005, the KentuckyCommission initiated the six-month review of the KU fuel adjustmentclause for the period of May 2005 through October 2005. Initial discovery wascompleted on January 17, 2006, and a hearing was held March 16, 2006. KUanticipates Kentucky Commission approvalof the charges and credits billed and the fuel procurement practices of KUduring the second quarter of 2006.

 

# **DSM.**KU’srates contain a DSM provision. The provision includes a rate mechanism thatprovides for concurrent recovery of DSM costs and provides an incentive forimplementing DSM programs. The provision allows KU to recover revenues fromlost sales associated with the DSM programs based on program plan 

 

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# **engineeringestimates and post-implementation evaluation.**

# ** **

**Deferred Storm Costs.**Based on an order fromthe Kentucky Commission in September 2004, KU reclassified from maintenanceexpense to a regulatory asset, $4.0 million related to costs not reimbursedfrom the 2003 ice storm. These costs will be amortized through June 2009. KUearns a return of these amortized costs, which are included in KU’sjurisdictional operating expenses.

 

**Accumulated Cost of Removal of Utility Plant.**Asof December 31, 2005 and 2004, KU has segregated the cost of removal, embeddedin accumulated depreciation, of $280.9 million and $266.8 million,respectively, in accordance with FERC Order No. 631*.*For reporting purposes in the balance sheets, KU haspresented this cost of removal as a regulatory liability pursuant to SFAS No.71.

 

**Deferred Income Taxes - Net.**Deferred incometaxes represent the future income tax effects of recognizing the regulatoryassets and liabilities in the income statement. Deferred income taxes arerecognized at currently enacted tax rates for all material temporarydifferences between the financial reporting and income tax bases of assets andliabilities.

 

**ECR.**KU’s retail rates contain an ECR surchargewhich recovers costs incurred by KU that are required to comply with the CleanAir Act and other environmental regulations. In March 2003, the Kentucky Commission initiated a series of six-monthand two-year reviews of the operation of KU’s Environmental Surcharge. A finalorder was issued in October 2003, resolving all outstanding issues related toover-recovery from customers and under-recovery of allowed O&M expense. TheCommission found that KU had over-collected a net $6.0 million from customersand ordered the refund to occur through adjustments to the calculation of themonthly surcharge billing factor over the subsequent 12-month period. TheKentucky Commission further ordered KU to roll $17.9 million of environmentalassets into base rates and make corresponding adjustments to the monthlyenvironmental surcharge filings to reflect that portion of environmental ratebase now included in base rates going forward. The rates of return for KU’s1994 and post-1994 plans were reset to 1.24% 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 the elimination of KU’s 1994 Plan for its ECRbilling mechanism, with all remaining costs associated with that plan to beincluded 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 costs associated with new and additionalenvironmental compliance facilities. The estimated capital cost of the additionalfacilities over the next three years is approximately $680.0 million, of whichapproximately $560.0 million is related to the FGDs at Ghent and Brown. Hearingsin these cases occurred in May 2005 and final orders were issued in June 2005,granting approval of the CCN and amendments to KU’s compliance plan.

 

Other Regulatory Matters

 

**MISO.**The MISO is a non-profit independenttransmission system operator that controls approximately 97,000 miles oftransmission lines over 947,000 square miles in 15 northern Midwest states andone Canadian province. The MISO operates the regional power grid and wholesaleelectricity market in an effort to optimize efficiency and safeguardreliability in accordance with federal energy policy.

 

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KU is now involved in proceedings with the Kentucky Commission and theFERC seeking the authority to exit the MISO. A timeline of events regarding theMISO and various proceedings is as follows:

 

•                  September 1998 –The FERC granted conditional approval for the formation of the MISO. KU was afounding member.

 

•                  October 2001 –The FERC ordered that all bundled retail loads and grandfathered wholesaleloads of each member transmission owner be included in the calculation of theMISO “cost adder,” the Schedule 10 charges designed to recover the MISO’s costof operation, including start-up capital (debt) costs. KU and several ownersopposed the FERC order and filed suit with the United States Court of Appeals.

 

•                  February 2002 –The MISO began commercial operations.

 

•                  February 2003 –The FERC reaffirmed its position on the Schedule 10 charges and the order wassubsequently upheld by the U.S. Court of Appeals.

 

•                  July 2003 – TheKentucky Commission opened an investigation into KU’s MISO membership. Testimonywas filed by KU that supported an exit from the MISO, under certain conditions.This proceeding remains open.

 

•                  August 2004 –The MISO filed its FERC-required TEMT. KU and other owners filed opposition tocertain conditions of the TEMT and sought to delay the implementation. Suchopposition was denied by the FERC.

 

•                  December 2004 –KU provided the MISO its required one-year notice of intent to exit the grid.

 

•                  April 2005 – TheMISO implemented its day-ahead and real-time market (MISO Day 2), including acongestion management system.

 

•                  October 2005 –KU filed documents with the FERC seeking authority to exit the MISO. Thisproceeding remains open.

 

•                  November 2005 –KU requested a Kentucky Commission order authorizing the transfer of functionalcontrol of its transmission facilities from the MISO to KU, for the purpose of exitingthe MISO. The request stated that the TVA would have control to the extentnecessary to act as the Company’s Reliability Coordinator and for the SPP toperform its function as the Company’s Independent Transmission Organization.This proceeding remains open.

 

Based on various financial analyses performed internally, in responseto the July 2003 Kentucky Commission investigation into MISO membership, andparticularly in light of the financial impacts following MISO’s implementationof the new day-ahead and real-time markets, KU determined that the costs ofMISO membership, both now and in the future, outweigh the benefits.

 

Should KU be allowed to exit the MISO, an aggregate exit fee of up to$41.0 million (approximately $25.0 million for KU and $16.0 million forLG&E) could be imposed, depending on the timing and circumstances of the actualexit. KU estimates that, over time, such fee could be more than offset bysavings resulting from exit from the MISO. Conversely, should KU be ordered toremain in the MISO, costs are expected to continue to exceed benefits,currently without mechanisms for immediate recovery.

 

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On March 17, 2006, the FERC issued an order conditionally approving therequest of KU and LG&E to exit the MISO. For further discussion, see Note15, Subsequent Events.

 

**Market-Based Rate Authority.**SinceApril 2004, the FERC has initiated proceedings to modify its methods whichassess generation market power and has established more stringent interimmarket screen tests. During 2005, in connection with KU’s and LG&E’stri-annual market-based rate tariff renewals, although disputed by KU andLG&E, the FERC continued to contend that KU and LG&E failed such marketscreens in certain regions. In January 2006, in order to resolve the matter, KUand LG&E submitted proposed tariff schedules to the FERC containing amitigation mechanism with respect to applicable power sales into an adjacentwestern Kentucky control area where a non-utility affiliate company is active. Pricesfor such sales will be capped at a relevant MISO power pool index price. ShouldKU and LG&E exit the MISO, they could additionally be deemed to have marketpower in their own joint control area, potentially requiring a similarmitigation mechanism for power sales into such region. KU and LG&E cannotpredict the ultimate impact of the current or potential mitigation mechanismson their future wholesale power revenues.

 

**IRP.**In April 2005, KU and LG&E filed their 2005Joint IRP with the Kentucky Commission. The IRP provides historical andprojected demand, resource and financial data, and other operating performanceand system information. The AG and the KIUC were granted intervention in theIRP proceeding. The Kentucky Commission issued its staff report onFebruary 15, 2006, with no substantive issues noted and closed the case byOrder dated February 24, 2006.

 

**Kentucky Commission Administrative Case forSystem Adequacy.**In June 2001, Kentucky’s Governorissued Executive Order 2001-771, which directed the Kentucky Commission toreview and study issues relating to the need for and development of newelectric generating capacity in Kentucky. In response to that Executive Order,in July 2001, the Kentucky Commission opened Administrative Case No. 387 toreview the adequacy of Kentucky’s generation capacity and transmission system. Specifically,the items reviewed were the appropriate level of reliance on purchased power,the appropriate reserve margins to meet existing and future electric demand,the impact of spikes in natural gas prices on electric utility planningstrategies, and the adequacy of Kentucky’s electric transmission facilities. InDecember 2001, the Kentucky Commission issued an order in which it noted thatKU is responsibly addressing the long-term supply needs of native loadcustomers and that current reserve margins are appropriate. However, due to therapid pace of change in the industry, the order also requires KU to provide anannual assessment of supply resources, future demand, reserve margin and theneed 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 the 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.

 

**EPAct 2005.**The EPAct 2005 was enacted onAugust 8, 2005. Among other matters, this comprehensive legislation containsprovisions mandating improved electric reliability standards and performance;providing economic and other incentives relating to transmission, pollutioncontrol and renewable generation assets; increasing funding for clean coal generationincentives; repealing PUHCA 1935; enacting PUHCA 2005 and expanding FERCjurisdiction over public utility holding companies and related matters via theFPA and PUHCA 2005.

 

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The FERC wasdirected by the EPAct 2005 to adopt rules to address many areas previouslyregulated by the other agencies under other statutes, including PUHCA 1935. TheFERC is in various stages of rulemaking on these issues and KU is monitoringthese rulemaking activities and actively participating in these and otherrulemaking proceedings. KU is still evaluating the potential impacts of theEPAct 2005 and the associated rulemakings and cannot predict what impact theEPAct 2005, and any such rulemakings, will have on its operations or financialposition.

 

**KentuckyCommission 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 is 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 establishedAdministrative Case No. 2005-00090 to collect information from all jurisdictionalutilities in Kentucky, including KU, pertaining to Kentucky electricgeneration, transmission and distribution systems. KU responded to the KentuckyCommission’s first set of data requests at the end of March 2005 and to asecond set of data requests in May 2005. The Commission held a TechnicalConference on June 14, 2005, in which all parties participated in a paneldiscussion. A final report was provided on August 22, 2005 from the KentuckyCommission to the Governor. The Kentucky Commission issued an order and closedthis proceeding on September 15, 2005. Some of the key findings from the reportare:

 

•                  Kentucky’selectric utilities currently have adequate infrastructure as well as adequateplanning to serve the needs of customers through 2025;

•                  Kentucky willneed 7,000 megawatts of additional generating capacity by 2025;

•                  Kentucky’selectric transmission is reliable but intrastate power transfers are limited;

•                  Additionalincentives to use renewable energy and educate the public on the benefits ofrenewables are needed;

•                  Financialincentives should be available for coal purification and other clean airtechnologies;

•                  A cautiousapproach should be taken toward deregulation; and

•                  Kentucky must beinvolved in federal decisions that impact its status as a low cost energyprovider.

 

**Lock 7.** On September 27, 2005, KU filed anapplication with the FERC seeking authority to transfer the operating licensefor the Lock 7 Hydroelectric Station, a 2.04 Mw facility, to the Lock 7 HydroPartners, LLC, an unaffiliated third party, for less than $1 million. OnSeptember 28, 2005, KU filed an application with the Kentucky Commissionseeking: 1) a determination that Kentucky Commission approval is not requiredfor the transfer of the Lock 7 Hydroelectric Station or 2) Kentucky Commissionapproval, pursuant to a Kentucky Commission order in case No. 2005-00405, tosell any real property associated with the Lock 7 Hydroelectric Station to Lock7 Hydro Partners, LLC. Approval from the FERC to transfer the license wasreceived on November 23, 2005. Authority from the Kentucky Commission totransfer the license was granted on December 22, 2005. The license wastransferred to the Lock 7 Hydro Partners, LLC on December 29, 2005.

 

**Note 4 - Financial Instruments**

 

The cost and estimated fair values of KU’s non-trading financialinstruments as of December 31, 2005, and 2004 follow:

 

126

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| ** **                                                 | ** ** | **2005**            | ** ** | **2004**        | ** ** |
|------------------------------------------------------------|------------|---------------------|------------|-----------------|------------|
| **(in millions)**                                          | ** ** | **Carrying  Value** | ** ** | **Fair  Value** | ** ** | **Carrying  Value** | ** ** | **Fair  Value** | ** ** |
|                                                       |       |                |       |            |       |   |   |   |   |
| Long-term debt (including current portion)                 |       | $                   | 363.6      |            | $          | 363.5 |   | $ | 393.2 |   | $ | 393.5 |   |
| Long-term debt from affiliate (including  current portion) |       | $                   | 383.0      |            | $          | 382.4 |   | $ | 333.0 |   | $ | 337.0 |   |
| Interest-rate swaps - asset                                |       | $                   | 0.8        |            | $          | 0.8 |   | $ | 6.1 |   | $ | 6.1 |   |
|                                                            |            |                     |            |                 |            |  |  |  |  |  |  |  |  |  |  |

 

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. The fair values of cash and cash equivalents,accounts receivable, accounts payable and notes payable are substantially thesame as their carrying values.

 

**Interest Rate Swaps.** KU uses over-the-counter interest rateswaps to hedge exposure to market fluctuations in certain of its debtinstruments. Pursuant to Company policy, use of these financial instruments isintended to mitigate risk, earnings and cash flow volatility and is notspeculative in nature. Management has designated all of the interest rate swapsas hedge instruments. Financial instruments designated as fair value hedges andthe underlying hedged items are periodically marked to market with theresulting net gains and losses recorded directly into net income. Upontermination of any fair value hedge, the resulting gain or loss is recordedinto net income. Financial instruments designated as cash flow hedges haveresulting gains and losses recorded within other comprehensive income andstockholders’ equity.

 

KU was party to various interest rate swap agreements with aggregatenotional amounts of $53.0 million and $103.0 million as of December 31, 2005and December 31, 2004, respectively. Under these swap agreements, KU paidvariable rates based on LIBOR averaging 6.41% and 3.29%, and received fixedrates averaging 7.92% and 7.74% at December 31, 2005 and 2004, respectively.The swap agreement in effect at December 31, 2005 has been designated as a fairvalue hedge and matures in 2007. The fair value designation was assignedbecause the underlying fixed rate debt has a firm future commitment. For 2005and 2004, the effect of marking these financial instruments and the underlyingdebt to market resulted in pre-tax gains of $0.8 million and $2.5 million,respectively, recorded in interest expense.

 

Interest rate swaps hedge interest rate risk on the underlying debtunder SFAS No. 133, as amended, in addition to swaps being marked to market,the item being hedged must also be marked to market, consequently at December31, 2005 and 2004, KU’s debt reflects a mark-to-market adjustment of $2.0million and $8.2 million, respectively.

 

In June 2005, a KU interestrate swap with a notional amount of $50.0 million was terminated by thecounterparty pursuant to the terms of the swap agreement. KU received a paymentof $1.9 million in consideration for the termination of the agreement. KU alsocalled the underlying debt (First Mortgage Bond Series R) and paid a callpremium of $1.9 million. No impact on earnings occurred as a result of the bondcall and related swap termination.

 

In February 2004, KU terminated the swap it had in place at December31, 2003 related to the Series 9 pollution control bonds. The notional amountof the terminated swap was $50.0 million and KU received a payment of $2.0million as part of the termination. The swap was terminated because it was nolonger an effective hedge of the underlying bond.

 

127

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**Energy Risk Management Activities.**KU conductsenergy trading and risk management activities to maximize the value of powersales from physical assets it owns. Certain energy trading activities areaccounted for on a mark-to-market basis in accordance with SFAS No. 133, asamended. Wholesale sales of excess asset capacity are treated as normal salesunder SFAS No. 133, as amended and are not marked to market.

 

No changes to valuation techniques for energy tradingand risk management activities occurred during 2005 or 2004. Changes in marketpricing, interest rate and volatility assumptions were made during both years. Allcontracts outstanding at December 31, 2005, have a maturity of less than oneyear and are valued using prices actively quoted for proposed or executedtransactions or quoted by brokers.

 

KU maintains policies intended to minimize credit risk and revaluescredit exposures daily to monitor compliance with those policies. At December31, 2005, 100% of the trading and risk management commitments were withcounterparties rated BBB-/Baa3 equivalent or better.

 

KU hedges the price volatility of its forecasted electric off-systemsales with the sales of market-traded electric forward contracts for periods ofless than one year. These electric forward sales have been designated as cashflow hedges and are not speculative in nature. Gains or losses on theseinstruments, to the extent that the hedging relationship has been effective,are deferred in other comprehensive income. Gains and losses resulting fromineffectiveness are shown in KU’s Statements of Income in other (income) – net.Upon completion of the underlying hedge transaction, the amount recorded inother comprehensive income is recorded in earnings. No material pre-tax gainsand losses resulted from these cash flow hedges in 2005, 2004 and 2003. SeeNote 13, Accumulated Other Comprehensive Income.

 

**Accounts Receivable Securitization.**KUterminated its accounts receivable securitization program in January 2004, andin May 2004, KU dissolved its inactive accounts receivablesecuritization-related subsidiary, KU R. No material pre-tax gains and lossesresulted from the sale of the receivables in 2004 and 2003. KU’s net cash flowsfrom KU R were reduced by $50.1 million and $0.1 million for 2004 and 2003,respectively. The allowance for doubtful accounts associated with the eligiblesecuritized receivables at December 31, 2003, was $0.5 million. This allowancewas based on historical experience of KU. Each securitization facilitycontained a fully funded reserve for uncollectible receivables. KU was able toterminate this program at any time without penalty.

 

**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. Concentrationsof credit risk (whether on- or off-balance sheet) relate to groups of customersor counterparties that have similar economic or industry characteristics thatwould cause their ability to meet contractual obligations to be similarlyaffected by changes in economic or other conditions.

 

KU’s customer receivables and revenues arisefrom deliveries of electricity to approximately 495,000 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 5 customers in Tennessee. For the years ended December 31,2005 and 2004, 100% of total utility revenue was derived from electricoperations.

 

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 2005with authorized annual wage reopeners. The employees represented by these twobargaining units comprise approximately 16% of KU’s workforce.

 

128

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**Note 6 - Pension Plansand Other Postretirement Benefit Plans**

 

KU has both funded and unfunded non-contributorydefined benefit pension plans and other post-retirement benefit plans thattogether cover substantially all of its employees. The healthcare plans arecontributory with participants’ contributions adjusted annually. KU usesDecember 31 as the measurement date for its plans.

 

**Obligations and Funded Status.**Thefollowing table provides a reconciliation of the changes in the plan’s benefitobligations and fair value of assets over the three-year period ending December31, 2005, and a statement of the funded status as of December 31, 2005, 2004and 2003 for KU’s sponsored defined benefit:

 

| **(in millions)**                                  | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|----------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
|                                               |       |     |       |     |       |     |       |
| Pension Plans:                                     |       |     |       |     |       |     |       |
| Change in projected benefit obligation             |       |     |       |     |       |     |       |
| Projected benefit obligation at beginning  of year |       | $        | 290.7      |     | $          | 257.7    |       | $ | 247.7 |   |
| Service cost                                       |       | 5.1      |       | 3.7      |       | 3.0      |       |
| Interest cost                                      |       | 16.2     |       | 16.0     |       | 15.9     |       |
| Plan amendment                                     |       | —   |       | —   |       | 0.1      |       |
| Change due to transfers                            |       | (0.5     | )          | 0.1      |       | (0.3     | )          |
| Benefits paid                                      |       | (19.6    | )          | (19.6    | )          | (22.6    | )          |
| Actuarial (gain) or loss and other                 |       | 26.6     |       | 32.8     |       | 13.9     |       |
| Projected benefit obligation at end of year        |       | $        | 318.5      |     | $          | 290.7    |       | $ | 257.7 |   |
|                                               |       |     |       |     |       |     |       |
| Change in plan assets                              |       |     |       |     |       |     |       |
| Fair value of plan assets at beginning of  year    |       | $        | 248.2      |     | $          | 201.1    |       | $ | 178.6 |   |
| Actual return on plan assets                       |       | 20.7     |       | 24.6     |       | 36.5     |       |
| Employer contributions                             |       | —   |       | 43.4     |       | 10.2     |       |
| Change due to transfers                            |       | (0.4     | )          | —   |       | (0.2     | )          |
| Benefits paid                                      |       | (19.6    | )          | (19.6    | )          | (22.6    | )          |
| Administrative expenses                            |       | (1.4     | )          | (1.3     | )          | (1.4     | )          |
| Fair value of plan assets at end of year           |       | $        | 247.5      |     | $          | 248.2    |       | $ | 201.1 |   |
|                                               |       |     |       |     |       |     |       |
| Reconciliation of funded status                    |       |     |       |     |       |     |       |
| Funded status                                      |       | $        | (71.0      | )        | $          | (42.5    | )          | $ | (56.6 | ) |
| Unrecognized actuarial (gain) or loss              |       | 80.8     |       | 56.2     |       | 27.9     |       |
| Unrecognized transition (asset) or  obligation     |       | (0.1     | )          | (0.2     | )          | (0.4     | )          |
| Unrecognized prior service cost                    |       | 7.5      |       | 8.3      |       | 9.2      |       |
| Net amount recognized at end of year               |       | $        | 17.2       |     | $          | 21.8     |       | $ | (19.9 | ) |
|                                               |       |     |       |     |       |     |       |
| Other Benefits:                                    |       |     |       |     |       |     |       |
| Change in benefit obligation                       |       |     |       |     |       |     |       |
| Benefit obligation at beginning of year            |       | $        | 100.3      |     | $          | 105.8    |       | $ | 104.6 |   |
| Service cost                                       |       | 1.5      |       | 1.2      |       | 0.8      |       |
| Interest cost                                      |       | 4.9      |       | 5.8      |       | 6.3      |       |
| Plan amendments                                    |       | 0.8      |       | —   |       | —   |       |
| Benefits paid net of retiree contributions         |       | (5.2     | )          | (6.1     | )          | (7.3     | )          |
| Actuarial (gain) or loss                           |       | (7.7     | )          | (6.4     | )          | 1.4      |       |
| Benefit obligation at end of year                  |       | $        | 94.6       |     | $          | 100.3    |       | $ | 105.8 |   |
|                                               |       |     |       |     |       |     |       |
| Change in plan assets                              |       |     |       |     |       |     |       |
| Fair value of plan assets at beginning of  year    |       | $        | 5.9        |     | $          | 5.4      |       | $ | 8.0 |   |
| Actual return on plan assets                       |       | 0.7      |       | 2.5      |       | (0.8     | )          |
| Employer contributions                             |       | 7.5      |       | 4.4      |       | 5.5      |       |
| Change due to transfers                            |       | —   |       | (0.2     | )          | —   |       |
| Benefits paid net of retiree contributions         |       | (5.2     | )          | (6.2     | )          | (7.3     | )          |
| Fair value of plan assets at end of year           |       | $        | 8.9        |     | $          | 5.9      |       | $ | 5.4 |   |
|                                                    |            |          |            |          |            |          |            |  |  |  |  |

 

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| Reconciliation of funded status                |   |   |   |   |   |   |   |
|------------------------------------------------|--------|--------|--------|--------|--------|--------|--------|
| Funded status                                  |   | $      | (85.7  | )      | $      | (94.4  | )      | $ | (100.4 | ) |
| Unrecognized actuarial (gain) or loss          |   | 6.7    |   | 14.8   |   | 24.0   |   |
| Unrecognized transition (asset) or  obligation |   | 7.8    |   | 9.0    |   | 10.1   |   |
| Unrecognized prior service cost                |   | 1.6    |   | 1.4    |   | 2.2    |   |
| Net amount recognized at end of year           |   | $      | (69.6  | )      | $      | (69.2  | )      | $ | (64.1 | ) |
|                                                |        |        |        |        |        |        |        |  |  |  |  |

 

## **AmountsRecognized in Statement of Financial Position.**The followingtables provide the amounts recognized in the balance sheet and information forplans with benefit obligations in excess of plan assets as of December 31, 2005,2004 and 2003:

 

| **(in millions)**                                                                                         | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|-----------------------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
|                                                                                                      |       |     |       |     |       |     |       |
| Pension Plans:                                                                                            |       |     |       |     |       |     |       |
| Amounts recognized in the balance sheet  consisted of:                                                    |       |     |       |     |       |     |       |
| Accrued benefit liability                                                                                 |       | $        | (22.0      | )        | $          | (8.7     | )          | $ | (39.0 | ) |
| Intangible asset                                                                                          |       | 7.5      |       | 8.3      |       | 9.2      |       |
| Accumulated other comprehensive income                                                                    |       | 31.7     |       | 22.2     |       | 9.9      |       |
| Net amount recognized at year-end                                                                         |       | $        | 17.2       |     | $          | 21.8     |       | $ | (19.9 | ) |
|                                                                                                      |       |     |       |     |       |     |       |
| Increase (decrease) in minimum liability  included in other comprehensive income                          |       | $        | 9.5        |     | $          | 12.4     |       | $ | (7.7 | ) |
|                                                                                                      |       |     |       |     |       |     |       |
| Additional year-end information for plans  with accumulated benefit obligations in excess of plan assets: |       |     |       |     |       |     |       |
| Projected benefit obligation                                                                              |       | $        | 318.5      |     | $          | 290.7    |       | $ | 257.7 |   |
| Accumulated benefit obligation                                                                            |       | 269.5    |       | 256.9    |       | 240.1    |       |
| Fair value of plan assets                                                                                 |       | 247.5    |       | 248.2    |       | 201.1    |       |
|                                                                                                      |       |     |       |     |       |     |       |
| Other Benefits:                                                                                           |       |     |       |     |       |     |       |
| Amounts recognized in the balance sheet consisted  of:                                                    |       |     |       |     |       |     |       |
| Accrued benefit liability                                                                                 |       | $        | (69.6      | )        | $          | (69.2    | )          | $ | (64.1 | ) |
|                                                                                                      |       |     |       |     |       |     |       |
| Additional year-end information for plans  with benefit obligations in excess of plan assets:             |       |     |       |     |       |     |       |
| Benefit obligation                                                                                        |       | $        | 94.6       |     | $          | 100.3    |       | $ | 105.8 |   |
| Fair value of plan assets                                                                                 |       | 8.9      |       | 5.9      |       | 5.4      |       |
|                                                                                                           |            |          |            |          |            |          |            |  |  |  |  |

 

**Components of Net Periodic Benefit Cost.**Thefollowing table provides the components of net periodic benefit cost for theplans for 2005, 2004 and 2003:

 

| **(in millions)**                                 | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|---------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
|                                              |       |     |       |     |       |     |       |
| Pension  Plans:                                   |       |     |       |     |       |     |       |
| Components of net periodic benefit cost           |       |     |       |     |       |     |       |
| Service cost                                      |       | $        | 5.1        |     | $          | 3.7      |       | $ | 3.0 |   |
| Interest cost                                     |       | 16.2     |       | 16.0     |       | 15.9     |       |
| Expected return on plan assets                    |       | (19.6    | )          | (19.6    | )          | (14.9    | )          |
| Amortization of transition (asset) or  obligation |       | (0.1     | )          | (0.1     | )          | (0.1     | )          |
| Amortization of prior service cost                |       | 0.8      |       | 0.9      |       | 0.9      |       |
| Amortization of actuarial (gain) or loss          |       | 2.2      |       | 0.8      |       | 1.2      |       |
| Net periodic benefit cost                         |       | $        | 4.6        |     | $          | 1.7      |       | $ | 6.0 |   |
|                                              |       |     |       |     |       |     |       |
| Other Benefits:                                   |       |     |       |     |       |     |       |
| Components of net periodic benefit cost           |       |     |       |     |       |     |       |
|                                                   |            |          |            |          |            |          |            |  |  |  |  |

 

130

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| Service cost                                        |   | $    | 1.5    |   | $      | 1.2  |   | $ | 0.8 |   |
|-----------------------------------------------------|--------|------|--------|--------|--------|------|--------|---|-----|--------|
| Interest cost                                       |   | 4.9  |   | 5.8    |   | 6.3  |   |
| Expected return on plan assets                      |   | (0.6 | )      | (0.4   | )      | (0.3 | )      |
| Amortization of prior service cost                  |   | 0.7  |   | 0.7    |   | 0.7  |   |
| Amortization of transitional (asset) or  obligation |   | 1.1  |   | 1.1    |   | 1.1  |   |
| Amortization of actuarial (gain) or loss            |   | 0.3  |   | 1.0    |   | 1.2  |   |
| Net periodic benefit cost                           |   | $    | 7.9    |   | $      | 9.4  |   | $ | 9.8 |   |

 

The assumptions used in themeasurement of KU’s pension benefit obligation are shown in the followingtable:

 

| ** **                                       | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|--------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
|                                             |       |     |       |     |       |     |       |
| Weighted-average  assumptions as of December 31: |       |     |       |     |       |     |       |
| Discount  rate                                   |       | 5.50     | %          | 5.75     | %          | 6.25     | %          |
| Rate of  compensation increase                   |       | 5.25     | %          | 4.50     | %          | 3.00     | %          |

 

The assumptions used in themeasurement of KU’s net periodic benefit cost are shown in the following table:

 

| ** **                                | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|-------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
|                                      |       |     |       |     |       |     |       |
| Discount  rate                            |       | 5.75     | %          | 6.25     | %          | 6.75     | %          |
| Expected long-term  return on plan assets |       | 8.25     | %          | 8.50     | %          | 9.00     | %          |
| Rate of  compensation increase            |       | 4.50     | %          | 3.50     | %          | 3.75     | %          |

 

To develop the expected long-term rate of return on assets assumption,KU considered the current level of expected returns on risk free investments (primarilygovernment bonds), the historical level of the risk premium associated with theother asset classes in which the portfolio is invested and the expectations forfuture returns of each asset class. The expected return for each asset classwas then weighted based on the target asset allocation to develop the expectedlong-term rate of return on assets assumption for the portfolio.

 

## **AssumedHealthcare Cost Trend Rates.**For measurement purposes, an11.0% annual increase in the per capita cost of covered healthcare benefits wasassumed for 2005. The rate was assumed to decrease gradually to 5.0% by 2015and remain at that 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 millions)**                                                 | ** ** | **1% Decrease** | ** ** | **1% Increase** | ** ** |
|-------------------------------------------------------------------|------------|-----------------|------------|-----------------|------------|
|                                                              |       |            |       |            |       |
| Effect on  total of service and interest cost components for 2005 |       | $               | (0.4       | )               | $          | 0.4 |   |
| Effect on  year-end 2005 postretirement benefit obligations       |       | $               | (5.6       | )               | $          | 6.4 |   |

 

## **ExpectedFuture Benefit Payments.**The following list provides theamount of expected future benefit payments, which reflect expected futureservice, as appropriate:

 
| **(in millions)** | ** ** | **Pension  Plans** | ** ** | **Other  Benefits** | ** ** |
|-------------------|------------|--------------------|------------|---------------------|------------|
|              |       |               |       |                |       |
| 2006              |       | $                  | 19.3       |                | $          | 6.8 |   |
| 2007              |       | $                  | 18.8       |                | $          | 7.2 |   |
| 2008              |       | $                  | 18.2       |                | $          | 7.4 |   |
| 2009              |       | $                  | 17.7       |                | $          | 7.7 |   |
| 2010              |       | $                  | 17.3       |                | $          | 7.9 |   |
| 2011-2015         |       | $                  | 85.3       |                | $          | 41.4 |   |

 

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## **EstimatedGross Amount of Medicare Subsidy Receipts.**The following listprovides the amount of subsidy receipts which are expected to be received.

##  

| **(in millions)** | ** ** | **Other  Benefits** | ** ** |
|-------------------|------------|---------------------|------------|
| 2006              |       | $                   | 0.5        |   |
| 2007              |       | $                   | 0.5        |   |
| 2008              |       | $                   | 0.6        |   |
| 2009              |       | $                   | 0.6        |   |
| 2010              |       | $                   | 0.6        |   |
| 2011-2015         |       | $                   | 3.3        |   |

 

## **PlanAssets.**The following table shows KU’s weighted-average assetallocation by asset category at December 31:

##  

| ** **         | ** ** | **Target  Range** | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|--------------------|------------|-------------------|------------|----------|------------|----------|------------|----------|------------|
| Pension  Plans:    |       |              |       |     |       |     |       |     |       |
| Equity  securities |       | 45% - 75          | %          | 57       | %          | 66       | %          | 66       | %          |
| Debt  securities   |       | 30% - 50          | %          | 42       | %          | 33       | %          | 33       | %          |
| Other              |       | 0% - 10           | %          | 1        | %          | 1        | %          | 1        | %          |
| 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 ofthe investment policy is to preserve the capital of the fund and maximizeinvestment earnings. The return objective is to exceed the benchmark return forthe policy index comprised of the following: Russell 3000 Index, MSCI-EAFEIndex, Lehman Aggregate, and Lehman Long Duration Gov/Corporate Bond Index inproportions equal to the targeted asset allocation.

 

**Evaluationof performance focuses on a long-term investment time horizon of at least threeto five years or a complete market cycle. The assets of the pension plans arebroadly 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 thefund is diversified among the market’s various subsections to diversify risk,maximize returns and avoid undue exposure to any single economic sector,industry group or individual security. The equity subsectors include, but arenot limited to, growth, value, small capitalization and international.

 

Inaddition, the overall fixed income portfolio may have an averageweighted duration, or interest rate sensitivity which is within +/- 20% of theduration of overall fixed income benchmark. Foreign bonds in the aggregateshall not exceed 10% of the total fund. The portfolio may include a limitedinvestment of up to 20% in below investment grade securities provided that theoverall average portfolio quality remains “AA” or better. The below investmentgrade securities include, but are not limited to, medium-term notes, corporatedebt, non-dollar and emerging market debt and asset backed securities. The cash investments should be in securitiesthat either are of short maturities (not to exceed 180 days) or readilymarketable with modest risk.

 

Derivative securities are permitted only to improve the portfolio’srisk/return profile, to modify the portfolio’s duration or to reducetransaction costs and must be used in conjunction with underlying physicalassets in the 

 

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portfolio. Derivative securities that involve speculation, leverage,interest rate anticipation, or any undue risk whatsoever are not deemedappropriate 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 postretirement funds are invested in a prime cash money market fund that investsprimarily in a portfolio of short-term, high-quality fixed income securitiesissued by banks, corporations and the U.S. government.

 

### **Contributions.**KU madediscretionary contributions to the pension plan of $10.2 million in 2003 and$43.4 million in 2004. KU did not make a contribution to the pension plan in 2005.

###  

**FSP 106-2.**FSP 106-2, which provided guidanceon accounting for subsidies provided under the Medicare Act, was effective forthe first interim or annual period beginning after June 15, 2004. The followingtable reflects the impact of the subsidy in 2004:

 
| **(in millions)**                                                                           | ** ** | ** ** | ** ** |
|---------------------------------------------------------------------------------------------|------------|------------|------------|
| Reduction in  APBO                                                                          |       | $          | 3.3        |   |
|                                                                                        |       |       |       |
| Effect of  the subsidy on the measurement of the net periodic postretirement benefit  cost: |       |       |       |
|                                                                                        |       |       |       |
| Amortization  of the actuarial experience gain/(loss)                                       |       | $          | 0.3        |   |
| Reduction in  service cost due to the subsidy                                               |       | —     |       |
| Resulting  reduction in interest cost on the APBO                                           |       | 0.2        |       |
| Total                                                                                       |       | $          | 0.5        |   |

 

**Thrift Savings Plans.**KU has a thrift savingsplan under section 401(k) of the Internal Revenue Code. Under the plan,eligible employees may defer and contribute to the plan a portion of currentcompensation in order to provide future retirement benefits. KU makescontributions to the plan by matching a portion of the employee contributions.The costs of this matching were approximately $1.5 million for 2005, $1.5 millionfor 2004 and $1.9 million for 2003.

 

**Note 7 - Income Taxes**

 

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

 
| **(in millions)**                      | ** **            | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|----------------------------------------|-----------------------|----------|------------|----------|------------|----------|------------|
|                                   |                  |     |       |     |       |     |       |
| Current                                | - federal             |     | $          | 56.8     |       | $        | 39.3       |   | $ | 29.1 |   |
|                                   | - state               |     | 10.6       |     | 17.7       |     | 11.4       |   |
| Deferred                               | - federal –  net |     | (1.9       | )        | 22.0       |     | 11.4       |   |
|                                   | - state –  net   |     | 0.2        |     | (0.5       | )        | 0.9        |   |
| Amortization  of investment tax credit |                  | (1.7     | )          | (2.1     | )          | (2.7     | )          |
| Total income  tax expense              |                  | $        | 64.0       |     | $          | 76.4     |       | $ | 50.1 |   |

 

Deferred federal income tax expense during 2003 and 2004 includedsignificant deductions attributable to federal bonus depreciation which endedafter December 2004.

 

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

 

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| **(in millions)**                          | ** ** | **2005** | ** ** | **2004** | ** ** |
|--------------------------------------------|------------|----------|------------|----------|------------|
|                                       |       |     |       |     |       |
| Deferred tax  liabilities:                 |       |     |       |     |       |
| Depreciation and other plant-related items |       | $        | 300.7      |     | $          | 304.7 |   |
| Regulatory assets and other                |       | 26.4     |       | 25.9     |       |
| Total deferred tax liabilities             |       | 327.1    |       | 330.6    |       |
|                                       |       |     |       |     |       |
| Deferred tax  assets:                      |       |     |       |     |       |
| Investment tax credit                      |       | 0.8      |       | 1.5      |       |
| Income taxes due to customers              |       | 9.1      |       | 7.8      |       |
| Pensions and related benefits              |       | 23.3     |       | 21.2     |       |
| Liabilities and other                      |       | 20.1     |       | 17.5     |       |
| Total deferred tax assets                  |       | 53.3     |       | 48.0     |       |
|                                       |       |     |       |     |       |
| Net deferred  income tax liability         |       | $        | 273.8      |     | $          | 282.6 |   |

 

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

 
| ** **                                           | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
|                                                 |       |     |       |     |       |     |       |
| Statutory  federal income tax rate                   |       | 35.0     | %          | 35.0     | %          | 35.0     | %          |
| State income  taxes, net of federal benefit          |       | 3.8      |       | 5.4      |       | 5.8      |       |
| Reduction of  income tax accruals                    |       | (2.5     | )          | (0.5     | )          | (1.0     | )          |
| EEI  undistributed earnings adjustment               |       | 1.8      |       | —   |       | —   |       |
| Change in  tax rate                                  |       | 0.1      |       | —   |       | —   |       |
| Amortization  of investment tax credit & R&D |       | (1.0     | )          | (1.2     | )          | (1.9     | )          |
| Other  differences                                   |       | (0.9     | )          | (2.3     | )          | (2.5     | )          |
| Effective  income tax rate                           |       | 36.3     | %          | 36.4     | %          | 35.4     | %          |

 

Other differences for 2005 include excess deferred taxes which reflectthe benefits of deferred taxes reversing at higher tax rates than the currentstatutory rate (1.0%) and various other permanent differences 0.1%. Otherdifferences for 2004 include excess deferred taxes (1.4%) and various otherpermanent differences (0.9%). Other differences for 2003 include excessdeferred taxes (1.9%) and various other permanent differences (0.6%).

 

KUrecognized additional deferred income tax expense in the third quarter of 2005($3.1 million) related to the undistributed earnings of its EEI unconsolidatedinvestment. Recent EEI management decisions regarding changes in the distributionof EEI’s earnings led to the decision to provide deferred taxes for all bookand tax temporary differences in this investment.

 

OnSeptember 19, 2005, KU received notice from the Congressional Joint Committeeon Taxation approving the Internal Revenue Service’s audit of KU’s income taxreturns for the periods December 1999 through December 2003. As a result ofresolving numerous tax matters during these periods, KU reduced income taxaccruals by $4.6 million during 2005.

 

Kentucky HouseBill 272, also known as “Kentucky’s Tax Modernization Plan”, was signed intolaw in March 2005. This bill contains a number of changes in Kentucky’s taxsystem, including the reduction of the Corporate income tax rate from 8.25% to7% effective January 1, 2005, and a further reduction to 6% effective January1, 2007. As a result of the income tax rate change, KU’s deferred tax reserveamount will exceed its actual deferred tax liability attributable to existingtemporary differences since the new statutory rates are lower than the rateswere when the deferred tax liability originated. This excess amount is referredto as excess deferred income taxes. In June 2005, KU received approval from theKentucky Commission to establish and amortize a regulatory liability ($11.0million) for its net excess deferred income tax balances. Under this accountingtreatment, KU will amortize its depreciation-related excess deferred income taxbalances under the average rate assumption method. The average rate assumptionmethod matches the amortization of the excess 

 

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deferredincome taxes with the life of the timing differences to which they relate. Excessdeferred income tax balances related to non-depreciation timing differences willbe expensed in the current year due to their immaterial amount.

 

KU expects to have adequate levels of taxable income to realize itsrecorded deferred taxes.

 

**Note 8 - Long-Term Debt**

 

As of December 31, 2005, long-term debt and the current portion of long-termdebt consist of first mortgage bonds, pollution control bonds and long-termloans from affiliated companies as summarized below.

 
| **(in millions)**                  | ** ** | **Stated  Interest Rates** | ** **           | **Maturities** | ** ** | **Principal  Amounts** | ** ** |
|------------------------------------|------------|----------------------------|----------------------|----------------|------------|------------------------|------------|
| Outstanding  at December 31, 2005: |       |                       |                 |           |       |                   |       |
| Noncurrent  portion                |       |                       | Variable – 7.92 | %              | 2007-2035  |                   | $          | 623.5 |   |
| Current  portion                   |       |                       | Variable – 5.99 | %              | 2006-2032  |                   | $          | 123.1 |   |
|                               |       |                       |                 |           |       |                   |       |   |
| Outstanding  at December 31, 2004: |       |                       |                 |           |       |                   |       |   |
| Noncurrent portion                 |       |                       | Variable – 7.92 | %              | 2006-2032  |                   | $          | 564.1 |   |
| Current portion                    |       |                       |   Variable |           | 2005-2032  |                   | $          | 162.1 |   |

 

Under the provisions for KU’s variable-rate pollution control bonds,Series 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 the occurrenceof certain events, causing the bonds to be classified as current portion oflong-term debt in the balance sheets. The average annualized interest rate forthese bonds during 2005 and 2004 was 2.55% and 1.37%, respectively.

 

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 agreementobligates KU to make debt service payments to the county that equate to thedebt service due from the county on the related pollution control revenue bonds.The county’s debt is also secured by an equal amount of KU’s first mortgagebonds (the pollution control series bonds) that are pledged to the trustee forthe pollution control revenue bonds, and that match the terms and conditions ofthe county’s debt, but require no payment of principal and interest unless KUdefaults on the loan agreement.

 

Substantially all of KU’s assets are pledged as security for its firstmortgage bonds.

 

Interest rate swaps are used to hedge KU’s underlying debt obligations.These swaps hedge specific debt issuances and, consistent with management’sdesignation, are accorded hedge accounting treatment. The swaps effectivelyconvert fixed rate obligations on KU’s first mortgage bonds Series P tovariable-rate obligations. As of December 31, 2005 and 2004, KU had swaps witha combined notional value of $53.0 million and $103.0 million, respectively. SeeNote 4, Financial Instruments.

 

Redemptions and maturities of long-term debt for 2005, 2004 and 2003are summarized below:

 

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($ in millions)

 
| **Year** | ** ** | **Description**          | ** ** | **Principal  Amount** | ** ** | **Rate** | ** ** | **Secured/  Unsecured** | ** ** | **Maturity** | ** ** |
|----------|------------|--------------------------|------------|-----------------------|------------|----------|------------|-------------------------|------------|--------------|------------|
| 2005     |       | First  mortgage bonds    |       | $                     | 50.0       |     | 7.55       | %                       | Secured    |         | Jun 2025   |   |
| 2005     |       | Due to  Fidelia          |       | $                     | 75.0       |     | 2.29       | %                       | Secured    |         | Dec 2005   |   |
| 2004     |       | Pollution  control bonds |       | $                     | 4.8        |     | Variable   |                    | Secured    |         | Feb 2032   |   |
| 2004     |       | Pollution  control bonds |       | $                     | 50.0       |     | 5.75       | %                       | Secured    |         | Dec 2023   |   |
| 2003     |       | First  mortgage bonds    |       | $                     | 62.0       |     | 6.32       | %                       | Secured    |         | Jun 2003   |   |
| 2003     |       | First  mortgage bonds    |       | $                     | 33.0       |     | 8.55       | %                       | Secured    |         | May 2027   |   |

 

Issuances of long-term debt for 2005, 2004 and 2003 are summarizedbelow:

 

($ in millions)

 
| **Year** | ** ** | **Description**          | ** ** | **Principal  Amount** | ** ** | **Rate** | ** ** | **Secured/  Unsecured** | ** ** | **Maturity** | ** ** |
|----------|------------|--------------------------|------------|-----------------------|------------|----------|------------|-------------------------|------------|--------------|------------|
| 2005     |       | Pollution  control bonds |       | $                     | 13.3       |     | Variable   |                    | Secured    |         | Jun 2035   |   |
| 2005     |       | Pollution  control bonds |       | $                     | 13.3       |     | Variable   |                    | Secured    |         | Jun 2035   |   |
| 2005     |       | Due to  Fidelia          |       | $                     | 50.0       |     | 4.735      | %                       | Unsecured  |         | Jul 2015   |   |
| 2005     |       | Due to  Fidelia          |       | $                     | 75.0       |     | 5.36       | %                       | Unsecured  |         | Dec 2015   |   |
| 2004     |       | Due to  Fidelia          |       | $                     | 50.0       |     | 4.39       | %                       | Unsecured  |         | Jan 2012   |   |
| 2004     |       | Pollution  control bonds |       | $                     | 50.0       |     | Variable   |                    | Secured    |         | Oct 2034   |   |
| 2003     |       | Due to  Fidelia          |       | $                     | 100.0      |     | 4.55       | %                       | Unsecured  |         | Apr 2013   |   |
| 2003     |       | Due to  Fidelia          |       | $                     | 75.0       |     | 5.31       | %                       | Secured    |         | Aug 2013   |   |
| 2003     |       | Due to  Fidelia          |       | $                     | 33.0       |     | 4.24       | %                       | Secured    |         | Nov 2010   |   |
| 2003     |       | Due to  Fidelia          |       | $                     | 75.0       |     | 2.29       | %                       | Secured    |         | Dec 2005   |   |

 

In May 2005, KU repaid a $26.7 million loan against the cash surrendervalue of life insurance policies.

 

In October 2005, KU redeemed all of its outstanding shares of preferredstock for $40.8 million. KU paid $101 per share for the 4.75% Series and$102.939 per share for the 6.53% Series.

 

Long-term debt maturities for KU are shown in the following table:

 
| **(in millions)** | ** ** | ** ** | ** ** |
|-------------------|------------|------------|------------|
| 2006              |       | $          | 36.0       |   |
| 2007              |       | 55.0       |       |
| 2008              |       | —     |       |
| 2009              |       | —     |       |
| 2010              |       | 33.0       |       |
| Thereafter        |       |       | 622.6      | (a) |
| Total             |       | $          | 746.6      |   |

 

----

(a)  Includes long-term debt of$87.1 million classified as current liabilities because these bonds are subjectto tender for purchase at the option of the holder and to mandatory tender forpurchase upon the occurrence of certain events. Maturity dates for these bonds range from 2024 to 2032.  KU does not expect to pay these amounts in2006.

 

**Note 9 - Notes Payable and Other Short-Term Obligations**

 

KU participates in an intercompany money pool agreement wherein E.ONU.S. and/or LG&E make funds available to KU at market-based rates (based onan index of highly rated commercial paper issues) up to $400.0 million.

 
| **($ in millions)** | ** ** | **Total Money  Pool Available** | ** ** | **Amount  Outstanding** | ** ** | **Balance  Available** | ** ** | **Average  Interest Rate** | ** ** |
|--------------------------|------------|---------------------------------|------------|-------------------------|------------|------------------------|------------|----------------------------|------------|
| December 31,  2005       |       | $                               | 400.0      |                    | $          | 69.7                   |       | $                          | 330.3      |   | 4.21 | % |
| December 31,  2004       |       | $                               | 400.0      |                    | $          | 34.8                   |       | $                          | 365.2      |   | 2.22 | % |

 

E.ON U.S. maintains a revolving credit facility totaling $200.0 millionwith an affiliated company, E.ON North America, Inc., to ensure fundingavailability for the money pool. The balance outstanding on this facility atDecember 31, 2005 was $104.7 million, leaving $95.3 million available. AtDecember 31, 2004, the facility totaled $150.0 million with a balance of $65.4million outstanding, leaving $84.6 million available.

 

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**Note 10 -Commitments and Contingencies**

 

**Operating Leases.**KU leases office space,office equipment and vehicles and accounts for these leases as operating leases.In addition, KU reimburses LG&E for a portion of the lease expense paid byLG&E for KU’s usage of office space leased by LG&E. Total lease expensefor 2005, 2004 and 2003, was $3.3 million, $2.8 million and $2.2 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 December1999, KU and LG&E entered into a tax-efficient, 18-year lease of the CTs.KU and LG&E have provided funds to fully defease the lease, 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 existwith 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 December31, 2005, the maximum aggregate amount of default fees or amounts, whichdecrease over the term of the lease, was $8.2 million, of which KU would beresponsible for $5.1 million (62%). KU has made arrangements with E.ON U.S.,via guarantee and regulatory commitment, for E.ON U.S. to pay KU’s full portionof any default fees or amounts.

 

**Letter ofCredit.**KU has provided a letter of credit totaling$0.8 million to support certain obligations related to barge unloading.

 

**Purchased Power.**KU has purchased powerarrangements with OMU and OVEC. Under the OMU 

 

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agreement, which could last through January 1, 2020, KU purchases allof the output of a 400-Mw (approximate) coal-fired generating station notrequired by OMU. The amount of purchased power available to KU during2006-2010, which is expected to be approximately 7% of KU’s total Kwh nativeload energy requirements, is dependent upon a number of factors including theOMU units’ availability, maintenance schedules, fuel costs and OMU requirements.Payments are based on the total costs of the station allocated per terms of theOMU agreement. Included in the total costs is KU’s proportionate share of debtservice requirements on $287.0 million of OMU bonds outstanding at December 31,2005. The debt service is allocated to KU based on its annual allocated shareof capacity, which averaged approximately 43% in 2005. KU does not guaranteethe OMU bonds, or any requirements 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. Previously, KU was entitled to take 20% of theavailable capacity of the station under a pricing formula comparable to thecost of other power generated by KU. Such power equated to approximately 9% ofKU’s net generation system output in 2005. This contract governing thepurchases from EEI terminated on December 31, 2005. Subsequent to December 31,2005, EEI has sold power under general market-based pricing and terms. KU hasnot contracted with EEI for power under the new arrangements, but maintains its20% ownership in the common stock of EEI. Replacement power for the EEIcapacity has been largely provided by KU generation.

 

KU has an investmentof 2.5% ownership in OVEC’s common stock, which is accounted for on the costmethod of accounting. KU is entitled to purchase 2.5% of OVEC’s output,approximately 55 Mw of generation capacity. In April 2004, OVEC and itsshareholders, including KU, entered into an Amended and Restated Inter-CompanyPower Agreement, to be effective beginning March 2006, upon the expiration ofthe current power contract among the parties. The parties received SEC approvalunder PUHCA 1935 of the Amended and Restated Inter-Company Power Agreementduring February 2005.

 

Futureobligations for power purchases are shown in the following table:

 
| **(in millions)** | ** ** | ** ** | ** ** |
|------------------------|------------|------------|------------|
| 2006                   |       | $          | 24.2       |   |
| 2007                   |       |       | 24.5       |   |
| 2008                   |       |       | 23.3       |   |
| 2009                   |       |       | 24.7       |   |
| 2010                   |       |       | 24.9       |   |
| Thereafter             |       |       | 358.2      |   |
| Total                  |       | $          | 479.8      | (a) |

 

----

(a)  Represents future minimum payments under OVECand OMU purchased power agreements through 2024.

 

**Construction Program.**KU had approximately$120.2 million of commitments in connection with its construction program atDecember 31, 2005. Construction expenditures for the three-year period endingDecember 31, 2008, are estimated to total approximately $1.5 billion, althoughall of this is not currently committed, including future expenditures relatedto the construction of Trimble County Unit 2 and the installation of FGDs atGhent and Brown.

 

**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 SO2 requirements primarily throughinstallation of FGD equipment on Ghent Unit 1 and through the consumption ofemission allowances granted under the Clean Air Act. KU’s strategy for Phase IISO2 reductions, which commenced January 1, 2000, has been to useaccumulated emissions allowances to delay additional capital expenditures andwill include fuel switching and the installation of additional FGDs asnecessary. KU decided in December 2004 that additional FGDs will be necessaryto maintain compliance with Phase II SO2 reductions. Thoseinstallations are currently scheduled for completion in 2007-2009. KU met theinitial NOx emission requirements of the Act through installation of low-NOxburner systems. 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 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 of Kentucky SIP, which was approved by theEPA on June 24, 2003, requires reductions in NOx emissions from coal-firedgenerating units to the 0.15 lb./MMBtu level on a system-wide basis. In relatedproceedings in response to petitions filed by various Northeast states, inDecember 1999, 

 

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the EPA issued a final rule pursuant to Section 126 of the Clean AirAct directing similar NOx reductions from a number of specifically targetedgenerating units including all KU units in the eastern half of Kentucky. Additionalpetitions currently pending before the EPA may potentially result in rulesencompassing KU’s remaining generating units. As a result of appeals to bothrules, the compliance date was extended to May 31, 2004. All KU generatingunits are in compliance 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 neural networks. TheNOx controls project commenced in late 2000 with the controls being placed intooperation prior to the 2004 summer ozone season. As of December 31, 2005, KUincurred total capital costs of approximately $217.0 million to reduce its NOxemissions below the 0.15 lb./MMBtu level on a company-wide basis. In addition,KU will incur additional operating and maintenance costs in operating new NOxcontrols. KU believes its costs in this regard to be comparable to those ofsimilarly situated utilities with like generation assets. KU anticipated thatsuch capital and operating costs are the type of costs that are eligible forrecovery from customers under its environmental surcharge mechanism andbelieved that a significant portion of such costs could be recovered. In April2001, the Kentucky Commission granted recovery of these costs for KU.

 

On March 10, 2005, the EPA issued the final CAIR which requiressubstantial additional reductions in SO2 and NOx emissions fromelectric generating units. The CAIR provides for a two-phased reduction programwith Phase I reductions in NOx and SO2 emissions in 2009 and 2010,respectively, and Phase II reductions in 2015. On March 15, 2005, the EPAissued a related regulation, the final CAMR, which requires substantial mercuryreductions from electric generating units. CAMR also provides for a two-phasedreduction, with the Phase I target in 2010 achieved as a “co-benefit” of thecontrols installed to meet CAIR. Additional control measures will be requiredto meet the Phase II target in 2018. Both CAIR and CAMR establish a cap andtrade framework, in which a limit is set on total emissions and allowances canbe bought or sold on the open market, to be used for compliance, unless thestate chooses another approach.

 

In order to meet these new regulatory requirements, KU has implementeda plan for adding significant additional SO2 controls to itsgenerating units. Installation of additional SO2 controls willproceed on a phased basis, with construction of controls (i.e., FGDs) havingcommenced in September 2005 and continuing through the final installation andoperation in 2009. KU estimates that it will incur $658.9 million in capitalcosts related to the construction of the FGDs to achieve compliance withcurrent emission limits on a company-wide basis. In addition, KU will incuradditional operating and maintenance costs in operating the new SO2controls.

 

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 and measures to implement EPA’sCAVR.

 

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 completed a cleanup of one MGP site in 1995, andhas conducted limited cleanups at other sites, evaluations of these types ofproperties generally have not identified issues of significance. With regard tothese properties, KU is unaware 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. Brown Station. KUcommenced immediate spill containment and recovery measures which continuedunder the oversight of the EPA and state officials and prevented the spill fromreaching the Kentucky River. KU ultimately recovered approximately 34,000gallons of diesel fuel. In November 1999, the Kentucky Division of Water issueda notice of violation for the incident. KU has resolved all outstanding issues 

 

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for this incident with the Commonwealth of Kentucky. KU incurred spillresponse and cleanup costs of approximately $1.8 million and received insurancereimbursement of $1.2 million. In December 2002, the DOJ demanded a civilpenalty to resolve alleged violations relating to the spill and failure totimely submit a facility response plan. After extensive negotiations betweenKU, the EPA and the DOJ, the government entered into a consent decree resolvingall alleged violations. Under the terms of the settlement, KU is required topay a civil penalty of $0.2 million (which has been accrued), construct a supplementalenvironmental project at a cost of $0.8 million, and maintain that project forten years at a cost of $0.4 million. The consent decree was entered by thejudge of the U.S. District Court for the Eastern District of Kentucky onDecember 23, 2005.

 

In April 2002, the EPA sent correspondence to KU and other potentiallyresponsible parties demanding recovery of remediation costs associated with atransformer scrap-yard, with such cost currently being in excess of $1.7million. The Kentucky Division of Waste Management subsequently demandedadditional cleanup measures at the site. KU and the other potentiallyresponsible parties have entered into settlement discussions with the EPA andthe Kentucky Division of Waste Management in an effort to resolve this matter.

 

In January 2005, approximately 1,000 gallons of fuel oil leaked from acracked weld in a storage tank at KU’s Green River Generating Station. KUcommenced immediate spill containment, recovery and remediation actions and hasreceived satisfactory inspections from state regulators to date. The cost relatedto the cleanup of the oil spill was less than $0.2 million and no penalties orfines are anticipated.

 

# **Note 11 – Jointly Owned Electric Utility Plant**

# ** **

LG&E and KU jointly own the following combustion turbines:

 
| **($ in  millions)** | ** ** | ** **     | ** ** | **LG&E** | ** ** | **KU** | ** ** | **Total** | ** ** |
|---------------------------|------------|----------------|------------|--------------|------------|--------|------------|-----------|------------|
| Paddy’s Run  13      |       | Ownership %    |       | 53           | %          | 47     | %          | 100       | %          |
|                      |       | Mw capacity    |       | 84           |       | 74     |       | 158       |       |
|                      |       | Cost           |       | $            | 34.0       |   | $          | 30.1      |       | $ | 64.1 |   |
|                      |       | Depreciation   |       | (5.2         | )          | (4.6   | )          | (9.8      | )          |
|                      |       | Net book value |       | $            | 28.8       |   | $          | 25.5      |       | $ | 54.3 |   |
|                      |       |           |       |         |       |   |       |      |       |
| E.W. Brown 5              |       | Ownership %    |       | 53           | %          | 47     | %          | 100       | %          |
|                      |       | Mw capacity    |       | 62           |       | 55     |       | 117       |       |
|                      |       | Cost           |       | $            | 24.0       |   | $          | 20.2      |       | $ | 44.2 |   |
|                      |       | Depreciation   |       | (3.5         | )          | (3.0   | )          | (6.5      | )          |
|                      |       | Net book value |       | $            | 20.5       |   | $          | 17.2      |       | $ | 37.7 |   |
|                      |       |           |       |         |       |   |       |      |       |
| E.W. Brown 6              |       | Ownership %    |       | 38           | %          | 62     | %          | 100       | %          |
|                      |       | Mw capacity    |       | 59           |       | 95     |       | 154       |       |
|                      |       | Cost           |       | $            | 25.3       |   | $          | 38.9      |       | $ | 64.2 |   |
|                      |       | Depreciation   |       | (4.2         | )          | (7.9   | )          | (12.1     | )          |
|                      |       | Net book value |       | $            | 21.1       |   | $          | 31.0      |       | $ | 52.1 |   |
|                      |       |           |       |         |       |   |       |      |       |
| E.W. Brown 7              |       | Ownership %    |       | 38           | %          | 62     | %          | 100       | %          |
|                      |       | Mw capacity    |       | 59           |       | 95     |       | 154       |       |
|                      |       | Cost           |       | $            | 24.9       |   | $          | 39.7      |       | $ | 64.6 |   |
|                      |       | Depreciation   |       | (6.4         | )          | (8.2   | )          | (14.6     | )          |
|                      |       | Net book value |       | $            | 18.5       |   | $          | 31.5      |       | $ | 50.0 |   |
|                      |       |           |       |         |       |   |       |      |       |
| Trimble 5                 |       | Ownership %    |       | 29           | %          | 71     | %          | 100       | %          |
|                      |       | Mw capacity    |       | 46           |       | 114    |       | 160       |       |
|                      |       | Cost           |       | $            | 16.4       |   | $          | 39.7      |       | $ | 56.1 |   |
|                      |       | Depreciation   |       | (1.9         | )          | (4.7   | )          | (6.6      | )          |
|                      |       | Net book value |       | $            | 14.5       |   | $          | 35.0      |       | $ | 49.5 |   |

 

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| Trimble 6              |   | Ownership %    |   | 29     | %      | 71     | %      | 100    | %      |
|------------------------|--------|----------------|--------|--------|--------|--------|--------|--------|--------|
|                   |   | Mw capacity    |   | 46     |   | 114    |   | 160    |   |
|                   |   | Cost           |   | $      | 16.2   |   | $      | 39.7   |   | $ | 55.9 |   |
|                   |   | Depreciation   |   | (1.9   | )      | (4.7   | )      | (6.6   | )      |
|                   |   | Net book value |   | $      | 14.3   |   | $      | 35.0   |   | $ | 49.3 |   |
|                   |   |           |   |   |   |   |   |   |   |
| Trimble 7              |   | Ownership %    |   | 37     | %      | 63     | %      | 100    | %      |
|                   |   | Mw capacity    |   | 59     |   | 101    |   | 160    |   |
|                   |   | Cost           |   | $      | 19.3   |   | $      | 33.3   |   | $ | 52.6 |   |
|                   |   | Depreciation   |   | (1.0   | )      | (1.7   | )      | (2.7   | )      |
|                   |   | Net book value |   | $      | 18.3   |   | $      | 31.6   |   | $ | 49.9 |   |
|                   |   |           |   |   |   |   |   |   |   |
| Trimble 8              |   | Ownership %    |   | 37     | %      | 63     | %      | 100    | %      |
|                   |   | Mw capacity    |   | 59     |   | 101    |   | 160    |   |
|                   |   | Cost           |   | $      | 19.2   |   | $      | 32.8   |   | $ | 52.0 |   |
|                   |   | Depreciation   |   | (1.0   | )      | (1.7   | )      | (2.7   | )      |
|                   |   | Net book value |   | $      | 18.2   |   | $      | 31.1   |   | $ | 49.3 |   |
|                   |   |           |   |   |   |   |   |   |   |
| Trimble 9              |   | Ownership %    |   | 37     | %      | 63     | %      | 100    | %      |
|                   |   | Mw capacity    |   | 59     |   | 101    |   | 160    |   |
|                   |   | Cost           |   | $      | 19.2   |   | $      | 32.8   |   | $ | 52.0 |   |
|                   |   | Depreciation   |   | (1.0   | )      | (1.6   | )      | (2.6   | )      |
|                   |   | Net book value |   | $      | 18.2   |   | $      | 31.2   |   | $ | 49.4 |   |
|                   |   |           |   |   |   |   |   |   |   |
| Trimble 10             |   | Ownership %    |   | 37     | %      | 63     | %      | 100    | %      |
|                   |   | Mw capacity    |   | 59     |   | 101    |   | 160    |   |
|                   |   | Cost           |   | $      | 19.1   |   | $      | 32.8   |   | $ | 51.9 |   |
|                   |   | Depreciation   |   | (0.9   | )      | (1.6   | )      | (2.5   | )      |
|                   |   | Net book value |   | $      | 18.2   |   | $      | 31.2   |   | $ | 49.4 |   |
|                   |   |           |   |   |   |   |   |   |   |
| Trimble CT  Pipeline   |   | Ownership %    |   | 29     | %      | 71     | %      | 100    | %      |
|                   |   | Cost           |   | $      | 2.0    |   | $      | 4.9    |   | $ | 6.9 |   |
|                   |   | Depreciation   |   | (0.2   | )      | (0.6   | )      | (0.8   | )      |
|                   |   | Net book value |   | $      | 1.8    |   | $      | 4.3    |   | $ | 6.1 |   |
|                   |   |           |   |   |   |   |   |   |   |
| Trimble CT  Substation |   | Ownership %    |   | 29     | %      | 71     | %      | 100    | %      |
| 5 & 6              |   | Cost           |   | $      | 1.5    |   | $      | 3.6    |   | $ | 5.1 |   |
|                   |   | Depreciation   |   | (0.1   | )      | (0.3   | )      | (0.4   | )      |
|                   |   | Net book value |   | $      | 1.4    |   | $      | 3.3    |   | $ | 4.7 |   |
|                   |   |           |   |   |   |   |   |   |   |
| Trimble CT  Substation |   | Ownership %    |   | 37     | %      | 63     | %      | 100    | %      |
| 7 - 10                 |   | Cost           |   | $      | 3.1    |   | $      | 4.9    |   | $ | 8.0 |   |
|                   |   | Depreciation   |   | (0.1   | )      | (0.2   | )      | (0.3   | )      |
|                   |   | Net book value |   | $      | 3.0    |   | $      | 4.7    |   | $ | 7.7 |   |

 

In addition to these generating units, KU and LG&E share jointownership in the Brown Inlet Air Cooling system. KU owns 90% of the system,attributable to Brown Unit 5 and Units 8-11, which provides an additional 88 Mwof capacity.

 

**Note 12 - Related Party Transactions**

 

KU, subsidiaries of E.ON U.S. and other subsidiaries of E.ON engage inrelated party transactions. Transactions between KU and its subsidiary KU R areeliminated upon consolidation with KU. Transactions between KU and E.ON U.S.subsidiaries are eliminated upon consolidation of E.ON U.S. Transactionsbetween KU and E.ON subsidiaries are eliminated upon consolidation of E.ON. Thesetransactions are generally performed at cost and are 

 

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in accordance with the prior SEC regulations under PUHCA 1935 and theapplicable FERC, Kentucky Commission and Virginia Commission regulations. Amountspayable to and receivable from related parties are netted and presented asaccounts payable to affiliated companies on the balance sheet of KU, as alloweddue to the right of offset. Obligations related to intercompany debt arrangementswith E.ON U.S. and Fidelia are presented as separate line items on the balancesheet, as appropriate. The significant related party transactions are disclosedbelow.

 

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 sellsenergy to LEM, a subsidiary of E.ON U.S. These sales and purchases are includedin the Statements of Income as Electric Operating Revenues and Purchased PowerOperating Expense. KU intercompany electric revenues and purchased powerexpense for the years ended December 31, 2005, 2004 and 2003 were as follows:

 
| **(in millions)**                          | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|--------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Electric  operating revenues from LG&E |       | $        | 95.5       |     | $          | 61.7     |       | $ | 46.7 |   |
| Electric  operating revenues from LEM      |       | —   |       | 0.2      |       | 2.4      |       |
| Purchased  power from LG&E             |       | 91.6     |       | 58.7     |       | 53.7     |       |
|                                            |            |          |            |          |            |          |            |  |  |  |

 

Interest Charges

 

See Note 9, Notes Payable and Other Short-Term Obligations, for detailsof intercompany borrowing arrangements. Intercompany agreements do not requireinterest payments for receivables related to services provided when settledwithin 30 days.

 

KU’s intercompany interest income and expense for the years endedDecember 31, 2005, 2004 and 2003 were as follows:

 
| **(in millions)**             | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|-------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Interest on  money pool loans |       | $        | 1.0        |     | $          | 0.4      |       | $ | 1.2 |   |
| Interest on  Fidelia loans    |       | 15.0     |       | 13.8     |       | 4.7      |       |
|                               |            |          |            |          |            |          |            |  |  |  |

 

Other Intercompany Billings

 

E.ON U.S. Services provides KU with a variety of centralizedadministrative, management and support services. These charges include payrolltaxes paid by E.ON U.S. on behalf of KU, labor and burdens of E.ON U.S.Services employees performing services for KU and vouchers paid by E.ON U.S.Services on behalf of KU. The cost of these services are directly charged toKU, or for general costs which cannot be directly attributed, charged based onpredetermined allocation factors, including the following ratios: number ofcustomers, total assets, revenues, number of employees and other statisticalinformation. These costs are charged on an actual cost basis.

 

In addition, KU and LG&E provide services to each other and to E.ONU.S. Services. Billings between LG&E and KU relate to labor and overheadsassociated with union employees performing work for the other utility, chargesrelated to jointly-owned combustion turbines, and other miscellaneous charges. Billingsfrom KU to E.ON U.S. Services related to information technology-relatedservices provided by KU employees, cash received by E.ON U.S. Services onbehalf of KU and services provided by KU to other non-regulated businesseswhich are paid through E.ON U.S. Services.

 

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Intercompany billings to and from KU for the years ended December 31,2005, 2004 and 2003 were as follows:

 
| **(in millions)**                  | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| E.ON U.S.  Services billings to KU |       | $        | 184.9      |     | $          | 170.6    |       | $ | 202.5 |   |
| KU billings  to LG&E           |       | 28.6     |       | 7.2      |       | 16.6     |       |
| LG&E  billings to KU           |       | 100.5    |       | 59.5     |       | 77.2     |       |
| KU billings  to E.ON U.S. Services |       | 7.2      |       | 5.0      |       | 16.1     |       |
|                                    |            |          |            |          |            |          |            |  |  |  |

 

Theincrease in 2005 billings between LG&E and KU is largely due to theincrease in the unit cost of purchased power resulting from the 2005 increasesin fuel costs.

 

**Note 13 – Accumulated Other Comprehensive Income**

 

Accumulated other comprehensive income (loss) consisted of thefollowing:

 
| **(in millions)**                                                                                    | ** ** | **Minimum  Pension  Liability  Adjustment** | ** ** | **Accumulated  Derivative  Gain or Loss** | ** ** | **Pre-Tax** | ** ** | **Income  Taxes** | ** ** | **Net** | ** ** |
|------------------------------------------------------------------------------------------------------|------------|---------------------------------------------|------------|-------------------------------------------|------------|-------------|------------|-------------------|------------|---------|------------|
| Balance at December 31, 2002                                                                         |       | $                                           | (17.6      | )                                         | $          | —      |       | $                 | (17.6      | )       | $          | 7.1 |   | $ | (10.5 | ) |
|                                                                                                 |       |                                        |       |                                      |       |        |       |              |       |    |       |
| Minimum pension liability adjustment                                                                 |       | 7.7                                         |       | —                                    |       | 7.7         |       | (3.1              | )          | 4.6     |       |
| Gains (losses) on derivative instruments designated  and qualifying as cash flow hedging instruments |       | —                                      |       | (0.3                                      | )          | (0.3        | )          | 0.1               |       | (0.2    | )          |
| Balance at December 31, 2003                                                                         |       | (9.9                                        | )          | (0.3                                      | )          | (10.2       | )          | 4.1               |       | (6.1    | )          |
|                                                                                                 |       |                                        |       |                                      |       |        |       |              |       |    |       |
| Minimum pension liability adjustment                                                                 |       | (12.4                                       | )          | —                                    |       | (12.4       | )          | 5.0               |       | (7.4    | )          |
| Gains (losses) on derivative instruments designated  and qualifying as cash flow hedging instruments |       | —                                      |       | 0.3                                       |       | 0.3         |       | (0.1              | )          | 0.2     |       |
| Balance at December 31, 2004                                                                         |       | $                                           | (22.3      | )                                         | $          | —      |       | $                 | (22.3      | )       | $          | 9.0 |   | $ | (13.3 | ) |
|                                                                                                 |       |                                        |       |                                      |       |        |       |              |       |    |       |
| Minimum pension liability adjustment                                                                 |       | (9.5                                        | )          | —                                    |       | (9.5        | )          | 3.5               |       | (6.0    | )          |
| Gains (losses) on derivative instruments designated  and qualifying as cash flow hedging instruments |       | —                                      |       | —                                    |       | —      |       | —            |       | —  |       |
| Balance at December 31, 2005                                                                         |       | $                                           | (31.8      | )                                         | $          | —      |       | $                 | (31.8      | )       | $          | 12.5 |   | $ | (19.3 | ) |

 

**Note 14 - Selected Quarterly Data (Unaudited)**

 

Selected financial data for the four quarters of 2005 and 2004 areshown below. Because of seasonal fluctuations in temperature and other factors,results for quarters may fluctuate throughout the year.

 
| ** **            | ** ** | **Quarters Ended** | ** ** |
|-----------------------|------------|--------------------|------------|
| **(in millions)**     | ** ** | **March**          | ** ** | **June** | ** ** | **September** | ** ** | **December** | ** ** |
| 2005                  |       |               |       |   |   |   |   |   |   |
| Operating  revenues   |       | $                  | 287.5      |   | $ | 265.2 |   | $ | 347.2 |   | $ | 306.7 |   |
| Net  operating income |       | 65.6               |       | 34.2 |   | 55.4 |   | 46.9 |   |
| Net income            |       | 37.5               |       | 17.7 |   | 31.7 |   | 25.2 |   |
|                  |       |               |       |   |   |   |   |   |   |
| 2004                  |       |               |       |   |   |   |   |   |   |
| Operating  revenues   |       | $                  | 247.4      |   | $ | 232.4 |   | $ | 252.6 |   | $ | 263.0 |   |
| Net  operating income |       | 56.4               |       | 50.3 |   | 57.9 |   | 63.3 |   |
| Net income            |       | 32.4               |       | 27.6 |   | 34.8 |   | 38.7 |   |

 

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# **Note 15 – Subsequent Events**

 

On January 17, 2006, KU repaid its $36.0 million First Mortgage Bonds,Series S at maturity.

 

On February 27, 2006, the AG, KIUC, LG&E and KU reached asettlement agreement on the future ratemaking treatment of the VDT surcreditsand costs and subsequently submitted a joint motion to the Kentucky Commissionto approve the unanimous settlement agreement. Under the terms of thesettlement agreement, the VDT surcredit will continue at the current leveluntil such time as KU files for a change in electric base rates. The KentuckyCommission held a public hearing in the proceeding on March 21, 2006 and issuedan order thereafter approving the settlement agreement.

 

On March 17, 2006, the FERC issued an order conditionally approving therequest of KU and LGE to exit the MISO.

 

The Companies must satisfy a number of conditions to effect their exitfrom the MISO including:

 

•      Submission of various compliance filingsaddressing:

 

•      the Companies’ hold-harmless obligationsunder the MISO Transmission Owners’ Agreement, and the amount of the MISO exitfee to be paid by the Companies as calculated under the approved methodology;

 

•      the Companies’ anticipated arrangementswith SPP and TVA, including revisions to address certain independence and transmissionplanning considerations, and reciprocity arrangements to ensure certain KUrequirements customers do not incur pancaked rates for transmission andancillary services;

 

•      the Companies’ proposed OATT, as revisedto address possible capacity hoarding available transmission calculationmethodology, curtailment priority and pricing, among other matters; and

 

•      the Companies’ finalized arrangements withthe SPP and TVA.

 

•      The Companies must also file anapplication of the proposed OATT under Section 205 of the Federal Power Actincluding a proposed return on equity.

 

While KU and LG&E believe they can reasonably achieve all of theconditions imposed by the FERC order, completion of a number of the conditionsis dependent upon the actions or agreement of third parties. There is also arisk that the FERC decision will be challenged by intervenors with a requestfor rehearing, which could happen within 30 days of the decision. The Companiesare currently unable to estimate the time period, if any, in which theconditions of the FERC order might be satisfied, the Companies might receiveKentucky Commission approval and, thereafter, exit the MISO.

 

 

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Kentucky Utilities Company

REPORT OF MANAGEMENT

 

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 preparedin accordance with accounting principles generally accepted in the UnitedStates applied on a consistent basis and, necessarily, include amounts thatreflect the best estimates and judgment of management.

 

KU’s financial statements for the three years ended December 31, 2005,have been audited by PricewaterhouseCoopers LLP, an independent registeredpublic accounting firm. Management made available to PricewaterhouseCoopers LLPall KU’s financial records and related data as well as the minutes ofshareholders’ 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 an adequate system of internal controls ismaintained through the selection and training of personnel, appropriatedivision of responsibility, establishment and communication of policies andprocedures and by regular reviews of internal accounting controls by KU’sinternal auditors. Management reviews and modifies its system of internalcontrols in light of changes in conditions and operations, as well as inresponse to recommendations from the internal and external auditors. Theserecommendations for the year ended December 31, 2005, did not identify anymaterial weaknesses in the design and operation of KU’s internal controlstructure.

 

KU is not anaccelerated filer under the Sarbanes-Oxley Act of 2002 and associated rules(the “Act”) and consequently anticipates issuing Management’s Report onInternal Controls over Financial Reporting pursuant to Section 404 of the Actin its first periodic report covering the fiscal year ended December 31, 2007,as 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 registered public accounting firm, internal auditors and management.The Board of Directors reviews the results of the independent registered publicaccounting firm’s audit of the financial statements and their audit procedures,and discusses the adequacy of internal accounting controls. The Board ofDirectors also approves the annual internal auditing program, and reviews theactivities and results of the internal auditing function. Both the independentregistered public accounting firm and the internal auditors have access to theBoard of Directors at any time.

 

KU maintains and internally communicates a written code of businessconduct and a senior financial officer code of ethics which address, amongother items, potential conflicts of interest, compliance with laws, includingthose relating to financial disclosure, and the confidentiality of proprietaryinformation.

 

 

S. Bradford Rives

Chief Financial Officer

 

Kentucky Utilities Company

Louisville, Kentucky

 

Date: March 29, 2006

 

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Report of Independent RegisteredPublic Accounting Firm

 

To the Shareholder of Kentucky Utilities Company:

 

In our opinion, theaccompanying balance sheet and the related statement of capitalization, income,retained earnings, cash flows and comprehensive income present fairly, in allmaterial respects, the financial position of Kentucky Utilities Company at December 31,2005 and December 31, 2004, and the results of its operations and its cashflows for each of the three years in the period ended December 31, 2005 inconformity with accounting principles generally accepted in the United Statesof America. In addition, in our opinion, the financial statement schedule listedin the index appearing under Item 15(a)(2) present fairly, in all materialrespects, the information set forth therein when read in conjunction with therelated financial statements. These financial statements and financialstatement schedule are the responsibility of the Company’s management. Ourresponsibility is to express an opinion on these financial statements andfinancial statement schedule based on our audits. We conducted our auditsof these statements in accordance with the standards of the Public CompanyAccounting Oversight Board (United States). Those standards require that weplan and perform the audit to obtain reasonable assurance about whetherthe financial statements are free of material misstatement. An audit includesexamining, on a test basis, evidence supporting the amounts and disclosures inthe financial statements, assessing the accounting principles used andsignificant estimates made by management, and evaluating the overall financialstatement presentation. We believe that our audits provide a reasonable basisfor our opinion. 

 

As discussed in Note1 to the financial statements, effective December31, 2005, Kentucky Utilities Company adopted Statement of Financial AccountingStandards Board Interpretation No. 47, *Accounting for ConditionalAsset Retirement Obligations.*

 

/s/ PricewaterhouseCoopers LLP

Louisville, Kentucky

February 8, 2006

 

146

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# **ITEM 9. Changes in andDisagreements with Accountants on 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 KUconducted an evaluation of such controls and procedures under the supervisionand with the participation of the Companies’ Management, including theChairman, President and Chief Executive Officer (“CEO”) and the Chief FinancialOfficer (“CFO”). Based upon that evaluation, the CEO and CFO are of theconclusion that the Companies’ disclosure controls and procedures are effectiveas of the end of the period covered 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 fiscal yearended December 31, 2005, that has materially affected, or is reasonably likelyto materially affect, the Companies’ internal control over financial reporting.

 

LG&E andKU are not accelerated filers under the Sarbanes-Oxley Act of 2002 andassociated rules (the “Act”) and consequently anticipate issuing Management’sReport on Internal Controls over Financial Reporting pursuant to Section 404 ofthe Act in their first periodic reports covering the fiscal year ended December31, 2007, as permitted by SEC rulemaking.

 

ITEM 9B. Other Information.

 

Filed as Exhibits 4.28, 4.29 and 10.47 hereto is information relatingto an intercompany long-term borrowing of KU and annual salary increases ofcertain executive officers of LG&E and KU, both of which items occurredduring the fourth quarter of 2005 in the ordinary course of business.

 

# **PART III**

# ** **

**ITEM 10. Directorsand Executive Officers of LG&E and KU**.

 

Information regarding directors who are standing for reelection is setforth in Exhibit 99.02 filed herewith, which information is incorporated hereinby reference. Information regarding executive officers of LG&E and KU hasbeen included in Part I of this 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 

 

147

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committees. The Boards of Directors of LG&E and KU have determinedthat each of Victor A. Staffieri and S. Bradford Rives is an audit committeefinancial expert as defined by Item 401(h) of Regulation S-K. All of themembers of the boards of LG&E and KU are officers or employees of thecompanies, or their ultimate parent, E.ON AG, and therefore are not independentwithin the meaning of Item 7(d)(3)(iv) of Schedule 14A of the Exchange Act. Nevertheless,LG&E and KU believe the structure and composition of their boards ofdirectors and the qualifications and attributes of their members to be fullyable and competent to perform their duties in the areas associated with auditcommittees.

 

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.eon-us.com. LG&E and KU intendto satisfy the disclosure requirement under Item 5.05 of Form 8-K regarding anamendment to, or waiver from, a provision of the Code of Ethics by posting suchinformation on 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.

 

# **ITEM 11. Executive Compensation.**

# ** **

Information regarding compensation of named executive officers and ofdirectors is set forth in Exhibit 99.02 filed herewith, which information isincorporated herein by reference.

 

# **ITEM 12. Security Ownership ofCertain 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.

 

# **ITEM 13. Certain Relationships andRelated 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.

 

# **ITEM 14. Principal Accountant Feesand 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 Financial Statement Schedules.

 

148

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| (a)    | 1.     | Financial Statements (included in Item 8):                                                  |
|--------|--------|---------------------------------------------------------------------------------------------|
|   |   |                                                                                        |
|   |   | LG&E:                                                                                   |
|   |   | Statements of Income for the three years ended December 31, 2005  (page 70).                |
|   |   | Statements of Retained Earnings for the three years ended December  31, 2005 (page 70).     |
|   |   | Statements of Comprehensive Income for the three years ended December  31, 2005 (page 71).  |
|   |   | Balance Sheets-December 31, 2005, and 2004 (page 72).                                       |
|   |   | Statements of Cash Flows for the three years ended December 31, 2005  (page 74).            |
|   |   | Statements of Capitalization-December 31, 2005, and 2004 (page 75).                         |
|   |   | Notes to Financial Statements (pages 76-104).                                               |
|   |   | Report of Management (page 105).                                                            |
|   |   | Report of Independent Registered Public Accounting Firm (page 106).                         |
|   |   |                                                                                        |
|   |   | KU:                                                                                         |
|   |   | Statements of Income for the three years ended December 31, 2005  (page 109).               |
|   |   | Statements of Retained Earnings for the three years ended December  31, 2005 (page 109).    |
|   |   | Statements of Comprehensive Income for the three years ended December  31, 2005 (page 110). |
|   |   | Balance Sheets-December 31, 2005, and 2004 (page 111).                                      |
|   |   | Statements of Cash Flows for the three years ended December 31, 2005  (page 113).           |
|   |   | Statements of Capitalization-December 31, 2005, and 2004 (page 114).                        |
|   |   | Notes to Financial Statements (pages 115-144).                                              |
|   |   | Report of Management (page 145).                                                            |
|   |   | Report of Independent Registered Public Accounting Firm (page 146).                         |

 
| 2.  Financial Statement  Schedules (included in Part IV): |
|----------------------------------------------------------------|
|                                                           |   |   |
| Schedule II                                                    |   | Valuation and Qualifying Accounts for the three years ended December  31, 2005, for LG&E (page 161), and  KU (page 162). |

 

All other schedules have been omitted as not applicable or not requiredor because the information required to be shown is included in the FinancialStatements or the accompanying Notes to Financial Statements.

 

3. Exhibits

 
| ** **  | ** ** | **Applicable** |       |   |
|-------------|------------|----------------|------------|--------|
| ** **  | ** ** | **to**         |       |   |
| ** **  | ** ** | **Form**       |       |   |
| **Exhibit** | ** ** | **10-K  of**   |       |   |
| **No.**     | ** ** | **LG&E**   | ** ** | **KU** | ** ** | **Description** |
|        |       |           |       |   |   |   |
| 2.01        |       | X              |       | X      |   | Copy of Agreement and Plan of Merger, dated as of February 27,  2000, by and among Powergen plc, LG&E Energy Corp., US Subholdco2 and  Merger Sub, including certain exhibits thereto. [Filed as Exhibit 1 to  LG&E’s and KU’s Current Report on Form 8-K filed February 29,  2000 and incorporated by reference herein] |
|        |       |           |       |   |   |   |
| 2.02        |       | X              |       | X      |   | Amendment No. 1 to Agreement and Plan of Merger, dated as of December 8,  2000, among LG&E Energy Corp., Powergen plc, Powergen US Investments  Corp. and Powergen Acquisition Corp. [Filed as Exhibit 2.01 to LG&E’s  and KU’s Current Report on Form 8-K filed December 11, 2000 and  incorporated by reference herein] |
|        |       |           |       |   |   |   |
| 2.03        |       | X              |       | X      |   | Copy of Agreement and Plan of Merger, dated as of May 20, 1997,  by and between LG&E Energy and KU Energy, including certain exhibits  thereto. [Filed as Exhibit 2 to LG&E’s and KU’s Current Report on Form 8-K  filed May 30, 1997 and incorporated by reference herein] |
|        |       |           |       |   |   |   |
| 3.01        |       | X              |       |   |   | Copy of Restated Articles of Incorporation of LG&E, dated November 6,  1996. [Filed as Exhibit 3.06 to LG&E’s Quarterly Report on Form 10-Q  for the quarter ended September 30, 1996, and incorporated by reference  herein] |
|        |       |           |       |   |   |   |
| 3.02        |       | X              |       |   |   | Copy of Amendment to Articles of Incorporation of LG&E, dated February 6,  2004. [Filed as Exhibit 3.02 to LG&E’s and KU’s Annual Report on Form 10-K  for the year ended December 31, 2003, and incorporated by reference  herein] |
|        |       |           |       |   |   |   |
| 3.03        |       | X              |       |   |   | Copy of By-Laws of LG&E, as amended through December 16,  2003. [Filed as Exhibit 3.03 to LG&E’s and KU’s Annual Report on Form 10-K  for the year ended December 31, 2003, 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, 2003, and incorporated by reference  herein] |

 

149

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| 3.06   |   |   |   | X      |   | Copy of By-Laws of KU, as amended through December 16, 2003.  [Filed as Exhibit 3.06 to LG&E’s and KU’s Annual Report on Form 10-K  for the year ended December 31, 2003, 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 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]     |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                            |
| 4.06   |   | 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]  |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                            |
| 4.07   |   | 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]     |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                            |
| 4.08   |   | 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]    |

 

150

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| 4.09   |   | 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]                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
|--------|--------|--------|--------|--------|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               |
| 4.10   |   | 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,  2003, and incorporated by reference herein]                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               |
| 4.11   |   | X      |   |   |   | Supplemental Indenture dated as of April 1, 2005, from  Louisville Gas and Electric Company to BNY Midwest Trust Company, as Trustee,  which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.1  to LG&E’s Form 8-K filed on April 13, 2005, and incorporated by  reference herein]                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               |
| 4.12   |   |   |   | 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 |

 

151

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|   |   |   |   |   |   |  the quarter ended September 30,  1992), June 15, 1993 (Exhibit 4.02 to Form 8-K of KU dated June 15,  1993) and December 1, 1993 (Exhibit 4.01 to Form 8-K of KU  dated December 10, 1993), November 1, 1994 (Exhibit 4.C to Form 10-K  Annual Report of KU for the year ended December 31, 1994), June 1,  1995 (Exhibit 4 to Form 10-Q Quarterly Report of KU for the quarter  ended June 30, 1995) and January 15, 1996 [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] |
|--------|--------|--------|--------|--------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| 4.13   |   |   |   | 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]                                                                                                                                                                                                                                                                                                                                          |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| 4.14   |   |   |   | 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]                                                                                                                                                                                                                                                                                                                                                                                            |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| 4.15   |   |   |   | X      |   | Copy of Supplemental Indenture dated September 1, 2001, which is  a supplemental instrument to Exhibit 4.12hereto. [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]                                                                                                                                                                                                                                                                                                                                                                                       |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| 4.16   |   |   |   | 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]                                                                                                                                                                                                                                                                                                                                                                                            |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| 4.17   |   |   |   | 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]                                                                                                                                                                                                                                                                                                                                                                                      |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| 4.18   |   |   |   | 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]                                                                                                                                                                                                                                                                                                                                                                                     |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| 4.19   |   |   |   | X      |   | Supplemental Indenture dated as of June 15, 2005, from Kentucky  Utilities Company to U.S. Bank National Association and Richard Prokosch, as  Trustees, which is a supplemental instrument to Exhibit                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |

 

152

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|   |   |   |   |   |   | 4.12 hereto, [Filed as Exhibit 4.1 to KU’s Form 8-K filed  on July 7, 2005, and incorporated by reference herein]                                                                                                                                                                        |
|--------|--------|--------|--------|--------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                         |
| 4.19a  |   |   |   | X      |   | Copy of Supplemental Indenture dated November 1, 2005, from Kentucky  Utilities Company to U.S. Bank National Association, which is a supplemental  instrument to Exhibit 4.12 hereto.   [Filed as Exhibit 4.1 to KU’s Form 8-K filed on November 17, 2005, and  incorporated by reference herein] |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                         |
| 4.20   |   |   |   | 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, 2003, and incorporated by reference herein]                                                            |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                         |
| 4.21   |   | 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, 2003, and  incorporated by reference herein]                                               |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                         |
| 4.22   |   | X      |   |   |   | Copy of Loan Agreement between LG&E and Fidelia Corporation,  dated January 15, 2004. [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 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 the year ended December 31,  2003, and incorporated by reference herein]                                       |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                         |
| 4.24   |   | 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,  2003, and incorporated by reference herein]                           |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                         |
| 4.25   |   |   |   | X      |   | Copy of Promissory Note from KU to Fidelia Corporation, dated as of November 24,  2003, in the amount of $33 million. [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]                       |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                         |
| 4.26   |   |   |   | X      |   | Copy of Promissory Note from KU to Fidelia Corporation, dated as of July 8,  2005. [Filed as Exhibit 4.4 to KU’s Current Report on Form 8-K  dated July 7, 2005, and incorporated by reference herein]                                                                                   |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                         |
| 4.26a  |   |   |   | X      |   | Copy of Loan Agreement between KU and Fidelia Corporation dated July  8, 2005 [Filed as Exhibit 4.3 to KU's Current Report on Form 8-K dated July  7, 2005, and incorporated by reference herein.]                                                                                                           |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                         |
| 4.27   |   |   |   | X      |   | Copy of Loan Agreement between KU and Fidelia Corporation, dated as  of 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]                                                    |

 

153

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| 4.28   |   |   |   | X      |   | Copy of Loan Agreement between KU and Fidelia Corporation, dated as  of December 19, 2005.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
|--------|--------|--------|--------|--------|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| 4.29   |   |   |   | X      |   | Copy of Promissory Note from KU to Fidelia Corporation, dated as of December 19,  2005, in the amount of $75 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 10.01above 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]                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| 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                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |

 

154

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|   |   |   |   |   |   | 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      |   | 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                                                                                                                                                                                                         |

 

155

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|   |   |   |   |   |   | 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 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]                                                                          |

 

156

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| 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]                                                                                                                  |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                                                                    |
| 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                                                                                                               |

 

157

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|   |   |   |   |   |   | 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 Representative Terms and Conditions for Stock Appreciation  Rights Issued as part of E.ON Group’s Stock Appreciation Rights  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,  2003, 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,  2003, 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,  2003, 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,  2003, and incorporated by reference herein]                                   |

 

158

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| 10.38  |   | 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]                        |
|--------|--------|--------|--------|--------|--------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                 |
| 10.39  |   | 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] |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                 |
| 10.40  |   | 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]                 |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                 |
| 10.41  |   | X      |   |   |   | Participation Agreement between LG&E and Illinois Municipal  Electric Agency, dated as of September 24, 1990. [Filed as Exhibit 10.42  to LG&E’s Annual Report on Form 10-K for the year ended December 31,  2004 and incorporated by reference herein]                                                                             |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                 |
| 10.42  |   | X      |   |   |   | Participation Agreement between LG&E and Indiana Municipal Power  Agency, dated as of February 1, 1993. [Filed as Exhibit 10.43 to  LG&E’s Annual Report on Form 10-K for the year ended December 31,  2004, and incorporated by reference herein]                                                                                  |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                 |
| 10.43  |   | X      |   | X      |   | Participation Agreement by and among LG&E and KU and Illinois  Municipal Electric Agency and Indiana Municipal Power Agency, dated as of February 9,  2004. [Filed as Exhibit 10.44 to LG&E and KU’s Annual Report on Form 10-K  for the year ended December 31, 2004, and incorporated by reference  herein]                       |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                 |
| 10.44  |   | X      |   | X      |   | Copy of Barge Transportation Agreement between LG&E, effective January 1,  2002, and KU, effective July 1, 2002, and Crounse Corporation. [Filed as  Exhibit 10.45 to LG&E and KU’s Annual Report on Form 10-K for  the year ended December 31, 2004, and incorporated by reference herein]                                    |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                                                                                                                 |
| 10.45  |   | X      |   | X      |   | Amendment No. 1 to Barge Transportation Agreement between                                                                                                                                                                                                                                                                                                       |

 

159

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|   |   |   |   |   |   | Louisville Gas and Electric Company and Kentucky Utilities Company  and Crounse Corporation, dated as of January 1, 2005.                                                                                                                                                |
|--------|--------|--------|--------|--------|--------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                          |
| 10.46  |   | X      |   | X      |   | * Copy of LG&E Energy LLC Nonqualified Savings Plan, effective January 1,  2005                                                                                                                                                                                      |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                          |
| 10.47  |   | X      |   | X      |   | * Executive Officer Salary Information.                                                                                                                                                                                                                                       |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                          |
| 10.48  |   | X      |   | X      |   | * Form of Representative Specimen Award under LG&E Energy  Long-Term Performance Unit Plan [Filed as Exhibit 10.47 to LG&E and  KU’s Annual Report on Form 10-K for the year ended December 31,  2004, and incorporated by reference herein] |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                          |
| 10.49  |   | X      |   | X      |   | * Form of Representative Specimen Award under E.ON Group Stock  Appreciation Rights Program [Filed as Exhibit 10.48 to LG&E and KU’s  Annual Report on Form 10-K for the year ended December 31, 2004,  and incorporated by reference herein]    |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                          |
| 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.                                                                                                                                                                                                                                                           |
|   |   |   |   |   |   |                                                                                                                                                                                                                                                                          |
| 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.                                                                                                                                                                                                                             |

 

ExecutiveCompensation Plans and Arrangements

 

Exhibits preceded by an asterisk(“*”) above are management contracts, compensation plans or arrangementsrequired to be identified pursuant to Item 15(a)(3) of form 10-K.

 

CertainAvailable Instruments

 

Pursuant to Item601(b)(4)(iii)(A) of Regulation S-K, certain instruments defining the rights ofholders of certain long-term debt of LG&E or KU have not been filed withthe Securities and Exchange Commission but will be furnished to the Commissionupon request.

 

160

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Schedule II

Louisville Gas and Electric Company

Schedule II - Valuation and QualifyingAccounts

For the Three Years Ended December 31, 2005

(Millions of $)

 
| ** **                                             | ** ** | **Other  Property  and  Investments** | ** ** | **Accounts  Receivable  (Uncollectible  Accounts)** | ** ** |
|--------------------------------------------------------|------------|---------------------------------------|------------|-----------------------------------------------------|------------|
|                                                   |       |                                  |       |                                                |       |
| Balance  December 31, 2002                             |       | $                                     | 0.1        |                                                | $          | 2.1 |   |
|                                                   |       |                                  |       |                                                |       |
| Additions:                                             |       |                                  |       |                                                |       |
| Charged to costs and expenses                          |       | —                                |       | 5.5                                                 |       |
|                                                   |       |                                  |       |                                                |       |
| Deductions:                                            |       |                                  |       |                                                |       |
| Net charges of nature for which reserves  were created |       | —                                |       | 4.1                                                 |       |
|                                                   |       |                                  |       |                                                |       |
| Balance  December 31, 2003                             |       | 0.1                                   |       | 3.5                                                 |       |
|                                                   |       |                                  |       |                                                |       |
| Additions:                                             |       |                                  |       |                                                |       |
| Charged to costs and expenses                          |       | —                                |       | 1.9                                                 |       |
|                                                   |       |                                  |       |                                                |       |
| Deductions:                                            |       |                                  |       |                                                |       |
| Net charges of nature for which reserves  were created |       | —                                |       | 4.6                                                 |       |
|                                                   |       |                                  |       |                                                |       |
| Balance  December 31, 2004                             |       | 0.1                                   |       | 0.8                                                 |       |
|                                                   |       |                                  |       |                                                |       |
| Additions:                                             |       |                                  |       |                                                |       |
| Charged to costs and expenses                          |       | —                                |       | 3.1                                                 |       |
|                                                   |       |                                  |       |                                                |       |
| Deductions:                                            |       |                                  |       |                                                |       |
| Net charges of nature for which reserves  were created |       | —                                |       | 2.8                                                 |       |
|                                                   |       |                                  |       |                                                |       |
| Balance December  31, 2005                             |       | $                                     | 0.1        |                                                | $          | 1.1 |   |

 

161

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**Schedule II**

 

Kentucky Utilities Company

Schedule II - Valuation and QualifyingAccounts

For the Three Years Ended December 31, 2005

(Millions of $)

 
| ** **                                             | ** ** | **Other  Property  and  Investments** | ** ** | **Accounts  Receivable  (Uncollectible  Accounts)** | ** ** |
|--------------------------------------------------------|------------|---------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                             | ** ** | ** **                            | ** ** | ** **                                          | ** ** |
| Balance  December 31, 2002                             |       | $                                     | 0.1        |                                                | $          | 0.8 |   |
|                                                   |       |                                  |       |                                                |       |
| Additions:                                             |       |                                  |       |                                                |       |
| Charged to costs and expenses                          |       | —                                |       | 1.5                                                 |       |
|                                                   |       |                                  |       |                                                |       |
| Deductions:                                            |       |                                  |       |                                                |       |
| Net charges of nature for which reserves  were created |       | —                                |       | 1.6                                                 |       |
|                                                   |       |                                  |       |                                                |       |
| Balance  December 31, 2003                             |       | 0.1                                   |       | 0.7                                                 |       |
|                                                   |       |                                  |       |                                                |       |
| Additions:                                             |       |                                  |       |                                                |       |
| Charged to costs and expenses                          |       | —                                |       | 1.2                                                 |       |
|                                                   |       |                                  |       |                                                |       |
| Deductions:                                            |       |                                  |       |                                                |       |
| Net charges of nature for which reserves  were created |       | —                                |       | 1.3                                                 |       |
|                                                   |       |                                  |       |                                                |       |
| Balance  December 31, 2004                             |       | 0.1                                   |       | 0.6                                                 |       |
|                                                   |       |                                  |       |                                                |       |
| Additions:                                             |       |                                  |       |                                                |       |
| Charged to costs and expenses                          |       | —                                |       | 2.3                                                 |       |
|                                                   |       |                                  |       |                                                |       |
| Deductions:                                            |       |                                  |       |                                                |       |
| Net charges of nature for which reserves  were created |       | —                                |       | 1.4                                                 |       |
|                                                   |       |                                  |       |                                                |       |
| Balance  December 31, 2005                             |       | $                                     | 0.1        |                                                | $          | 1.5 |   |

 

162

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**SIGNATURES**– LOUISVILLE GAS AND ELECTRIC COMPANY

 

Pursuant to the requirements of Section 13 or 15(d) of the SecuritiesExchange Act of 1934, the registrant has duly caused this report to be signedon its behalf by the undersigned, thereunto duly authorized.

 

 
|           | LOUISVILLE GAS AND ELECTRIC COMPANY |
|----------------|-------------------------------------|
|           | Registrant                          |
|           |                                |
| March 29, 2006 | /s/ S. Bradford Rives               |   |
| (Date)         | S. Bradford Rives                   |
|           | Chief Financial Officer             |

 

Pursuant to the requirements of the Securities Exchange Act of 1934,this report has been signed below by the following persons on behalf of theregistrant and in the capacities and on the date 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 29, 2006 |
|                | (Attorney-In-Fact)    |                                                            |       |     |   |
|                     |                       |                                                                 |            |          |  |  |

 

163

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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 29, 2006 | /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 29, 2006 |
|                | (Attorney-In-Fact)    |                                                            |       |     |   |
|                     |                       |                                                                 |            |          |  |  |

 

164

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