**UNITED STATES**

**SECURITIESAND 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, 2003** |
|                                                 |                                                                                                                  |
| **OR**                                               |
|                                                 |                                                                                                                  |
| **o**                                                | **TRANSITION REPORT PURSUANT TO  SECTION 13 OR 15(d) OF THE  SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)** |

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

 

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

 

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

 

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

 

As of June 30, 2003, the aggregate market value of the commonstock of each of Louisville Gas and Electric Company and Kentucky Utilities Companyheld by non-affiliates was $0.  As ofFebruary 27, 2004, Louisville Gas and Electric Company had 21,294,223shares of common stock outstanding, all held by LG&E Energy LLC.  Kentucky Utilities Company had 37,817,878shares of common stock outstanding, all held by LG&E Energy LLC.

 

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

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Not applicable.

 

 

----

 

**TABLEOF 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 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  and Related Stockholder Matters. |   |
| Item 6.       |   | Selected Financial Data. |   |
| Item 7.       |   | Management’s Discussion and Analysis of  Financial Condition and Results of Operation. |   |
|          |   | Louisville  Gas and Electric Company |   |
|          |   | Kentucky  Utilities Company |   |
| Item  7A.     |   | Quantitative  and Qualitative Disclosure 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. |   |
|          |   |   |   |
| **PART  III** |   |
|          |   |   |   |
| Item 10.      |   | Directors and Executive Officers of  Registrant (a). |   |
| Item 11.      |   | Executive Compensation (a). |   |
| Item 12.      |   | Security Ownership of Certain Beneficial  Owners and Management (a). |   |
| Item 13.      |   | Certain Relationships and Related  Transactions (a). |   |
| Item 14.      |   | Principal Accountant Fees and Services. |   |
|          |   |   |   |
| **PART IV**   |   |
|          |   |   |   |
| Item 15.      |   | Exhibits, Financial Statement Schedules,  and Reports on Form 8-K. |   |
| Signatures    |   |

 

----

(a) Incorporated by reference.

 

----

 

INDEX OF ABBREVIATIONS

 
| AFUDC               |   | Allowance for Funds Used During  Construction                |
|---------------------|--------|--------------------------------------------------------------|
| ARO                 |   | Asset Retirement Obligation                                  |
| Capital Corp.       |   | LG&E Capital Corp.                                       |
| Clean Air Act       |   | The Clean Air Act, as amended in 1990                        |
| CCN                 |   | Certificate of Public Convenience and  Necessity             |
| CT                  |   | Combustion Turbines                                          |
| CWIP                |   | Construction Work in Progress                                |
| DSM                 |   | Demand Side Management                                       |
| ECR                 |   | Environmental Cost Recovery                                  |
| EEI                 |   | Electric Energy, Inc.                                        |
| EITF                |   | Emerging Issues Task Force Issue                             |
| E.ON                |   | E.ON AG                                                      |
| EPA                 |   | U.S. Environmental Protection Agency                         |
| ESM                 |   | Earnings Sharing Mechanism                                   |
| F                   |   | Fahrenheit                                                   |
| FAC                 |   | Fuel Adjustment Clause                                       |
| FERC                |   | Federal Energy Regulatory Commission                         |
| FGD                 |   | Flue Gas Desulfurization                                     |
| FPA                 |   | Federal Power Act                                            |
| FT and FT-A         |   | Firm Transportation                                          |
| GSC                 |   | Gas Supply Clause                                            |
| IBEW                |   | International Brotherhood of Electrical  Workers             |
| IMEA                |   | Illinois Municipal Electric Agency                           |
| IMPA                |   | Indiana Municipal Power Agency                               |
| Kentucky Commission |   | Kentucky Public Service Commission                           |
| KIUC                |   | Kentucky Industrial Utility Consumers, Inc.                  |
| KU                  |   | Kentucky Utilities Company                                   |
| KU Energy           |   | KU Energy Corporation                                        |
| KU R                |   | KU Receivables LLC                                           |
| kV                  |   | Kilovolts                                                    |
| Kva                 |   | Kilovolt-ampere                                              |
| KW                  |   | Kilowatts                                                    |
| Kwh                 |   | Kilowatt hours                                               |
| LEM                 |   | LG&E Energy Marketing Inc.                               |
| LG&E            |   | Louisville Gas and Electric Company                          |
| LG&E Energy     |   | LG&E Energy LLC (as successor to  LG&E Energy Corp.) |
| LG&E R          |   | LG&E  Receivables LLC                                    |
| LG&E Services   |   | LG&E Energy Services Inc.                                |
| Mcf                 |   | Thousand Cubic Feet                                          |
| MGP                 |   | Manufactured Gas Plant                                       |
| MISO                |   | Midwest Independent Transmission System  Operator            |
| Mmbtu               |   | Million British thermal units                                |
| Moody’s        |   | Moody’s Investor Services, Inc.                         |
| Mw                  |   | Megawatts                                                    |
| Mwh                 |   | Megawatt hours                                               |
| NNS                 |   | No-Notice Service                                            |
| NOPR                |   | Notice of Proposed Rulemaking                                |
| NOx                 |   | Nitrogen Oxide                                               |
| OATT                |   | Open Access Transmission Tariff                              |
| OMU                 |   | Owensboro Municipal Utilities                                |
| OVEC                |   | Ohio Valley Electric Corporation                             |
| PBR                 |   | Performance-Based Ratemaking                                 |
| PJM                 |   | Pennsylvania, New Jersey, Maryland Interconnection           |
| Powergen            |   | Powergen Limited (formerly Powergen plc)                     |
| PUHCA               |   | Public Utility Holding Company Act of 1935                   |
| ROE                 |   | Return on Equity                                             |
| RTO                 |   | Regional Transmission Organization                           |

 

----

 
| S&P             |   | Standard & Poor’s Rating Services   |
|---------------------|--------|----------------------------------------------|
| SCR                 |   | Selective Catalytic Reduction                |
| SEC                 |   | Securities and Exchange Commission           |
| SERP                |   | Supplemental Employee Retirement Plan        |
| SFAS                |   | Statement of Financial Accounting Standards  |
| SIP                 |   | State Implementation Plan                    |
| SMD                 |   | Standard Market Design                       |
| SO2                 |   | Sulfur Dioxide                               |
| Tennessee Gas       |   | Tennessee Gas Pipeline Company               |
| Texas Gas           |   | Texas Gas Transmission LLC                   |
| TRA                 |   | Tennessee Regulatory Authority               |
| Trimble County      |   | LG&E’s Trimble County Unit 1        |
| USWA                |   | United Steelworkers of America               |
| Utility Operations  |   | Operations of LG&E and KU                |
| VDT                 |   | Value Delivery Team Process                  |
| Virginia Commission |   | Virginia State Corporation Commission        |
| Virginia Staff      |   | Virginia State Corporation  Commission Staff |
| WNA                 |   | Weather Normalization Adjustment             |

 

----

 

PART I

 

Item 1. Business.

##  

LG&E and KU are each subsidiaries of LG&E Energy.  On December 11, 2000, LG&E EnergyCorp., now LG&E Energy LLC, was acquired by Powergen plc, now known asPowergen Limited, for cash of approximately $3.2 billion and the assumption ofall of LG&E Energy’s debt.  As aresult of the acquisition, among other things, LG&E Energy became a whollyowned subsidiary of Powergen and, as a result, LG&E and KU became indirectsubsidiaries of Powergen.  Following theacquisition, Powergen became a registered holding company under PUHCA, andLG&E and KU, as subsidiaries of a registered holding company, becamesubject to additional regulation under PUHCA.

 

As a result of the Powergen acquisition and in order to comply withPUHCA, LG&E Services was formed as a subsidiary of LG&E Energyeffective on January 1, 2001. LG&E Services provides certain services to affiliated entities,including LG&E and KU, at cost as required under PUHCA.  On January 1, 2001, approximately 1,000employees, mainly from LG&E Energy, LG&E and KU, were moved to LG&EServices.

 

On July 1, 2002, E.ON, a German company, completed its acquisitionof Powergen plc (now Powergen Limited).  As a result, LG&E and KUbecame indirect subsidiaries of E.ON. E.ON had announced its pre-conditional cash offer of £5.1 billion ($7.3billion) for Powergen on April 9, 2001.

 

Following the purchase of Powergen by E.ON, E.ON became a registeredholding company under PUHCA.  As aresult, E.ON, its utility subsidiaries, including LG&E and KU, and certainof its non-utility subsidiaries are subject to extensive regulation by the SECunder PUHCA with respect to issuances and sales of securities, acquisitions andsales of certain utility properties, and intra-system sales of certain goodsand services.  In addition, PUHCAgenerally limits the ability of registered holding companies to acquireadditional public utility systems and to acquire and retain businessesunrelated to the utility operations of the holding company.  LG&E and KU believe that they haveadequate authority (including financing authority) under existing SEC ordersand regulations to conduct their business. LG&E and KU will seek additional authorization when necessary.

 

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

 

The utility operations (LG&E and KU) of LG&E Energy havecontinued their separate identities and continue to serve customers inKentucky, Virginia and Tennessee under their existing names.  The preferred stock and debt securities ofLG&E and KU were not affected by these transactions resulting in LG&E’sand KU’s obligations to continue to file SEC reports.

 

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

 

1

----

 

LOUISVILLE GAS AND ELECTRIC COMPANY

 

General

 

LG&E, incorporated in 1913 in Kentucky, is a regulated publicutility that supplies natural gas to approximately 312,000 customers andelectricity to approximately 384,000 customers in Louisville and adjacent areasin Kentucky.  LG&E’s service areacovers approximately 700 square miles in 17 counties and has an estimatedpopulation of one million.  Included inthis area is the Fort Knox Military Reservation, to which LG&E transportsgas and provides electric service, but which maintains its own distributionsystems.  LG&E also provides gasservice in limited additional areas. LG&E’s coal-fired electric generating plants, all equipped withsystems to reduce sulfur dioxide emissions, produce most of LG&E’selectricity.  The remainder is generatedby a hydroelectric power plant and combustion turbines.  Underground natural gas storage fields helpLG&E provide economical and reliable gas service to customers.  See Item 2, Properties.

 

LG&E has one wholly owned consolidated subsidiary, LG&E R.LG&E R is a special purpose entity formed in September 2000 to enterinto accounts receivable securitization transactions with LG&E whichcommenced in February 2001. LG&E completed its accounts receivable securitization arrangementsinvolving LG&E R in January 2004 and LG&E R is currently inactive.

 

For the year ended December 31, 2003, 70% of total operatingrevenues were derived from electric operations and 30% from gasoperations.  Electric and gas operatingrevenues and the percentages by class of service on a combined basis for thisperiod were as follows:

 
| **(in thousands)**             |   | **Electric** |    | **Gas** |   | **Combined** |   | **% Combined** |      |
|--------------------------------|--------|--------------|---------|---------|--------|--------------|--------|----------------|-----------|
| Residential                    |   | $            | 223,404 |    | $      | 198,881      |   | $              | 422,285   |   | 48 | % |
| Commercial                     |   | 187,500      |    | 78,280  |   | 265,780      |   | 30             | %         |
| Industrial                     |   | 111,535      |    | 13,812  |   | 125,347      |   | 14             | %         |
| Public authorities             |   | 58,493       |    | 13,745  |   | 72,238       |   | 8              | %         |
| Total retail                   |   | 580,932      |    | 304,718 |   | 885,650      |   | 100            | %         |
| Wholesale sales                |   | 169,782      |    | 12,278  |   | 182,060      |   |           |      |
| Gas transported – net     |   | —       |    | 6,046   |   | 6,046        |   |           |      |
| Provision for rate collections |   | (412         | )       | —  |   | (412         | )      |           |      |
| Miscellaneous                  |   | 17,886       |    | 2,291   |   | 20,177       |   |           |      |
| Total                          |   | $            | 768,188 |    | $      | 325,333      |   | $              | 1,093,521 |   |   |   |

 

See Note 13 of LG&E’s Notes to Financial Statements under Item 8for financial information concerning segments of business for the three yearsended December 31, 2003.

 

ElectricOperations

 

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

 
|                                        |   | **2003** |    | **2002** |   | **2001** |   |
|---------------------------------------------|--------|----------|---------|----------|--------|----------|--------|
| ELECTRIC OPERATING REVENUES (in thousands): |   |     |    |     |   |     |   |
| Residential                                 |   | $        | 223,404 |     | $      | 232,527  |   | $ | 205,038 |   |
| Commercial                                  |   | 187,500  |    | 185,306  |   | 170,801  |   |
| Industrial                                  |   | 111,535  |    | 111,988  |   | 103,988  |   |
| Public authorities                          |   | 58,493   |    | 57,762   |   | 53,494   |   |
| Total retail                                |   | 580,932  |    | 587,583  |   | 533,321  |   |
| Wholesale sales                             |   | 169,782  |    | 120,552  |   | 127,253  |   |
| Provision for rate collections (refunds)    |   | (412     | )       | 11,656   |   | 1,588    |   |
| Miscellaneous                               |   | 17,886   |    | 16,251   |   | 11,610   |   |
| Total                                       |   | $        | 768,188 |     | $      | 736,042  |   | $ | 673,772 |   |
|                                        |   |     |    |     |   |     |   |
| ELECTRIC SALES (Thousands of Mwh):          |   |     |    |     |   |     |   |
| Residential                                 |   | 3,835    |    | 4,036    |   | 3,782    |   |
| Commercial                                  |   | 3,482    |    | 3,493    |   | 3,395    |   |
| Industrial                                  |   | 2,936    |    | 3,028    |   | 2,976    |   |
| Public authorities                          |   | 1,251    |    | 1,253    |   | 1,224    |   |
| Total retail                                |   | 11,504   |    | 11,810   |   | 11,377   |   |
| Wholesale sales                             |   | 7,678    |    | 6,387    |   | 5,990    |   |
| Total                                       |   | 19,182   |    | 18,197   |   | 17,367   |   |

 

2

----

 

LG&E uses efficient coal-fired boilers, fully equipped with sulfurdioxide removal systems, to generate most of its electricity.  LG&E’s weighted-average system-wideemission rate for sulfur dioxide in 2003 was approximately 0.6 lbs./Mmbtu ofheat input, with every generating unit below its emission limit established bythe Kentucky Division for Air Quality.

 

LG&E set an annual peak load of 2,583 Mw on Wednesday,August 27, 2003, when the temperature reached 92 degrees F in Louisville.

 

The electric utility business is affected by seasonal weatherpatterns.  As a result, operatingrevenues (and associated operating expenses) are not generated evenly throughoutthe year.  See LG&E’s Results ofOperations under Item 7.

 

LG&E currently maintains a 13% – 15% reserve margin range.  At December 31, 2003, LG&E ownedsteam and combustion turbine generating facilities with a net summer capabilityof 2,878 Mw and an 80 Mw nameplate-rated hydroelectric facility on the OhioRiver with a summer capability rate of 48 Mw. See Item 2, Properties.  LG&Ealso obtains power from other utilities under bulk power purchase andinterchange contracts.  AtDecember 31, 2003, LG&E’s system net summer capability, includingpurchases from others and excluding the hydroelectric facility, was 3,032Mw.  See Item 2, Properties.

 

LG&E and 11 other electric utilities are participating owners ofOVEC located in Piketon, Ohio. LG&E’s investment in OVEC is the equivalent of 4.9% of OVEC’s commonstock.  OVEC owns and operates two powerplants that burn coal to generate electricity, Kyger Creek Station in Ohio andClifty Creek Station in Indiana. LG&E’s share is 7%, representing approximately 155 Mw of generationcapacity.

 

LG&E and KU are founding members of the MISO.  Membership was obtained in 1998 in responseto and consistent with federal policy initiatives. It began commercialoperations in February 2002.  Atthat time, as members of the MISO, LG&E and KU turned over operationalcontrol of its high-voltage transmission facilities (100 kV and greater), whilecontinuing to control and operate the lower voltage transmission subject to theterms and conditions of the MISO.  TheMISO currently controls over 100,000 miles of transmission over 1.1 millionsquare miles located in the northern Midwest between Manitoba, Canada andKentucky.  In September 2002, FERCgranted a 12.88% ROE on transmission facilities for LG&E, KU and the restof the MISO owners. As a transmission-owning member of the MISO, LG&E andKU also incur administrative costs through MISO Schedule 10.  The MISO uses Schedule 10 as a means torecover operational and capital costs for providing system operator services toits members.  For discussion of currentMISO matters, see Rates and Regulation for LG&E under Item 7 and Note 3 ofLG&E’s Notes to Financial Statements under Item 8.

 

LG&E also has agreements with a number of entities throughout theUnited States for the purchase and/or sale of capacity and energy and for theutilization of their bulk transmission system.

 

3

----

 

Gas Operations

 

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

 
|                                   |   | **2003** |    | **2002** |   | **2001** |   |
|----------------------------------------|--------|----------|---------|----------|--------|----------|--------|
| GAS OPERATING REVENUES (in thousands): |   |     |    |     |   |     |   |
| Residential                            |   | $        | 198,881 |     | $      | 160,733  |   | $ | 177,387 |   |
| Commercial                             |   | 78,280   |    | 61,036   |   | 70,296   |   |
| Industrial                             |   | 13,812   |    | 10,232   |   | 15,750   |   |
| Public authorities                     |   | 13,745   |    | 11,197   |   | 13,223   |   |
| Total retail                           |   | 304,718  |    | 243,198  |   | 276,656  |   |
| Wholesale sales                        |   | 12,278   |    | 16,384   |   | 5,702    |   |
| Gas transported – net             |   | 6,046    |    | 6,232    |   | 6,042    |   |
| Miscellaneous                          |   | 2,291    |    | 1,879    |   | 2,375    |   |
| Total                                  |   | $        | 325,333 |     | $      | 267,693  |   | $ | 290,775 |   |
|                                   |   |     |    |     |   |     |   |
| GAS SALES (Millions of cu. ft.):       |   |     |    |     |   |     |   |
| Residential                            |   | 23,192   |    | 22,124   |   | 20,429   |   |
| Commercial                             |   | 9,652    |    | 9,074    |   | 8,587    |   |
| Industrial                             |   | 1,880    |    | 1,783    |   | 2,160    |   |
| Public authorities                     |   | 1,746    |    | 1,747    |   | 1,681    |   |
| Total retail                           |   | 36,470   |    | 34,728   |   | 32,857   |   |
| Wholesale sales                        |   | 2,119    |    | 5,345    |   | 1,882    |   |
| Gas transported                        |   | 13,683   |    | 13,939   |   | 13,108   |   |
| Total                                  |   | 52,272   |    | 54,012   |   | 47,847   |   |

 

The gas utility business is affected by seasonal weather patterns.  As a result, operating revenues (andassociated operating expenses) are not generated evenly throughout theyear.  While natural gas usage patternsare seasonal, LG&E received approval from the Kentucky Commission for aWeather Normalization Adjustment (“WNA”) mechanism.  The WNA mechanism adjusts the non-gas base portion of the naturalgas billings of residential and commercial customers to normal temperaturesduring the heating season months of December through April, somewhatmitigating the effect of weather extremes on gas revenue.  LG&E has requested, and the KentuckyCommission has approved an extension of the current WNA mechanism throughApril 30, 2006.  See LG&E’sResults of Operations under Item 7.

 

LG&E has five underground natural gas storage fields that helpprovide economical and reliable gas service to ultimate consumers.  By using gas storage facilities, LG&Eavoids the costs associated with typically more expensive pipelinetransportation capacity to serve peak winter space-heating loads.  LG&E stores gas in the summer season forwithdrawal in the subsequent winter heating season.  Without its storage capacity, LG&E would be forced to buyadditional gas and pipeline transportation services during the winter monthswhen customer demand increases and when the prices for gas supply andtransportation services are typically at their highest.  Currently, LG&E buys competitivelypriced gas from several large suppliers under contracts of varyingduration.  LG&E’s undergroundstorage facilities, in combination with its purchasing practices, enable it tooffer gas sales service at rates lower than state and national averages.  At December 31, 2003, LG&E had aninventory balance of gas stored underground of approximately 12.9 million Mcfvalued at approximately $69.9 million.

 

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

 

4

----

 

The all-time maximum day gas sendout of 545,000 Mcf occurred on Sunday,January 20, 1985, when the average temperature for the day was -10 degreesF.  During 2003, maximum day gas sendoutwas approximately 525,000 Mcf, occurring on January 23, 2003, when theaverage temperature for the day was 7 degrees F.  Supply on that day consisted of approximately 240,000 Mcf frompurchases, approximately 200,000 Mcf delivered from underground storage, andapproximately 85,000 Mcf transported for industrial customers.  For a further discussion, see Gas Supplyunder Item 1.

 

Rates andRegulation

 

Following the purchase of Powergen by E.ON, E.ON became a registeredholding company under PUHCA.  As aresult, E.ON, its utility subsidiaries, including LG&E, and certain of itsnon-utility subsidiaries are subject to extensive regulation by the SEC underPUHCA with respect to issuances and sales of securities, acquisitions and salesof certain utility properties, and intra-system sales of certain goods andservices.  In addition, PUHCA generallylimits the ability of registered holding companies to acquire additional publicutility systems and to acquire and retain businesses unrelated to the utilityoperations of the holding company. LG&E believes that it has adequate authority (including financingauthority) under existing SEC orders and regulations to conduct itsbusiness.  LG&E will seek additionalauthorization when necessary.

 

The Kentucky Commission has regulatory jurisdiction over LG&E’sretail rates and service, and over the issuance of certain of itssecurities.  The Kentucky Commission hasthe ability to examine the rates LG&E charges its retail customers at anytime.  FERC has classified LG&E as a“public utility” as defined in the FPA. The Department of Energy and FERC havejurisdiction under the FPA over certain electric utility facilities andoperations, wholesale sale of power and related transactions, accountingpractices of LG&E, and in certain other respects as provided in the FPA.

 

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

 

LG&E’s retail electric rates contain 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 requires public hearings at six-month intervalsto examine past fuel adjustments, and at two-year intervals to review pastoperations of the fuel clause and transfer of the then current fuel adjustmentcharge or credit to the base charges. The Kentucky Commission also requires that electric utilities, includingLG&E, file certain documents relating to fuel procurement and the purchaseof power and energy from other utilities.

 

LG&E’s retail electric rates are subject to an ESM.  The ESM, initially in place for three yearsbeginning in 2000, sets an upper and lower point for rate of return on equity,whereby if LG&E’s rate of return for the calendar year falls within therange of 10.5% to 12.5%, no action is necessary.  If earnings are above the upper limit, the excess earnings areshared 40% with ratepayers and 60% with shareholders; if earnings are below thelower limit, the earnings deficiency is recovered 40% from ratepayers and 60%from shareholders.  By order of theKentucky Commission, rate changes prompted by the ESM filing go into effect inApril of each year subject to a balancing adjustment in successiveperiods.

 

In November 2002, LG&E filed a revised ESM tariff whichproposed continuance of the existing ESM through 2005.  In addition, the Kentucky Commission initiateda focused management audit to review the ESM plan and reassess itsreasonableness, and recently concluded discovery in the case.  LG&E and interested parties had theopportunity to provide recommendations for modification and continuance of theESM or other forms of alternative or incentive regulation.  Continuance of the ESM is still beingdeliberated by the Kentucky Commission and a final order is not expected untilthe second quarter of 2004.  The ESMtariff remains in effect pending

 

5

----

 the resolution of the case.

 

LG&E’s retail rates contain an ECR surcharge which recovers certaincosts incurred by LG&E that are required to comply with the Clean Air Actand other environmental regulations. See Note 3 of LG&E’s Notes to Financial Statements under Item8.

 

LG&E’s gas rates contain a GSC, whereby increases or decreases inthe cost of gas supply are reflected in LG&E’s rates, subject to approvalby the Kentucky Commission.  The GSC procedureprescribed by order of the Kentucky Commission provides for quarterly rateadjustments to reflect the expected cost of gas supply in that quarter.  In addition, the GSC contains a mechanismwhereby any over- or under-recoveries of gas supply cost from prior quarterswill be refunded to or recovered from customers through the adjustment factordetermined for subsequent quarters.

 

Integrated resource planning regulations in Kentucky require LG&Eand the other major utilities to make triennial filings with the KentuckyCommission of various historical and forecasted information relating to load,capacity margins and demand-side management techniques.  LG&E filed its most recent integratedresource plan (“IRP”) in October 2002. The Kentucky Commission issued its Staff Report and ordered the caseclosed in December 2003 with no significant findings.  The next IRP is due April 2005 and willincorporate the recommendations from the Staff Report regarding the 2002 IRP.

 

In December 2003, LG&E filed applications with the KentuckyCommission requesting adjustments in LG&E’s electric and gas rates.  LG&E asked for general adjustments inelectric and gas rates based on the twelve month test year ended September 30,2003.  The revenue increases requestedwere $63.8 million for electric and $19.1 million for gas.  The Kentucky Commission has suspended theeffective date of the proposed new tariffs for five months, so that the ratesmay go into effect subject to refund by July 1, 2004.  The Kentucky Commission established aprocedural schedule for the cases pertaining to discovery andhearings.  Hearings are scheduled in May2004.  LG&E expects the KentuckyCommission to issue orders in the cases before new rates go into effectJuly 1, 2004.

 

For discussion of current regulatory matters, see Rates and Regulationfor LG&E under Item 7 and Note 3 of LG&E’s Notes to FinancialStatements under Item 8.

 

ConstructionProgram and Financing

 

LG&E’s construction program is designed to ensure that there willbe adequate capacity and reliability to meet the electric and gas needs of itsservice area.  These needs arecontinually being reassessed and appropriate revisions are made, whennecessary, in construction schedules. LG&E’s estimates of its construction expenditures can varysubstantially due to numerous items beyond LG&E’s control, such as changesin interest rates, economic conditions, construction costs, and newenvironmental or other governmental laws and regulations.

 

During the five years ended December 31, 2003, 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 additionsduring this period amounted to approximately 27% of total utility plant atDecember 31, 2003, and consisted of $870 million for electric propertiesand $155 million for gas properties. Gross retirements during the same period were $116 million, consistingof $80 million for electric properties and $36 million for gas properties.

 

6

----

 

Coal Supply

 

Coal-fired generating units provided over 98% of LG&E’s netkilowatt-hour generation for 2003.  Theremaining net generation for 2003 was provided by natural gas and oil-fueledcombustion turbine peaking units and a hydroelectric plant.  Coal is expected to be the predominant fuelused by LG&E in the foreseeable future, with natural gas and oil being usedfor peaking capacity and flame stabilization in coal-fired boilers or inemergencies.  LG&E has no nucleargenerating units and 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.  Reliability of coal deliveries can beaffected from time to time by a number of factors, including fluctuations indemand, coal mine labor issues and other supplier or transporter operatingdifficulties.

 

LG&E believes there are adequate reserves available to supply itsexisting base-load generating units with the quantity and quality of coalrequired for those units throughout their useful lives.  LG&E intends to meet a portion of itscoal requirements with three-year or shorter contracts.  As part of this strategy, LG&E willcontinue to negotiate replacement contracts as contracts expire.  LG&E does not anticipate any problemsnegotiating new contracts for future coal needs.  The balance of coal requirements will be met through spotpurchases.  LG&E had a coalinventory of approximately 1.04 million tons, or a****53-day supply, on hand atDecember 31, 2003.

 

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

 

Coal is delivered to LG&E’s Mill Creek plant by rail and barge,Trimble County plant by barge and Cane Run plant by rail.

 

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

 
|                               |   | **2003** |   | **2002** |   | **2001** |   |
|------------------------------------|--------|----------|--------|----------|--------|----------|--------|
| Per ton                            |   | $        | 25.56  |     | $      | 25.30    |   | $ | 21.27 |   |
| Per Mmbtu                          |   | $        | 1.12   |     | $      | 1.11     |   | $ | .93 |   |
| Spot purchases as % of all sources |   | 1        | %      | 2        | %      | 3        | %      |

 

A slight increase in the delivered cost of coal is expected during 2004due to multi-year contracts signed in 2002. This slight increase is partially offset by lower prices negotiated inmore recent contracts signed for 2004.

 

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

 

LG&E transports on the Texas Gas system under Rate SchedulesNo-Notice Service (“NNS”) and Firm

 

7

----

 

Transportation (“FT”) service. During the winter months, LG&E has 184,900 Mmbtu/day in NNS and36,000 Mmbtu/day in FT service. LG&E’s summer NNS levels are 60,000 Mmbtu/day and its summer FTlevels are 54,000 Mmbtu/day.  Each ofthese NNS and FT agreements with Texas Gas are subject to termination byLG&E in equal portions during 2005, 2006, and 2008.  For January 2004 only, LG&Econtracted for short-term firm transportation service from Texas Gas under RateSchedule STF in the amount of 15,000 Mmbtu/day.  LG&E also transports on the Tennessee Gas system underTennessee Gas’s Rate Schedule FT-A. LG&E’s contract levels with Tennessee Gas are 51,000 Mmbtu/daythroughout the year.  The FT-A agreementwith Tennessee Gas is subject to termination by LG&E during 2007.

 

LG&E also has a portfolio of supply arrangements of various termswith a number of suppliers designed to meet its firm sales obligations.  These gas supply arrangements includepricing provisions that are market-responsive. These firm gas supplies, intandem with pipeline transportation services, provide the reliability andflexibility necessary to serve LG&E’s gas customers.

 

LG&E owns and operates five underground gas storage fields with acurrent working gas capacity of approximately 15.1 million Mcf.  Gas is purchased and injected into storageduring the summer season when natural gas prices are typically lower, and isthen withdrawn to supplement pipeline supplies to meet the gas-system loadrequirements during the winter heating season. See Gas Operations under Item 1.

 

The estimated maximum deliverability from storage during the early partof the heating season is typically approximately 373,000 Mcf/day.  Deliverability decreases during the latterportion of the heating season as the storage inventory is reduced by seasonalwithdrawals.

 

The average cost per Mcf of natural gas purchased by LG&E was $6.30in 2003, $4.19 in 2002, and $5.27 in 2001. Natural gas prices in the unregulated wholesale market generally haveincreased significantly over the last few years beginning in 2000.  These increases in natural gas prices,caused in part by decreased natural gas production, decreased liquidity in themarketplace, and increased demand for natural gas as a fuel for electricgeneration have been significantly affected by changing national gas storageinventory levels.  LG&E relies uponstorage to mitigate the price volatility to which customers might otherwise beexposed.

 

EnvironmentalMatters

 

Protection of the environment is a major priority for LG&E.  Federal, state, and local regulatoryagencies have issued LG&E permits for various activities subject to airquality, water quality, and waste management laws and regulations.  For the five-year period ending with 2003,expenditures for pollution control facilities represented $269.9 million or 26%of total construction expenditures. LG&E estimates that construction expenditures for the installationof NOx control equipment from 2004 through 2005 will be approximately $5.1million.  For a discussion ofenvironmental matters, see Rates and Regulation for LG&E under Item 7 andNote 11 of LG&E’s Notes to Financial Statements under Item 8.

 

Competition

 

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

 

At this time, neither theKentucky General Assembly nor the Kentucky Commission has adopted or approved aplan or timetable for retail electric industry 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.

 

8

----

 

KENTUCKY UTILITIES COMPANY

 

General

 

KU, incorporated in Kentucky in 1912 and incorporated in Virginia in1991, is a regulated public utility engaged in producing, transmitting andselling electric energy.  KU provideselectric service to approximately 482,000 customers in over 600 communities andadjacent suburban and rural areas in 77 counties in central, southeastern andwestern Kentucky, to approximately 30,000 customers in 5****counties in southwesternVirginia and to less than 10 customers in Tennessee.  In Virginia, KU operates under the name Old Dominion PowerCompany.  KU operates under appropriatefranchises in substantially all of the 161 Kentucky incorporated municipalitiesserved.  No franchises are required inunincorporated Kentucky or Virginia communities.  The lack of franchises is not expected to have a material adverseeffect on KU’s operations**. **KUalso sells wholesale electric energy to 12 municipalities.

 

KU has one wholly owned consolidated subsidiary, KU R.  KU R is a special purpose entity formed inSeptember 2000 to enter into accounts receivable securitizationtransactions with KU which commenced in February 2001.  KU completed its accounts receivablesecuritization arrangements involving KU R in January 2004 and KU R iscurrently inactive.

 

ElectricOperations

 

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

 
|                                        |   | **2003** |    | **2002** |   | **2001** |   |
|---------------------------------------------|--------|----------|---------|----------|--------|----------|--------|
| ELECTRIC OPERATING REVENUES (in thousands): |   |     |    |     |   |     |   |
| Residential                                 |   | $        | 278,461 |     | $      | 274,660  |   | $ | 243,630 |   |
| Commercial                                  |   | 189,113  |    | 178,694  |   | 165,253  |   |
| Industrial                                  |   | 175,601  |    | 163,372  |   | 147,062  |   |
| Mine power                                  |   | 29,584   |    | 28,664   |   | 27,902   |   |
| Public authorities                          |   | 66,452   |    | 62,490   |   | 58,725   |   |
| Total retail                                |   | 739,211  |    | 707,880  |   | 642,572  |   |
| Wholesale sales                             |   | 138,003  |    | 117,252  |   | 164,430  |   |
| Provision for rate collections (refunds)    |   | (8,534   | )       | 15,481   |   | (199     | )      |
| Miscellaneous                               |   | 23,098   |    | 21,051   |   | 13,918   |   |
| Total                                       |   | $        | 891,778 |     | $      | 861,664  |   | $ | 820,721 |   |
|                                        |   |     |    |     |   |     |   |
| ELECTRIC SALES (Thousands of Mwh):          |   |     |    |     |   |     |   |
| Residential                                 |   | 6,001    |    | 6,198    |   | 5,678    |   |
| Commercial                                  |   | 4,210    |    | 4,161    |   | 3,990    |   |
| Industrial                                  |   | 5,110    |    | 4,975    |   | 4,717    |   |
| Mine power                                  |   | 722      |    | 766      |   | 770      |   |
| Public authorities                          |   | 1,551    |    | 1,533    |   | 1,481    |   |
| Total retail                                |   | 17,594   |    | 17,633   |   | 16,636   |   |
| Wholesale sales                             |   | 5,591    |    | 4,794    |   | 6,634    |   |
| Total                                       |   | 23,185   |    | 22,427   |   | 23,270   |   |

 

KU’s weighted-average system-wide emission rate for sulfur dioxide in2003 was approximately****1.4****lbs./Mmbtu****of heat input, with everygenerating unit below its emission limit established by the Kentucky Divisionfor Air Quality.

 

KU set an all-time record local peak load of 3,944 Mw on Monday,January 27, 2003, when the temperature

 

9

----

 

was -1 degree F.

 

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

 

KU currently maintains a 13% -15% reserve margin range.  At December 31, 2003, KU owned steamand combustion turbine generating facilities with a net summer capability of4,044 Mw and a 28 Mw nameplate-rated hydroelectric facility with a summercapability of 24 Mw.  See Item 2,Properties.  KU obtains power from otherutilities under bulk power purchase and interchange contracts. AtDecember 31, 2003, KU’s system net summer capability, including purchasesfrom others and excluding the hydroelectric facility, was 4,545 Mw.

 

Under a contract expiring in 2020 with OMU, KU has agreed to purchasefrom OMU the surplus output of the 142-Mw and 265-Mw generating units at OMU’sElmer Smith station.  Purchases underthe contract are made under a contractual formula resulting in costs which areexpected to be comparable to the cost of other power purchased or generated byKU.  Such power equated to approximately10% of KU’s net generation system output during 2003.  See Note 11 ofKU’s Notes to Financial Statements under Item 8.

 

KU owns 20% of the common stock of EEI, which owns and operates a1,000-Mw generating station in southern Illinois.  KU is entitled to take 20% of the available capacity of thestation.  Purchases from EEI are madeunder a contractual formula which has resulted in costs which were and areexpected to be comparable to the cost of other power purchased or generated byKU.  Such power equated to approximately9% of KU’s net generation system output in 2003.  See Note 11 ofKU’s Notes to Financial Statements under Item 8.

 

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

 

KU and LG&E are founding members of the MISO.  Membership was obtained in 1998 in responseto and consistent with federal policy initiatives.  It began commercial operations in February 2002.  At that time, as members of the MISO, KU andLG&E turned over operational control of its high-voltage transmissionfacilities (100 kV and greater), while continuing to control and operate thelower voltage transmission subject to the terms and conditions of theMISO.  The MISO currently controls over100,000 miles of transmission over 1.1 million square miles located in thenorthern Midwest between Manitoba, Canada and Kentucky.  In September 2002, FERC granted a12.88% ROE on transmission facilities for LG&E, KU and the rest of the MISOowners.  As a transmission-owning memberof the MISO, KU and LG&E also incur administrative costs through MISOSchedule 10.  The MISO usesSchedule 10 as a means to recover operational and capital costs forproviding system operator services to its members.  For discussion of current MISO matters, see Rates and Regulationfor KU under Item 7 and Note 3 of KU’s Notes to Financial Statements under Item8.

 

KU also has agreements with a number of entities throughout the UnitedStates for the purchase and/or sale of capacity and energy and for theutilization of their bulk transmission systems.

 

Rates andRegulation

 

Following the purchase of Powergen by E.ON, E.ON became a registeredholding company under PUHCA.  As aresult, E.ON, its utility subsidiaries, including KU, and certain of itsnon-utility subsidiaries are subject to extensive regulation by the SEC underPUHCA with respect to issuances and sales of securities, acquisitions

 

10

----

 

and sales of certain utility properties, and intra-system sales ofcertain goods and services.  Inaddition, PUHCA generally limits the ability of registered holding companies toacquire additional public utility systems and to acquire and retain businessesunrelated to the utility operations of the holding company.  KU believes that it has adequate authority(including financing authority) under existing SEC orders and regulations toconduct its business.  KU will seekadditional authorization when necessary.

 

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 $225,000) from which KU served five customers atDecember 31, 2003, KU is subject to the jurisdiction of the TRA. FERC hasclassified KU as a “public utility” as defined in the FPA.  The Department of Energy and FERC havejurisdiction under the FPA over certain of the electric utility facilities andoperations, wholesale sale of power and related transactions, accountingpractices of KU, and in certain other respects as provided in the FPA.

 

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

 

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

 

KU’s Kentucky retail electric rates are subject to an ESM.  The ESM, initially in place for three yearsbeginning in 2000, sets an upper and lower point for rate of return on equity,whereby if KU’s rate of return for the calendar year falls within the range of10.5% to 12.5%, no action is necessary. If earnings are above the upper limit, the excess earnings are shared40% with ratepayers and 60% with shareholders; if earnings are below the lowerlimit, the earnings deficiency is recovered 40% from ratepayers and 60% fromshareholders**. **By order of theKentucky Commission, rate changes prompted by the ESM filing go into effect inApril of each year subject to a balancing adjustment in successiveperiods.

 

In November 2002, KU filed a revised ESM tariff which proposedcontinuance of the existing ESM through 2005. In addition, the Kentucky Commission initiated a focused managementaudit to review the ESM plan and reassess its reasonableness, and recentlyconcluded discovery in the case.  KU andinterested parties had the opportunity to provide recommendations formodification and continuance of the ESM or other forms of alternative orincentive regulation.  Continuance ofthe ESM is still being deliberated by the Kentucky Commission and a final orderis not expected until the second quarter of 2004.  The ESM tariff remains in effect pending the resolution of thecase.

 

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

 

Integrated resource planning regulations in Kentucky require KU and theother major utilities to make triennial filings with the Kentucky Commission ofvarious historical and forecasted information relating to load, capacity

 

11

----

 

margins and demand-side management techniques.  KU filed its most recent integrated resourceplan (“IRP”) in October 2002.  TheKentucky Commission issued its Staff Report and ordered the case closed inDecember 2003 with no significant findings.  The next IRP is due April 2005 and will incorporate therecommendations from the Staff Report regarding the 2002 IRP.

 

The Commonwealth of Virginia passed the Virginia Electric UtilityRestructuring Act in 1999.  This actgives Virginia customers a choice for energy services.  The change was phased in gradually betweenJanuary 2002 and January 2004. In 2002, KU filed prospective unbundled rate schedules which included acap at current levels from January 2002 through June 2007.  The Virginia Commission granted KU a waiverfrom retail choice and the associated rate filings through December 2004.  Additionally, in March 2003, the General Assembly of Virginiaamended and reenacted Section 56-580 of the Code of Virginia with languagethat effectively exempts all KU Virginia service territory from retail choiceand the associated rate filings until such time as retail choice is offered toother customers in KU’s other service territories.

 

In December 2003, KU filed an application with the KentuckyCommission requesting an adjustment in KU’s electric rates.  KU asked for a general adjustment inelectric rates based on the twelve month test year ended September 30,2003.  The revenue increase requestedwas $58.3 million.  The KentuckyCommission has suspended the effective date of the proposed new tariffs forfive months, so that the rates may go into effect subject to refund byJuly 1, 2004.  The KentuckyCommission established a procedural schedule for the case pertaining todiscovery and a hearing.  The hearing isscheduled in May 2004.  KU expects theKentucky Commission to issue an order in the case before new rates go intoeffect July 1, 2004.

 

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

 

ConstructionProgram and Financing

 

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

 

During the five years ended December 31, 2003, 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 additionsduring this period amounted to approximately 28% of total utility plant atDecember 31, 2003.  Grossretirements during the same period were $90 million.

 

Coal Supply

 

Coal-fired generating units provided over 98% of KU’s net kilowatt-hourgeneration for 2003.  The remaining netgeneration for 2003 was provided by natural gas and oil-fueled combustionturbine peaking units and hydroelectric plants.  Coal is expected to be the predominant fuel used by KU in theforeseeable future, with natural gas and oil being used for peaking capacityand flame stabilization in coal-fired boilers or in emergencies.  KU has no nuclear generating units and hasno plans to build any in the foreseeable future.

 

12

----

 

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

 

KU believes there are adequate reserves available to supply itsexisting base-load generating units with the quantity and quality of coalrequired for those units throughout their useful lives.  KU intends to meet a portion of its coalrequirements with three-year or shorter contracts.  As part of this strategy, KU will continue to negotiatereplacement contracts as contracts expire. KU does not anticipate any problems negotiating new contracts for futurecoal needs.  The balance of coalrequirements will be met through spot purchases.  KU had a coal inventory of approximately 1.2 million tons, or a60-day supply, on hand at December 31, 2003.

 

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

 

Coal for Ghent is delivered by barge. Deliveries to the Tyrone and Green River locations are by truck.  Delivery to E.W. Brown is by rail.

 

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

 
|                               |   | **2003** |   | **2002** |   | **2001** |   |
|------------------------------------|--------|----------|--------|----------|--------|----------|--------|
|                               |   |     |   |     |   |     |   |
| Per ton                            |   | $        | 34.57  |     | $      | 31.44    |   | $ | 27.84 |   |
| Per Mmbtu                          |   | $        | 1.47   |     | $      | 1.35     |   | $ | 1.20 |   |
| Spot purchases as % of all sources |   | 11       | %      | 18       | %      | 44       | %      |

 

KU’s historical average cost of coal purchased is higher thanLG&E’s due to the lower sulfur content of the coal KU purchases for use atits Ghent plant and higher cost to transport coal to the E.W. Brown plant. Thedelivered cost of coal during 2004 is expected to remain at approximately thesame level as 2003.

 

EnvironmentalMatters

 

Protection of the environment is a major priority for KU.  Federal, state, and local regulatoryagencies have issued KU permits for various activities subject to air quality,water quality, and waste management laws and regulations.  For the five-year period ending with 2003,expenditures for pollution control facilities represented $201.8 million or 20%of total construction expenditures. KU estimates that construction expendituresfor the installation of NOx control equipment from 2004 through 2005 will beapproximately $58.9 million.  For adiscussion of environmental matters, see Rates and Regulation for KU under Item7 and Note 11 of KU’s Notes to Financial Statements under Item 8.

 

Competition

 

In the last several years, KU has taken many steps to keep its rateslow while maintaining high levels of customer satisfaction, including a reductionin the number of employees; aggressive cost cutting; an increase in focus oncommercial, industrial and residential customers; an increase in employeeinvolvement and training; and continuous modifications of its organizationalstructure.

 

At this time, neither theKentucky General Assembly nor the Kentucky Commission has adopted or approved aplan or timetable for retail electric industry 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.

 

Although Virginia has enactedcustomer choice, legislation has effectively exempted KU from retail choice until such time as retailchoice is offered to other customers in KU’s other service territories

 

13

----

 

EMPLOYEES AND LABOR RELATIONS

 

LG&E had 881 full-time regular employees and KU had 941 full-timeregular employees at December 31, 2003. Of the LG&E total, 621operating, maintenance, and construction employees were represented by IBEWLocal 2100.  LG&E and employeesrepresented by IBEW Local 2100 signed a four-year collective bargainingagreement in November 2001 and completed wage and benefits re-opener negotiationsin October 2003.  New wage andbenefit rates went into effect in November 2003.  Of the KU total, 155 operating, maintenance, and constructionemployees were represented by IBEW Local 2100 and USWA Local 9447-01.  In August 2003 KU and employees representedby IBEW Local 2100 entered into a three-year collective bargainingagreement.  KU and employees representedby USWA Local 9447-01 entered into a three-year collective bargaining agreementeffective August 2002 and expiring August 2005.

 

As a result of the Powergen acquisition and in order to comply withPUHCA, LG&E Services was formed effective on January 1, 2001.  LG&E Services provides certain servicesto affiliated entities, including LG&E and KU, at cost as required underPUHCA.  On January 1, 2001, approximately1,000 employees, mainly from LG&E Energy, LG&E and KU, were moved toLG&E Services.

 

See Note 3 of LG&E’s Notes to FinancialStatements and Note 3 of KU’s Notes to Financial Statements under Item 8 forthe workforce separation program in effect for 2001.

 

14

----

 

Executive Officers of LG&E and KU at December 31, 2003:

 
| **Name**            |   | **Age** |   | **Position**                                                        |   | **Effective  Date of  Election to Present  Position** |
|---------------------|--------|---------|--------|---------------------------------------------------------------------|--------|-------------------------------------------------------|
|                |   |    |   |                                                                |   |                                                  |
| Victor A. Staffieri |   | 48      |   | Chairman of the Board,  President and Chief  Executive Officer      |   | May 1, 2001                                           |
|                |   |    |   |                                                                |   |                                                  |
| John R. McCall      |   | 60      |   | Executive Vice President,  General Counsel and  Corporate Secretary |   | July 1, 1994                                     |
|                |   |    |   |                                                                |   |                                                  |
| S. Bradford Rives   |   | 45      |   | Chief Financial Officer                                             |   | September 15, 2003                               |
|                |   |    |   |                                                                |   |                                                  |
| Paul W. Thompson    |   | 46      |   | Senior Vice President -  Energy Services                            |   | June 7, 2000                                     |
|                |   |    |   |                                                                |   |                                                  |
| Chris Hermann       |   | 56      |   | Senior Vice President -  Energy Delivery                            |   | February 14, 2003                                |
|                |   |    |   |                                                                |   |                                                  |
| Wendy C. Welsh      |   | 49      |   | Senior Vice President -  Information Technology                     |   | December 11, 2000                                |
|                |   |    |   |                                                                |   |                                                  |
| Martyn Gallus       |   | 39      |   | Senior Vice President -  Energy Marketing                           |   | December 11, 2000                                |
|                |   |    |   |                                                                |   |                                                  |
| A. Roger Smith      |   | 50      |   | Senior Vice President  Project Engineering                          |   | December 11, 2000                                |
|                |   |    |   |                                                                |   |                                                  |
| David A. Vogel      |   | 38      |   | Vice President - Retail  and Gas Storage Operations                 |   | March 1, 2003                                    |
|                |   |    |   |                                                                |   |                                                  |
| Daniel K. Arbough   |   | 42      |   | Treasurer                                                           |   | December 11, 2000                                |
|                |   |    |   |                                                                |   |                                                  |
| Bruce D. Hamilton   |   | 48      |   | Vice President  Independent Power Operations                        |   | December 11, 2000                                |
|                |   |    |   |                                                                |   |                                                  |
| Michael S. Beer     |   | 45      |   | Vice President - Rates  and Regulatory                              |   | February 1, 2001                                 |
|                |   |    |   |                                                                |   |                                                  |
| George R. Siemens   |   | 54      |   | Vice President - External  Affairs                                  |   | January 11, 2001                                 |
|                |   |    |   |                                                                |   |                                                  |
| Paula H. Pottinger  |   | 46      |   | Vice President -  Human Resources                                   |   | June 1, 2002                                     |
|                |   |    |   |                                                                |   |                                                  |
| D. Ralph Bowling    |   | 46      |   | Vice President -  Power Operations WKE                              |   | August 1, 2002                                   |
|                |   |    |   |                                                                |   |                                                  |
| R. W. Chip Keeling  |   | 47      |   | Vice President -  Communications                                    |   | March 18, 2002                                   |
|                |   |    |   |                                                                |   |                                                  |
| John N. Voyles, Jr. |   | 49      |   | Vice President -  Regulated Generation                              |   | June 16, 2003                                    |

 

The present term of office of each of the above executive officersextends to the meeting of the Board of Directors following the 2004 AnnualMeeting of Shareholders.

 

15

----

 

There are no family relationships between or among executive officersof LG&E and KU.  The above tablesindicate officers serving as executive officers of both LG&E and KU atDecember 31, 2003.  Each of theabove officers serves in the same capacity for LG&E and KU.

 

Before he was elected to his current positions, Mr. Staffieri was ChiefFinancial Officer of LG&E Energy and LG&E from May 1997 toFebruary 1999, (including Chief Financial Officer of KU from May 1998 toFebruary 1999) and President and Chief Operating Officer of LG&EEnergy from March 1999 to April 2001 (including President of LG&Eand KU from June 2000 to April 2001).

 

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

 

Before he was elected to his current positions, Mr. Rives was VicePresident - Finance and Controller of LG&E Energy from March 1996 toFebruary 1999; Senior Vice President - Finance and Business Developmentfrom February 1999 to December 2000 and Senior Vice President -Finance and Controller of LG&E Energy, LG&E and KU fromDecember 2000 to September 2003.

 

Before he was elected to his current positions, Mr. Thompson was VicePresident - Business Development for LG&E Energy from July 1994 toSeptember 1996; Vice President, Retail Electric Business for LG&E fromSeptember 1996 to June 1998; Group Vice President for LG&E EnergyMarketing, Inc. from June 1998 to August 1999; Vice President, RetailElectric Business for LG&E from December 1998 to August 1999; andSenior Vice President - Energy Services for LG&E Energy fromAugust 1999 to June 2000.

 

Before he was elected to his current positions, Mr. Hermann was VicePresident, Business Integration of LG&E from June 1997 to May 1998;Vice President, Power Generation and Engineering Services, of LG&E from May1998 to December 1999; Vice President Supply Chain and Operating Servicesfrom December 1999 to December 2000; and Senior Vice President -Distribution Operations, from December 2000 to February 2003.

 

Before she was elected to her current positions, Ms. Welsh was VicePresident, Administration of LG&E Energy from May 1997 toFebruary 1998; and Vice President - Information Technology fromFebruary 1998 to December 2000.

 

Before he was elected to his current positions, Mr. Gallus was VicePresident, Structured Products from April 1997 to May 1998; Senior VicePresident, Trading, from May 1998 to August 1998 for LG&E EnergyMarketing Inc.; and Vice President, Energy Marketing from August 1998 toDecember 2000 for LG&E Energy.

 

Before he was elected to his current positions, Mr. Smith was Head ofConstruction Projects - Powergen from January 1996 to May 1999; Directorof Projects - Powergen from May 1999 to December 1999; and Director ofEngineering Projects for Powergen International from January 2000 toDecember 2000.

 

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

 

Before he was elected to his current positions, Mr. Arbough wasManager, Corporate Finance of LG&E Energy and LG&E fromAugust 1996 to May 1998; and he has held the position of Director,Corporate Finance of LG&E Energy, LG&E and KU from May 1998 to present.

 

16

----

 

Before he was elected to his current positions, Mr. Hamilton was VicePresident, Asset Management from September 1997 to December 2000.

 

Before he was elected to his current positions, Mr. Beer was Director,Federal Regulatory Affairs, for Illinois Power Company in Decatur, Illinois,from February of 1997 to January of 1998; Senior Corporate Attorneyfrom February 1998 to February 2000; and Senior Counsel Specialist,Regulatory from February 2000 to February 2001.

 

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

 

Before she was elected to her current position, Ms. Pottinger wasManager, Human Resources Development from May 1994 to May 1997; and Director,Human Resources from June 1997 to June 2002.

 

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

 

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

 

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

 

17

----

 

ITEM 2. 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 the following electric generating stationsunless otherwise stated:

 
|                                                 |   | **Summer  Capability  Rating (Kw)** |   |
|------------------------------------------------------|--------|-------------------------------------|--------|
|                                                 |   |                                |   |
| Steam Stations:                                      |   |                                |   |
| Mill Creek - Kosmosdale, KY                          |   |                                |   |
| Unit 1                                               |   | 303,000                             |   |
| Unit 2                                               |   | 301,000                             |   |
| Unit 3                                               |   | 394,000                             |   |
| Unit 4                                               |   | 481,000                             |   |
| Total Mill Creek                                     |   | 1,479,000                           |   |
|                                                 |   |                                |   |
| Cane Run - near Louisville, KY                       |   |                                |   |
| Unit 4                                               |   | 155,000                             |   |
| Unit 5                                               |   | 168,000                             |   |
| Unit 6                                               |   | 240,000                             |   |
| Total Cane Run                                       |   | 563,000                             |   |
|                                                 |   |                                |   |
| Trimble County - Bedford, KY (a)                     |   |                                |   |
| Unit 1                                               |   | 385,000                             |   |
|                                                 |   |                                |   |
| Combustion Turbine Generators (Peaking  capability): |   |                                |   |
| Zorn                                                 |   | 14,000                              |   |
| Paddy’s Run (b)                                 |   | 119,000                             |   |
| Cane Run                                             |   | 14,000                              |   |
| Waterside                                            |   | 22,000                              |   |
| E.W. Brown – Burgin, KY (c)                     |   | 190,000                             |   |
| Trimble County – Bedford, KY (d)                |   | 92,000                              |   |
| Total combustion turbine generators                  |   | 451,000                             |   |
|                                                 |   |                                |   |
| Total capability rating                              |   | 2,878,000                           |   |

 

----

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

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

(c)          Amount shown represents LG&E’s 53%interest in Unit 5 and 38% interest in Units 6 and 7 at E.W. Brown.  See Notes 11 and 12 of LG&E’s Notes toFinancial Statements, under Item 8 for further discussion on ownership.  KU operates the units on behalf of LG&E.

(d)         Amount shown represents LG&E’s 29%interest in Units 5 and 6 at Trimble County. See Notes 11 and 12 of LG&E’s Notes to Financial Statements, underItem 8 for further discussion on ownership.

 

LG&E also owns an 80 Mw nameplate-rated hydroelectric generatingstation located in Louisville, with a summer capability rating of 48 Mw,operated under a license issued by the FERC.

 

At December 31, 2003, LG&E’s electric transmission systemincluded 21 substations dedicated solely to transmission and an additional 20substations shared with the distribution system with a total capacity ofapproximately 11,037,000 Kva and approximately 668 structure miles oflines.  The electric distribution systemincluded 93 substations (20 of which are shared by the transmission system)with a total capacity of approximately 4,823,000 Kva, 3,866 structure miles ofoverhead lines and 1,849 miles of underground conduit.

 

18

----

 

LG&E’s gas transmission system includes 254 miles of transmissionmains, and the gas distribution system includes 3,898 miles of distributionmains.

 

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

 

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

 

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

 

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

 

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

 
|                                                |   | **Summer  Capability  Rating (Kw)** |   |
|-----------------------------------------------------|--------|-------------------------------------|--------|
| Steam Stations:                                     |   |                                |   |
| Tyrone - Tyrone, KY                                 |   |                                |   |
| Unit 1                                              |   | 27,000                              |   |
| Unit 2                                              |   | 31,000                              |   |
| Unit 3                                              |   | 71,000                              |   |
| Total Tyrone                                        |   | 129,000                             |   |
|                                                |   |                                |   |
| Green River – South Carrollton, KY             |   |                                |   |
| Unit 3                                              |   | 68,000                              |   |
| Unit 4                                              |   | 95,000                              |   |
| Total Green River                                   |   | 163,000                             |   |
|                                                |   |                                |   |
| E.W. Brown – Burgin, KY                        |   |                                |   |
| Unit 1                                              |   | 101,000                             |   |
| Unit 2                                              |   | 167,000                             |   |
| Unit 3                                              |   | 429,000                             |   |
| Total E.W. Brown                                    |   | 697,000                             |   |
|                                                |   |                                |   |
| Ghent – Ghent, KY                              |   |                                |   |
| Unit 1                                              |   | 486,000                             |   |
| Unit 2                                              |   | 484,000                             |   |
| Unit 3                                              |   | 495,000                             |   |
| Unit 4                                              |   | 495,000                             |   |
| Total Ghent                                         |   | 1,960,000                           |   |
|                                                |   |                                |   |
| Combustion Turbine Generators (Peaking capability): |   |                                |   |
| E.W. Brown – Burgin, KY (Units 5-11) (a)       |   | 757,000                             |   |
| Haefling – Lexington, KY                       |   | 36,000                              |   |
| Paddy’s Run – Louisville, KY (b)          |   | 74,000                              |   |
| Trimble County – Bedford, KY (c)               |   | 228,000                             |   |
| Total combustion turbine generators                 |   | 1,095,000                           |   |
|                                                |   |                                |   |
| Total capability rating                             |   | 4,044,000                           |   |

 

19

----

 

----

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

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

(c)          Amount shown represents KU’s 71% interest inUnits 5 and 6 at Trimble County.  SeeNotes 11 and 12 of KU’s Notes to Financial Statements, under Item 8 for furtherdiscussion on ownership.  LG&Eoperates these units on behalf of KU.

 

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

 

At December 31, 2003, KU’s electric transmission system included112 substations with a total capacity of approximately 16,991,000 Kva andapproximately 4,233 structure miles of lines. The electric distribution system included 466 substations with a total capacityof approximately 4,509,000 Kva and 12,744 structure miles of lines.

 

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

 

The trust indenture securing KU’s first mortgage bonds constitutes adirect first mortgage lien upon much of the property owned by KU.  In addition, Fidelia Corporation, anaffiliate of E.ON, has a second lien on the property subject to the firstmortgage bond lien.  The second liensecures loans provided by Fidelia.

 

# **ITEM3.**  Legal Proceedings.

# ** **

Rates and Regulatory Matters

 

For a discussion of current rate and regulatory matters, includingelectric and gas base rate increase proceedings, earnings sharing mechanismproceedings, MISO proceedings, merger surcredit proceedings, and other rate orregulatory matters affecting LG&E and KU, see Rates and Regulation underItem 1, Item 7 and Note 3 of LG&E’s Notes to Financial Statements and Note3 of KU’s Notes to Financial Statements under Item 8.

 

Environmental

 

For a discussion of environmental matters including currently proposedreductions in NOx emission limits; items regarding LG&E’s Mill Creekgenerating plant, KU’s E.W. Brown plant and LG&E’s and KU’s manufacturedgas plant sites; and other environmental items affecting LG&E and KU, seeEnvironmental Matters under Item 7 and Note 11 of LG&E’s Notes to FinancialStatements and Note 11 of KU’s Notes to Financial Statements under Item 8,respectively.

 

LG&E Employment Discrimination Case

 

In October 2001, approximately30 employees or former employees filed a complaint against LG&E claimingpast and current instances of employment discrimination against LG&E.  LG&E has removed the case to the U.S.District Court for the Western District of Kentucky and filed an answer denyingall plaintiffs’ claims.  The U.S. EqualEmployment Opportunity Commission has declined to proceed to litigation on anyclaims reviewed. Through continuing mediation, settlements have been reachedwith the majority of plaintiffs, including the lead plaintiff.  Negotiations continue with nineplaintiffs.  The complaint contains aclaimed damage amount of $100 million as well as requests for injunctiverelief.  Prior settlements have been fornon-material amounts and

 

20

----

 

LG&E does not anticipate that the remaining outcome will have amaterial impact on its operations or financial condition.

 

Combustion Turbine Litigation

 

In October 2003, LG&E and KU and third parties completed asettlement agreement and subsequently dismissed the Companies’ previouslyreported lawsuit in the U.S. District Court for the Eastern District ofKentucky against Alstom Power, Inc. The suit concerned two combustion turbinessupplied by Alstom during 1999 and jointly owned by LG&E and KU. Thesettlement agreement provides for an aggregate $20 million in reimbursement intwo installments to be paid in January and April 2004 to LG&E andKU for the Companies’ expenditures incurred regarding the turbines. Thepayments, secured by letters of credit provided during 2003, were included inthe Companies’ 2003 results.  TheJanuary 2004 payment was received by the Companies.  The parties also entered into a long-termservice agreement, whereby Alstom will provide to LG&E and KU certainfuture inspections, repairs and services for the turbines.

 

Other

 

In the normal course of business, other lawsuits, claims, environmentalactions, and other governmental proceedings arise against LG&E and KU.  To the extent that damages are assessed inany of these lawsuits, LG&E and KU believe that their insurance coverage isadequate.  Management, afterconsultation with legal counsel, does not anticipate that liabilities arisingout of other currently pending or threatened lawsuits and claims will have amaterial adverse effect on LG&E’s or KU’s consolidated financial positionor results of operations, respectively.

 

21

----

 

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

 

a)              LG&E’s and KU’s Annual Meetings ofShareholders were held on December 16, 2003.

 

b)             Not applicable.

 

c)              The matters voted upon and the results ofthe voting at the Annual Meetings are set forth below:

 

1.               LG&E

 

i)                 The shareholders voted to electLG&E’s nominees for election to the Board of Directors, as follows:

 

Michael Söhlke - 21,294,223 commonshares and 71,068 preferred shares cast in favor of election and 1,317preferred shares withheld.

 

Victor A. Staffieri - 21,294,223 commonshares and 71,068 preferred shares cast in favor of election and 1,317 preferredshares withheld.

 

Dr. Hans Michael Gaul - 21,294,223 commonshares and 71,068 preferred shares cast in favor of election and 1,317preferred shares withheld.

 

No holders of common or preferred shares abstained from voting on thismatter.

 

ii)              The shareholders voted 21,294,223 commonshares and 72,073 preferred shares in favor of and 258 preferred shares againstthe approval of PricewaterhouseCoopers LLP as independent accountants for2003.  Holders of 54 preferred sharesabstained from voting on this matter.

 

iii)           The shareholders voted 21,294,223 commonshares and 65,098 preferred shares in favor of and 4,692 preferred sharesagainst amendments to LG&E’s Articles of Incorporation and Bylaws to reducethe size of the Board of Directors and eliminate staggered terms.  Holders of 2,595 preferred shares abstainedfrom voting on this matter.

 

2.               KU

 

i)                 The sole shareholder voted to electKU’s nominees for election to the Board of Directors, as follows:

 

37,817,878 common shares cast in favor of election and no shareswithheld for each of Michael Söhlke, VictorA. Staffieri and Dr. Hans Michael Gaul, respectively.

 

ii)              The sole shareholder voted 37,817,878common shares in favor of and no shares withheld for approval ofPricewaterhouseCoopers LLP as independent accountants for 2003.

 

iii)           The sole shareholder voted 37,817,878 commonshares in favor of and no shares against amendments to KU’s Articles ofIncorporation and Bylaws to reduce the size of the board of directors andeliminate staggered terms.

 

No holders of common shares abstained from voting on these matters.

 

d)             Not applicable.

 

22

----

 

PART II.

 

ITEM 5. Market for the Registrant’s Common Equity and Related StockholderMatters.

 

LG&E:

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

 

LG&E had no cash distributions on common stock paid to LG&EEnergy in 2003.  The following tablesets forth LG&E’s cash distributions on common stock paid to LG&EEnergy during 2002:

 
| **(in thousands)** |   |   |   |   |
|--------------------|--------|--------|--------|--------|
| First quarter      |   | $      | — |   |
| Second quarter     |   | 23,000 |   |
| Third quarter      |   | 23,000 |   |
| Fourth quarter     |   | 23,000 |   |

 

KU:

All KU common stock, 37,817,878 shares, is held by LG&EEnergy.  Therefore, there is no publicmarket for KU’s common stock.  KU had nocash distributions on common stock paid to LG&E Energy during 2003 or 2002.

 

23

----

 

# **ITEM6.**  Selected Financial Data.

 

The 1999 and 2000 consolidated financial data were derived fromfinancial statements audited by Arthur Andersen LLP, independent accountants,who expressed an unqualified opinion on those financial statements in theirreport dated January 26, 2001, before the revisions required by EITF02-03.  Arthur Andersen LLP has ceasedoperations.  The amounts shown below forsuch periods, reclassified pursuant to the adoption of EITF 02-03, areunaudited.

 
|                                     |   | **Years  Ended December 31** |      |
|------------------------------------------|--------|-----------------------------------|-----------|
| **(in thousands)**                       |   | **2003**                          |      | **2002** | ** ** | **2001** | ** ** | **2000** | ** ** | **1999** | ** ** |
|                                     |   |                              |      |   |   |   |   |   |   |   |   |
| LG&E:                                |   |                              |      |   |   |   |   |   |   |   |   |
| Operating revenues:                      |   |                              |      |   |   |   |   |   |   |   |   |
| Revenues                                 |   | $                                 | 1,093,933 |   | $ | 992,079 |   | $ | 962,959 |   | $ | 934,204 |   | $ | 847,879 |   |
| Provision for rate collections (refunds) |   | (412                              | )         | 11,656 |   | 1,588 |   | (2,500 | ) | (1,735 | ) |
| Total operating revenues                 |   | $                                 | 1,093,521 |   | $ | 1,003,735 |   | $ | 964,547 |   | $ | 931,704 |   | $ | 846,144 |   |
|                                     |   |                              |      |   |   |   |   |   |   |   |   |
| Net operating income                     |   | $                                 | 122,685   |   | $ | 117,914 |   | $ | 141,773 |   | $ | 148,870 |   | $ | 140,091 |   |
|                                     |   |                              |      |   |   |   |   |   |   |   |   |
| Net income                               |   | $                                 | 90,839    |   | $ | 88,929 |   | $ | 106,781 |   | $ | 110,573 |   | $ | 106,270 |   |
|                                     |   |                              |      |   |   |   |   |   |   |   |   |
| Total assets                             |   | $                                 | 2,888,928 |   | $ | 2,768,930 |   | $ | 2,448,354 |   | $ | 2,226,084 |   | $ | 2,171,452 |   |
|                                     |   |                              |      |   |   |   |   |   |   |   |   |
| Long-term obligations                    |   |                              |      |   |   |   |   |   |   |   |   |
| (including amounts due within one year)  |   | $                                 | 798,054   |   | $ | 616,904 |   | $ | 616,904 |   | $ | 606,800 |   | $ | 626,800 |   |

 

LG&E’sManagement’s Discussion andAnalysis of Financial Condition and Results of Operation and LG&E’s.  Notes to Financial Statements should be readin conjunction with the above information.

 
|                                     |   | **Years  Ended December 31** |      |
|------------------------------------------|--------|-----------------------------------|-----------|
| **(in thousands)**                       |   | **2003**                          |      | **2002** | ** ** | **2001** | ** ** | **2000** | ** ** | **1999** | ** ** |
|                                     |   |                              |      |   |   |   |   |   |   |   |   |
| KU:                                      |   |                              |      |   |   |   |   |   |   |   |   |
| Operating revenues:                      |   |                              |      |   |   |   |   |   |   |   |   |
| Revenues                                 |   | $                                 | 900,312   |   | $ | 846,183 |   | $ | 820,920 |   | $ | 793,409 |   | $ | 815,532 |   |
| Provision for rate collections (refunds) |   | (8,534                            | )         | 15,481 |   | (199 | ) | — |   | (5,900 | ) |
| Total operating revenues                 |   | $                                 | 891,778   |   | $ | 861,664 |   | $ | 820,721 |   | $ | 793,409 |   | $ | 809,632 |   |
|                                     |   |                              |      |   |   |   |   |   |   |   |   |
| Net operating income                     |   | $                                 | 107,554   |   | $ | 108,643 |   | $ | 121,370 |   | $ | 128,136 |   | $ | 136,016 |   |
|                                     |   |                              |      |   |   |   |   |   |   |   |   |
| Net income                               |   | $                                 | 91,402    |   | $ | 93,384 |   | $ | 96,414 |   | $ | 95,524 |   | $ | 106,558 |   |
|                                     |   |                              |      |   |   |   |   |   |   |   |   |
| Total assets                             |   | $                                 | 2,513,619 |   | $ | 2,251,638 |   | $ | 1,826,902 |   | $ | 1,739,518 |   | $ | 1,785,090 |   |
|                                     |   |                              |      |   |   |   |   |   |   |   |   |
| Long-term obligations                    |   |                              |      |   |   |   |   |   |   |   |   |
| (including amounts due within one year)  |   | $                                 | 687,576   |   | $ | 500,492 |   | $ | 488,506 |   | $ | 484,830 |   | $ | 546,330 |   |

 

KU’sManagement’s Discussion and Analysis of Financial Condition and Results ofOperation and KU’s Notes to Financial Statements should be read in conjunctionwith the above information.

 

24

----

 

ITEM 7. Management’s Discussion and Analysis of Financial Condition and Resultsof Operation.

 

GENERAL

 

The following discussion and analysis by management focuses on thosefactors that had a material effect on LG&E’s and KU’s financial results ofoperations and financial condition during 2003, 2002, and 2001 and should beread in connection with the financial statements and notes thereto.

 

Some of the following discussion may contain forward-looking statementsthat are subject to certain risks, uncertainties and assumptions.  Such forward-looking statements are intendedto be identified in this document by the words “anticipate,” “expect,”“estimate,” “objective,” “possible,” “potential” and similar expressions.  Actual results may materially vary.  Factors that could cause actual results tomaterially differ include: general economic conditions; business andcompetitive conditions in the energy industry; changes in federal or statelegislation; unusual weather; actions by state or federal regulatory agencies;actions by credit rating agencies; and other factors described from time totime in LG&E’s and KU’s reports to the SEC, including Exhibit No. 99.01 tothis report on Form 10-K.

 

EXECUTIVE SUMMARY

 

Overview

 

LG&E and KU continue profitable operations despite national andregional economic weakness and turmoil in the U.S. energy industry.  LG&E and KU enjoy a competitive costadvantage relative to the U.S. industry average and high customer satisfactionratings. During 2003, the Companies were awarded first place in the region byJ.D. Power in the 2003 Residential Customer Satisfaction Survey and a nationalfirst place in the Midsize Business Survey.

 

As regulated utilities, LG&E’s and KU’s financial performance isgreatly impacted by regulatory proceedings. In December 2003, LG&E and KU filed applications with theKentucky Commission requesting an adjustment in LG&E’s electric and gasrates and KU’s electric rates.  LG&Eapplied for revenue increases of  $63.8million for electric and $19.1 million for gas.  KU applied for revenue increases of $58.3 million.  The Kentucky Commission has suspended theeffective date of the proposed new tariffs for five months, so that the ratesmay go into effect subject to refund by July 1, 2004.  The Kentucky Commission has established aprocedural schedule for the cases pertaining to discovery andhearings.  Hearings are scheduled in May2004.  The Companies expect the KentuckyCommission to issue orders in the cases before new rates go into effectJuly 1, 2004.

 

In addition, continuance of LG&E’s and KU’s ESM mechanism, whichsets an upper and lower point for rate of return on equity and sharingguidelines for returns above or below these thresholds, is being deliberated bythe Kentucky Commission.  A final orderis not expected until the second quarter of 2004.  Although the ESM tariff remains in effect pending the resolutionof the case, the future operation of the ESM cannot be determined by theCompanies.

 

Major Strategic Goals

 

LG&E’s and KU’s major strategic goals are to continue to be leadingelectric and gas utilities by meeting their utility native load and reliabilityrequirements while managing business, environmental and regulatory risks; bymaintaining excellent customer service and reputation with all stakeholders; byengaging in continuous improvement to foster efficiency; by securing afoundation for future regulatory support; and, by developing transferableutility best practices business models.

 

25

----

 

To continue to meet the regulated load growth in Kentucky, LG&E andKU are jointly installing four combustion turbines at Trimble County in timefor 2004 peak demand.  The installationswere authorized by the Kentucky Commission as the least cost alternative tomeet Kentucky’s needs.  Although costpressures resulted in LG&E and KU filing rate cases in December 2003,prices will remain competitive in the region.

 

LG&E and KU continue to aggressively moveto best practices and capture cost savings. The Companies have reduced headcount by 35% since 1998.  They continue to pursue best practiceimprovements and additional savings initiatives, including limited staffing andmanagement changes.

 

Current Trends

 

Although the stock market has rebounded somewhat, industrial energydemand and the employment market remain dampened.  Short-term interest rates have fallen to forty-year lows andconsensus forecasts continue to predict gradual economic recovery overtime.  Natural gas prices have beenvolatile and have increased significantly, further aggravating the U.S.economy’s recovery.  Peak wholesaleelectric prices have risen as a result of gas price increases, even withcontinued overcapacity in many regions, favoring coal-fired generators likeLG&E and KU.

 

The U.S. energy industry is still in the grips of national regulatoryuncertainty and financial turmoil, highlighting the strength of companies withintegrated utility operations. Deregulation momentum is stalled or abandoned in most states, withnational attention on the economy and international issues.  The Kentucky legislature did not take anyaction in either 2002 or 2003 to move Kentucky towards electricderegulation.  The nature or timing ofthe ultimate legislative or regulatory actions regarding industry restructuringand their impact on LG&E and KU, which may be significant, cannot currentlybe predicted.

 

Another area of regulatory uncertainty relates to the MISO.  LG&E and KU obtained membership in theMISO in 1998 in response to federal policy initiatives.  The Kentucky Commission has formallyquestioned LG&E’s and KU’s participation in the MISO and initiated a formalcase to evaluate the justification of MISO membership. Due to LG&E’s andKU’s membership in MISO, costs have been incurred related to transmission feesand the MISO organization’s administrative fees.  Additional fees which may be incurred by the MISO members,related to recovery of costs for the congestion management system, arecurrently being debated by FERC and the members of the MISO.  LG&E and KU are attempting to mitigatecosts, maintain system reliability, and operate within all applicable laws andregulation.  Litigation on federal andstate jurisdictional issues appears likely.

 

Also, the FERC issued a NOPR in July 2002 which wouldsubstantially alter the regulations governing the nation’s wholesale electricitymarkets by establishing a common set of rules, defined as SMD.  The FERC NOPR has met opposition, even afterrevision, and implementation is uncertain. Prolonged litigation is likely over any contentious provisions. Low coststates are wary of grid reforms and increased cost burdens. There are stillfundamental differences over federal and state jurisdictional issues andprerogatives.  Kentucky regulators andpolitical leaders are in the forefront of opposition to broad federal mandateson utility related issues.

 

National energy legislation and policy continues to be a very divisivearea. The U.S. House of Representatives passed the Energy Policy Act inApril 2003.  The legislation, aspassed in the House, included the repeal of PUHCA as well as tax incentives forvarious energy initiatives.  The U.S.Senate Energy and Natural Resources Committee passed its version of energylegislation in April 2003.  Aconference agreement merging both versions passed in the House inOctober 2003, but failed to pass in the Senate.  Many disputed issues remain and it is unclear whether legislationwill pass this year.  The impact oflegislation on LG&E and KU, which may be significant, cannot be predicted.

 

The August 14, 2003 transmission grid failures in the Northeast havespurred demands for transmission investment and national oversight through theNational Electricity Reliability Council (NERC) enforcement powers. In thepast, compliance with NERC 

 

26

----

 

reliability standards and guidelines has largely been voluntary. Potential impacts could include increasedNERC power to impose transmission standards, resulting in further transmissionregulation and increased capital requirements for LG&E and KU.

 

MERGERS AND ACQUISITIONS

 

LG&E and KU are each subsidiaries of LG&E Energy.  On December 11, 2000, LG&E EnergyCorp., now LG&E Energy LLC, was acquired by Powergen plc, now known asPowergen Limited, for cash of approximately $3.2 billion and the assumption ofall of LG&E Energy’s debt.  As aresult of the acquisition, among other things, LG&E Energy became a whollyowned subsidiary of Powergen and, as a result, LG&E and KU became indirectsubsidiaries of Powergen.  Following theacquisition, Powergen became a registered holding company under PUHCA, andLG&E and KU, as subsidiaries of a registered holding company, becamesubject to additional regulation under PUHCA.

 

As a result of the Powergen acquisition and in order to comply withPUHCA, LG&E Services was formed as a subsidiary of LG&E Energyeffective on January 1, 2001. LG&E Services provides certain services to affiliated entities,including LG&E and KU, at cost as required under PUHCA.  On January 1, 2001, approximately 1,000employees, mainly from LG&E Energy, LG&E and KU, were moved to LG&EServices.

 

On July 1, 2002, E.ON, a German company, completed its acquisitionof Powergen plc (now Powergen Limited).  As a result, LG&E and KUbecame indirect subsidiaries of E.ON. E.ON had announced its pre-conditional cash offer of £5.1 billion ($7.3billion) for Powergen on April 9, 2001.

 

Following the purchase of Powergen by E.ON, E.ON became a registeredholding company under PUHCA.  As aresult, E.ON, its utility subsidiaries, including LG&E, and certain of itsnon-utility subsidiaries are subject to extensive regulation by the SEC underPUHCA with respect to issuances and sales of securities, acquisitions and salesof certain utility properties, and intra-system sales of certain goods andservices.  In addition, PUHCA generallylimits the ability of registered holding companies to acquire additional publicutility systems and to acquire and retain businesses unrelated to the utilityoperations of the holding company. LG&E and KU believe that they have adequate authority (includingfinancing authority) under existing SEC orders and regulations to conduct theirbusiness.  LG&E and KU will seekadditional authorization when necessary.

 

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

 

The utility operations (LG&E and KU) of LG&E Energy havecontinued their separate identities and continue to serve customers inKentucky, Virginia and Tennessee under their existing names.  The preferred stock and debt securities ofLG&E and KU were not affected by these transactions resulting in LG&E’sand KU’s obligations to continue to file SEC reports.

 

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

 

27

----

 

RESULTS OF OPERATIONS

 

LG&E

 

Net Income

 

LG&E’s net income in 2003 increased $1.9 million (2.1%) compared to2002.  The increase resulted primarilyfrom increased electric wholesale sales partially offset by increasedtransmission expense and increased depreciation expense due to plant additions.

 

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

 

LG&E’s net income in 2003 related to the gas business increased$0.5 million (5.7%) compared to 2002. Gas operating revenues increased $57.6 million (21.6%) offset by highergas supply expenses of $51.5 million (28.3%). Other gas operations expense increased $3.1 million (8.4%) andmaintenance expense increased $0.3 million (4.4%).  Gas depreciation increased $1.1 million (7.3%).  Other income decreased $0.5 million(112.4%).

 

LG&E’s net income in 2002 decreased $17.9 million (16.7%) ($15.8million related to electric business and $2.1 million related to gas business)as compared to 2001.  The decreaseresulted primarily from higher transmission expenses, increased amortization ofthe VDT regulatory asset, and increased property insurance and pension expense,partially offset by an increase in electric sales to retail customers and lowerinterest expenses.

 

Revenues

 

A comparison of operating revenues for the years 2003 and 2002,excluding the provisions recorded for rate collections (refunds), with theimmediately preceding year reflects both increases and decreases, which havebeen segregated by the following principal causes:

 
|                                  |   | **Increase  (Decrease) From Prior Period** |       |
|---------------------------------------|--------|--------------------------------------------|------------|
|                                  |   | **Electric  Revenues**                     | ** ** | **Gas  Revenues** | ** ** |
| **Cause (in thousands)**              |   | **2003**                                   | ** ** | **2002** | ** ** | **2003** | ** ** | **2002** | ** ** |
|                                  |   |                                       |       |   |   |   |   |   |   |
| Retail sales:                         |   |                                       |       |   |   |   |   |   |   |
| Fuel and gas supply adjustments       |   | $                                          | 6,620      |   | $ | 19,449 |   | $ | 50,972 |   | $ | (58,003 | ) |
| LG&E/KU Merger surcredit          |   | (2,288                                     | )          | (2,825 | ) | — |   | — |   |
| Environmental cost recovery surcharge |   | (269                                       | )          | 9,694 |   | — |   | — |   |
| Earnings sharing mechanism            |   | 9,768                                      |       | 622 |   | — |   | — |   |
| Demand side management                |   | 1,362                                      |       | 1,381 |   | 267 |   | 938 |   |
| VDT surcredit                         |   | (3,394                                     | )          | (1,177 | ) | (1,283 | ) | (285 | ) |
| Weather normalization                 |   | —                                     |       | — |   | (506 | ) | 2,234 |   |
| Variation in sales volumes and other  |   | (18,450                                    | )          | 27,118 |   | 12,070 |   | 21,658 |   |
| Total retail sales                    |   | (6,651                                     | )          | 54,262 |   | 61,520 |   | (33,458 | ) |
| Wholesale sales                       |   | 49,230                                     |       | (6,701 | ) | (4,106 | ) | 10,682 |   |
| Gas transportation-net                |   | —                                     |       | — |   | (186 | ) | 190 |   |
| Other                                 |   | 1,635                                      |       | 4,641 |   | 412 |   | (496 | ) |
| Total                                 |   | $                                          | 44,214     |   | $ | 52,202 |   | $ | 57,640 |   | $ | (23,082 | ) |

 

28

----

 

Electric revenues increased in 2003 primarily due to an increase inwholesale sales due to both higher market prices and higher sales volume ascompared to 2002.  Retail revenuesdecreased due to 2.6% lower sales volume, primarily in the residential sectordue to milder summer weather than 2002. Cooling degree days decreased 33% compared to 2002 and were 14% belowthe 20-year average.  Electric revenuesincreased in 2002 primarily due to an increase in retail sales due to warmersummer weather, an increase in the recovery of fuel costs passed through theFAC, partially offset by a decrease in wholesale sales due to lower marketprices as compared to 2001. Cooling degree days increased 20% compared to 2001and were 29% above the 20-year average.

 

Gas revenues in 2003 increased due to higher gas supply cost billed tocustomers through the gas supply clause and increased gas retail sales due tocooler winter weather, offset by lower wholesale sales.  Heating degree days increased 5% as comparedto 2002 and were the same as the 20-year average.  Gas revenues in 2002 decreased due to a lower gas supply costbilled to customers through the gas supply clause offset partially by increasedgas retail sales due to cooler winter weather and an increase in wholesalesales volume.  Heating degree daysincreased 17% as compared to 2001 and were 5% below the 20-year average.

 

The decrease in the provision for rate collections (refunds) in 2003from 2002 ($12.1 million) results primarily from ESM revenues billed tocustomers during 2003 ($10.0 million), a decrease in the ESM accrual ($2.4million) and a decrease in 2003 fuel accruals ($2.6 million), partially offsetby an increase in 2003 ECR accruals ($2.9 million). The increase in theprovision for rate collections (refunds) in 2002 over 2001 ($10.1 million) isdue primarily to the increase in the ESM accruals ($10.2 million) and anincrease in fuel accruals ($1.4 million), partially offset by a 2002 ECRover-recovery ($1.5 million).

 

Expenses

 

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

 

Fuel for electric generation increased $2.1 million (1.1%) in 2003 dueto increased generation ($5.8 million) offset by lower cost of coal burned($3.7 million).  Fuel for electricgeneration increased $35.7 million (22.4%) in 2002 due to increased generation ($5.4million) and higher cost of coal burned ($30.3 million).  The average delivered cost per ton of coalpurchased was $25.56 in 2003, $25.30 in 2002 and $21.27 in 2001.

 

Power purchased increased $17.7 million (28.7%) in 2003 due to anincrease in purchases to meet requirements for off-system sales and a higherunit cost of purchases.  Power purchasedincreased $12.6 million (25.5%) in 2002 due to an increase in purchases to meetrequirements for native load and off-system sales and a higher unit cost ofpurchases.

 

Gas supply expenses increased $51.5 million (28.3%) in 2003 due to anincrease in cost of net gas supply ($50.2 million) and an increase in thevolume of gas delivered to the distribution system ($4.1 million), partiallyoffset by lower cost of purchases for wholesale sales ($2.8 million).  Gas supply expenses decreased $24.1 million(11.7%) in 2002 due to a decrease in cost of net gas supply ($36.6 million),partially offset by an increase in the volume of gas delivered to thedistribution system ($12.5 million).

 

29

----

 

Other operation expenses increased $8.7 million (4.2%) in 2003 dueprimarily to increased electric transmission and distribution expense ($5.4million), increased employee benefits costs ($4.0 million), increased demandside management program expenses ($2.5 million) and an increase inuncollectible customer accounts ($1.6 million) partially offset by decreases inexpenses from the amortization of regulatory assets ($3.5 million) and lowerexpenses related to injury and damage liabilities ($2.1 million).  Other operation expenses increased $40.5million (24.1%) in 2002 primarily due to a full year amortization in 2002 of aregulatory asset created as a result of the workforce reduction costsassociated with LG&E’s VDT ($17.0 million), higher costs for electrictransmission primarily resulting from increased MISO costs ($13.9 million), anincrease in property and other insurance costs ($3.9 million), an increase inpension costs due to change in pension assumptions to reflect current marketconditions and change in market value of plan assets at the measurement date($3.7 million), and an increase in steam production costs ($3.4 million).

 

Maintenance expenses for 2003 decreased $3.0 million (5.0%) dueprimarily to a decrease in expenses for maintenance of electric distribution($1.1 million) and gas distribution ($0.8 million) and a decrease incommunications maintenance expenses ($0.9 million).  Maintenance expenses for 2002 increased $1.5 million (2.6%)primarily due to gas distribution expenses for main remediation work ($2.2million).

 

Depreciation and amortization increased $7.4 million (7.0%) in 2003 and$5.6 million (5.5%) in 2002 because of additional utility plant in service.

 

Variations in income tax expenses are largely attributable to changesin pre-tax income. LG&E’s 2003 effective income tax rate decreased to 35.5%from the 37.2% rate in 2002. See Note 7 of LG&E’s Notes to FinancialStatements under Item 8.

 

Property and other taxes decreased $0.4 million (2.3%) in 2003 comparedto a $0.3 million (1.6%) decrease in 2002. Property taxes decreased $1.1 million in 2003 due to a $1.2 million coalcredit partially offset by payroll taxes which increased by $0.7 million.  Payroll taxes decreased by $1.1 million in2002 due to employee reductions and property taxes increased by $0.8 million.

 

Other income (expense) - net decreased $2.0 million (246.2%) in 2003due primarily to the write-off of amounts from CWIP for a terminated plantproject ($2.4 million) and a terminated software project ($0.6 million)partially offset by a decrease in benefit costs ($1.7 million).  Other income (expense) - net decreased $2.1million (72.0%) in 2002 primarily due to increased costs for non-regulatedcommercial activities ($1.3 million) and decreases in the gain on sale ofproperty ($0.8 million).

 

Interest charges for 2003 increased $0.8 million (2.8%) due to newfixed-rate debt with an affiliated company ($5.0 million) offset by a decreasein average outstanding balances on short-term notes payable to an affiliatedcompany ($0.4 million) and savings from lower average interest rates onvariable-rate long-term bonds ($3.5 million). Interest charges for 2002 decreased $8.1 million (21.4%) primarily dueto lower interest rates on variable-rate debt ($5.6 million), a decrease indebt to affiliated companies ($0.8 million), and a decrease in interestassociated with LG&E’s accounts receivable securitization program ($1.5million).

 

The weighted average interest rate on variable-rate long-term bonds for2003, 2002 and 2001 was 1.10%, 1.54% and 3.42%, respectively.  At December 31, 2003, 2002 and 2001,LG&E’s percentage of long-term debt having a variable-rate, including theimpact of interest rate swaps, was 38.3% at $306.0 million, 46.8% at $289.0million and 40.1% at $247.3 million, respectively.  LG&E’s weighted average cost of long-term debt, includingamortization of debt expense and interest rate swaps, was 3.58% and 3.87% atDecember 31, 2003 and 2002, respectively. See Note 9 of LG&E’s Notes to Financial Statements under Item 8.

 

30

----

 

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 applicationof these policies necessarily involves judgments regarding future events,including legal and regulatory challenges and anticipated recovery ofcosts.  These judgments, in and ofthemselves, could materially impact the financial statements and disclosuresbased on varying assumptions, which may be appropriate to use.  In addition, the financial and operatingenvironment also may have a significant effect, not only on the operation ofthe business, but on the results reported through the application of accountingmeasures used in preparing the financial statements and related disclosures,even if the nature of the accounting policies applied has not changed.  Specific risks for these critical accountingpolicies are described in the following paragraphs.  Each of these has a higher likelihood of resulting in materiallydifferent reported amounts under different conditions or using differentassumptions.  Events rarely developexactly as forecast and the best estimates routinely require adjustment.  See also Note 1 of LG&E’s Notes toFinancial Statements under Item 8.

 

Financial Instruments **–**LG&E uses over-the-counter interest-rate swap agreements to hedge itsexposure to fluctuations in the interest rates it pays on variable-ratedebt.  Gains and losses on interest-rateswaps used to hedge interest rate risk are reflected in other comprehensiveincome.  LG&E uses sales ofmarket-traded electric forward contracts for periods less than one year tohedge the price volatility of its forecasted peak electric off-system sales.  Gains and losses resulting fromineffectiveness are shown in other income (expense) and to the extent that thehedging relationship has been effective, gains and losses are reflected inother comprehensive income.  See Note 4- Financial Instruments.

 

Unbilled Revenue – At each month end LG&E prepares a financialestimate that projects electric and gas usage that has been used by customers,but not billed.  The estimated usage isbased on allocating the daily system net deliveries between billed volumes andunbilled volumes.  The allocation isbased on a daily ratio of the number of meter reading cycles remaining in themonth to the total number of meter reading cycles in each month.  Each day’s ratio is then multiplied by eachday’s system net deliveries to determine an estimated billed and unbilled volumefor each day of the accounting period. At December 31, 2003, a 10% change in these estimated quantitieswould cause revenue and accounts receivable to change by approximately $5.1million, including $2.2 million for electric usage and $2.9 million for gasusage.  See also Note 1 of LG&E’sNotes to Financial Statements under Item 8.

 

Allowance for Doubtful Accounts – At December 31, 2003 and 2002,the LG&E allowance for doubtful accounts was $3.5 million  and $2.1 million, respectively.  The allowance is based on the ratio of theamount charged-off during the last twelve months to the retail revenues billedover the same period multiplied by the retail revenues billed over the lastfour months.  Accounts with no paymentactivity are charged-off after four months.

 

Benefit Plan Accounting – Judgments and uncertainties in benefit planaccounting include future rate of returns on pension plan assets, interestrates used in valuing benefit obligation, healthcare cost trend rates, andother actuarial assumptions.

 

31

----

 

LG&E’s costs of providing defined-benefit pension retirement plansis dependent upon a number of factors, such as the rates of return on planassets, discount rate, and contributions made to the plan.  At December 31, 2002, LG&E wasrequired to recognize an additional minimum liability as prescribed by SFAS No.87 *Employers’Accounting for Pensions*.  Theliability was recorded as a reduction to other comprehensive income, and didnot affect net income.  The amount ofthe liability depended upon the asset returns experienced in 2002 andcontributions made by LG&E to the plan during 2002.  If the fair value of the plan assets exceedsthe accumulated benefit obligation, the recorded liability will be reduced andother comprehensive income will be restored in the consolidated balance sheet.

 

During 2002, the combination of poor market performance andhistorically low corporate bond rates created a divergence in the potentialvalue of the pension liabilities and the actual value of the pensionassets.  Market performance in 2003reversed the negative trend.  Shouldpoor market conditions return, these conditions could result in an increase inLG&E’s funded accumulated benefit obligations and future pensionexpense.  The primary assumptions thatdrive the value of the unfunded accumulated benefit obligations are thediscount rate and expected return on plan assets.

 

LG&E made contributions to the pension plan of $83.1 million inJanuary 2003, $6.0 million in September 2003 and $34.5 million inJanuary 2004.

 

A 1% increase or decrease in the assumed discount rate could have anapproximate $41 million positive or negative impact to the accumulated benefitobligation of LG&E.  See also Note 6of LG&E’s Notes to Financial Statements under Item 8.

 

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

 

Regulatory assets represent incurred costs that have been deferredbecause they are probable of future recovery in customer rates based uponKentucky Commission orders.  Regulatoryliabilities generally represent obligations to make refunds to customers forprevious collections based upon orders by the Kentucky Commission.  Management believes, based on orders, theexisting regulatory assets and liabilities are probable of recovery.  This determination reflects the currentregulatory climate in the state.  Iffuture recovery of costs ceases to be probable the assets would be required tobe recognized in current period earnings.

 

LG&E has accrued in the financial statements an estimate of $8.9million for 2003 ESM, with collection from customers commencing inApril 2004.  The ESM is subject toKentucky Commission approval.  See alsoNote 3 of LG&E’s Notes to Financial Statements under Item 8.

 

NEW ACCOUNTING PRONOUNCEMENTS

 

The following accounting pronouncements were implemented by LG&E in2003:

 

SFAS No. 143, *Accounting for Asset Retirement Obligations*was issued in 2001.  SFAS No. 143establishes accounting and reporting standards for obligations associated withthe retirement of tangible long-lived assets and the associated assetretirement costs.

 

The effective implementation date for SFAS No. 143 was January 1,2003.  Management has calculated theimpact of SFAS No. 143 and FERC Final Order No. 631 issued in Docket No.RM02-7, *Accounting, Financial Reporting, andRate Filing Requirements for Asset Retirement Obligations.*  The Company evaluated the impact of SFAS 143from both a legal and operations perspective, reviewing applicable laws andregulations affecting the industry, contracts, permits, certificates of needand right of way agreements, to determine if legal obligations existed.  The fair value of future removal obligationswas calculated based on the Company’s engineering estimates, costs expended forsimilar retirements and third party estimates at current market prices inflatedat a rate of 2.31% per year to the expected retirement date of the asset.  The future removal obligations were thendiscounted to their net present value at the original asset in-service datebased on a discount rate of 6.61%.  AROassets equal to the net present value were recorded on the Company’s books atimplementation.  An amount equal to thenet present value plus the accretion the Company would have accrued had thestandard been in effect at the original in-service date was also recorded onthe Company’s books as an ARO liability at implementation.  Additionally, the Company contracted with anindependent consultant to quantify the cost of removal included in itsaccumulated depreciation under regulatory accounting practices.

 

32

----

 

As of January 1, 2003, LG&E recorded asset retirementobligation (ARO) assets in the amount of $4.6 million and liabilities in theamount of $9.3 million.  LG&E alsorecorded a cumulative effect adjustment in the amount of $5.3 million toreflect the accumulated depreciation and accretion of ARO assets at thetransition date less amounts previously accrued under regulatory depreciation.  LG&E recorded offsetting regulatoryassets of $5.3 million, pursuant to regulatory treatment prescribed under SFASNo. 71, *Accountingfor the Effects of Certain Types of Regulation*.  Also pursuant to SFAS No. 71, LG&Erecorded regulatory liabilities in the amount of $0.1 million offsettingremoval costs previously accrued under regulatory accounting in excess ofamounts allowed under SFAS No. 143.

 

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

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

 

As of December 31, 2003, LG&E recorded ARO assets, net ofaccumulated depreciation, of $4.5 million and liabilities of $9.7 million.  LG&E recorded regulatory assets of $6.0million and regulatory liabilities of $0.1 million.

 

For the year ended December 31, 2003, LG&E recorded AROaccretion expense of approximately $0.6 million, ARO depreciation expense of$0.1 million and an offsetting regulatory credit in the income statement of$0.7 million, pursuant to regulatory treatment prescribed under SFAS No.71.  Approximately $0.2 million ofremoval costs were incurred and charged against the ARO liability during2003.  SFAS No. 143 has no impact on theresults of the operation of LG&E.

 

LG&E AROs are primarily related to final retirement of assetsassociated with generating units.  Forassets associated with AROs, the removal cost accrued through depreciationunder regulatory accounting is established as a regulatory asset or liabilitypursuant to regulatory treatment prescribed under SFAS No. 71.  For the year ended December 31, 2003,LG&E recorded approximately $25,000 of depreciation expense related to thecost of removal of ARO related assets. An offsetting regulatory liability was established pursuant toregulatory treatment prescribed under SFAS No. 71.

 

LG&E also continues to include a cost of removal component indepreciation for assets that do not have a legal ARO.  As of December 31, 2003 and 2002, LG&E has segregatedthis cost of removal, included in accumulated depreciation, of $223.6 millionand $207.9 million, respectively, in accordance with FERC Order No. 631*.* For reporting purposes in its Consolidated Balance Sheets included inItem 8, LG&E has presented this cost of removal as a regulatory liabilitypursuant to SFAS No. 71.

 

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

 

LG&E adopted EITF No. 98-10, *Accounting for Energy Trading and Risk ManagementActivities,*effective January 1, 1999.  This pronouncement required that energytrading contracts be marked to market on the balance sheet, with the gains andlosses shown net in the income statement. Effective January 1, 2003, LG&E adopted EITF No. 02-03, *IssuesInvolved in Accounting for Derivative Contracts Held for Trading Purposes andContracts Involved in Energy Trading and Risk Management Activities*.

 

33

----

  EITF No. 02-03 established the following:

 

•                  Rescinded EITFNo. 98-10,

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

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

 

With the rescission of EITF No. 98-10, energy trading contracts that donot also meet the definition of a derivative under SFAS No. 133 must beaccounted for as executory contracts. Contracts previously recorded at fair value under EITF No. 98-10 thatare not also derivatives under SFAS No. 133, *Accounting for Derivative Instruments**and**HedgingActivities*, must be restated to historical cost through a cumulativeeffect adjustment.  The rescission ofthis standard had no impact on financial position or results of operations ofLG&E since all forward and option contracts marked to market under EITF No.98-10 were also within the scope of SFAS No. 133.

 

As a result of EITF No. 02-03, LG&E has netted the power purchasedexpense for trading activities against electric operating revenue to reflectthis accounting change.  LG&Eapplied this guidance to all prior periods, which had no impact on previouslyreported net income or common equity.

 
| **(in thousands)**                            |   | **2002** |      | **2001** |   |
|-----------------------------------------------|--------|----------|-----------|----------|--------|
|                                          |   |     |      |     |   |
| Gross operating revenues                      |   | $        | 1,026,184 |     | $      | 996,700 |   |
| Less costs reclassified from power  purchased |   | 22,449   |      | 32,153   |   |
| Net operating revenues reported               |   | $        | 1,003,735 |     | $      | 964,547 |   |
|                                          |   |     |      |     |   |
| Gross power purchased                         |   | $        | 84,330    |     | $      | 81,475 |   |
| Less costs reclassified to revenues           |   | 22,449   |      | 32,153   |   |
| Net power purchased reported                  |   | $        | 61,881    |     | $      | 49,322 |   |

 

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

 

LG&E hasexisting $5.875 series mandatorily redeemable preferred stock outstandinghaving a current redemption price of $100 per share. The preferred stock has asinking fund requirement sufficient to retire a minimum of 12,500 shares onJuly 15 of each year commencing with July 15, 2003, and the remaining187,500 shares on July 15, 2008 at $100 per share.  LG&E redeemed 12,500 shares inaccordance with these provisions on July 15, 2003, leaving 237,500 sharescurrently outstanding.  Beginning withthe 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 portion oflong-term debt.  Dividends accrued beginningJuly 1, 2003, are charged as interest expense.

 

In January 2003, the Financial Accounting Standards Board issuedFinancial Accounting Standards Board Interpretation No. 46, *Consolidationof Variable Interest Entities*, an Interpretation of ARB No. 51 (FIN46).  FIN 46 requires certain variable interestentities to be consolidated by the primary beneficiary of the entity if theequity investors in the entity do not have the characteristics of a controllingfinancial interest or do not have sufficient equity at risk for the entity tofinance its activities without additional

 

34

----

 

subordinated financial support from other parties.  FIN 46 was effective immediately for all newvariable interest entities created or acquired after January 31, 2003.  For variable interest entities created oracquired prior to February 1, 2003, the provisions of FIN 46 must have beenapplied for the first interim or annual period beginning after June 15, 2003.

 

In December 2003, FIN 46 was revised, delaying the effective datesfor certain entities created before February 1, 2003, and making otheramendments to clarify application of the guidance.  For potential variable interest entities other than specialpurpose entities, the revised FIN 46 (FIN 46R) is now required to be applied nolater than the end of the first fiscal year or interim reporting period endingafter March 15, 2004.  The originalguidance under FIN 46 was applicable, however, for all special purpose entitiescreated prior to February 1, 2003, at the end of the first interim orannual reporting period ending after December 15, 2003.  FIN 46R may be applied prospectively with acumulative-effect adjustment as of the date it is first applied, or byrestating previously issued financial statements with a cumulative-effectadjustment as of the beginning of the first year restated.  FIN 46R also requires certain disclosures ofan entity’s relationship with variable interest entities.

 

LG&E has no special purpose entities that fall within the scope ofFIN 46R.  LG&E continues to evaluatethe impact that FIN 46R may have on its financial position and results ofoperations.

 

LIQUIDITY AND CAPITAL RESOURCES

 

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

 

Operating Activities

 

Cash provided by operations was $163.3 million, $212.4 million and$287.1 million in 2003, 2002, and 2001, respectively.  The 2003 decrease compared to 2002 of $49.1 million resultedprimarily from pension funding in 2003 of $89.1 million and the change inaccounts receivable balances of $33.4 million, including the sale of accountsreceivable through the accounts receivable securitization program, partiallyoffset by an increase in accounts payable and accrued taxes of $35.0 millionand $36.0 million, respectively.  The2002 decrease of $74.7 million resulted primarily from the change in accountsreceivable balances of $68.0 million. See Note 1 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.  Capitalexpenditures were $213.0 million, $220.4 million and $253.0 million in 2003,2002, and 2001, respectively.  LG&Eexpects its capital expenditures for 2004 and 2005 to total approximately$270.0 million, which consists primarily of construction estimates associatedwith installation of NOx equipment as described in the section titled“Environmental Matters,” construction of jointly owned CTs with KU and on-goingconstruction for the generation and distribution systems.

 

Net cash used for investment activities decreased $7.2 million in 2003compared to 2002 primarily due to the level of construction expenditures.  NOx equipment expenditures wereapproximately $29.6 million in 2003 and $71.8 million in 2002, while CTexpenditures were approximately $71.4 million in 2003 and $35.9 million in2002.  The $28.7 million decrease in netcash used in 2002 as compared to 2001 was primarily due to the purchase of CTs.

 

35

----

 

Financing Activities

 

Net cash inflows for financing activities were $34.2 million in 2003,$22.5 million in 2002 and outflows of $38.7 million in 2001.  In 2003, long-term borrowings from anaffiliated company increased $200.0 million which were used in part forrepayment of short-term borrowings from LG&E Energy and to retire amaturing first mortgage bond.  During2002, short-term borrowings increased $78.5 million from 2001 for payment of$73.3 million in dividends.

 

During 2001, LG&E issued $10.1 million of pollution control bondsresulting in net proceeds of $9.7 million after issuance costs.

 

On March 6, 2002, LG&E refinanced its $22.5 million and $27.5million unsecured pollution control bonds, both due September 1, 2026.  The replacement bonds, due September 1,2026, are variable-rate bonds and are secured by first mortgage bonds.

 

On March 22, 2002, LG&E refinanced its two $35 millionunsecured pollution control bonds due November 1, 2027.  The replacement variable-rate bonds aresecured by first mortgage bonds and will mature November 1, 2027.

 

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

 

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

 

During 2003, LG&E entered into two long-term loans from anaffiliated company totaling $200 million. $100 million of this total is unsecured and the remaining $100 millionis secured by a lien subordinated to the first mortgage bond lien.  The second lien applies to substantially allutility assets of LG&E.

 

LG&E first mortgage bond, 6% Series of $42.6 million matured in2003.

 

Under the provisions for LG&E’s variable-rate pollution controlbonds totaling $246.2 million, the bonds are subject to tender for purchase atthe option of the holder and to mandatory tender for purchase upon theoccurrence of certain events, causing the bonds to be classified as currentportion of long-term debt.

 

Future Capital Requirements

 

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

 

LG&E has a variety of funding alternatives available to meet itscapital requirements.  The Companymaintains a series of bilateral credit facilities with banks totaling $185million.  Several intercompany financingarrangements are also available. LG&E participates in an intercompany money pool agreement whereinLG&E

 

36

----

 

Energy and KU make funds available to LG&E at market-based rates upto $400 million.  Likewise, LG&EEnergy and LG&E make funds available to KU at market-based rates up to $400million.  Fidelia Corporation, anaffiliated company, also provides long-term intercompany funding to LG&E.

 

Certain regulatory approvals are required for the Company to incuradditional debt.  FERC and the SECauthorize the issuance of short-term debt while the Kentucky Commissionauthorizes issuance of long-term debt. As of December 31, 2003 the Company has received approvals fromFERC and the SEC to borrow up to $400 million in short-term funds, andapprovals from the Kentucky Commission for $150 million in additional long-termloans.  New long-term loans totaling$125 million were completed in January 2004.

 

LG&E’s debt ratings as of December 31, 2003, were:

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

 

These ratings reflect the views of Moody’s and S&P.  A security rating is not a recommendation tobuy, sell or hold securities and is subject to revision or withdrawal at anytime by the rating agency.  Fitch withdrewits ratings on LG&E securities effective October 14, 2003.

 

Contractual Obligations

 

The following is provided to summarize LG&E’s contractual cashobligations for periods after December 31, 2003:

 
|                                             |   | **Payments  Due by Period** |       |
|--------------------------------------------------|--------|-----------------------------|------------|
| **(in thousands)  Contractual Cash Obligations** |   | **2004**                    | ** ** | **2005-  2006** | ** ** | **2007-  2008** | ** ** | **After  2008** | ** ** | **Total** | ** ** |
| Short-term debt (a)                              |   | $                           | 80,332     |   | $ | — |   | $ | — |   | $ | — |   | $ | 80,332 |   |
| Long-term debt (b)                               |   | 247,450                     |       | 2,500 |   | 20,000 |   | 528,104 |   | 798,054 |   |
| Operating lease (c)                              |   | 3,401                       |       | 7,006 |   | 7,290 |   | 26,130 |   | 43,827 |   |
| Unconditional purchase obligations (d)           |   | 10,614                      |       | 25,182 |   | 27,195 |   | 254,235 |   | 317,226 |   |
| Other long-term obligations (e)                  |   | 20,700                      |       | 3,000 |   | — |   | — |   | 23,700 |   |
| Total contractual cash obligations (f)           |   | $                           | 362,497    |   | $ | 37,688 |   | $ | 54,485 |   | $ | 808,469 |   | $ | 1,263,139 |   |

 

----

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

(b)         Includes long-term debt of $246.2 millionclassified as current liabilities because these bonds are subject to tender forpurchase at the option of the holder and to mandatory tender for purchase uponthe occurrence of certain events. Maturity dates for these bonds range from 2013 to 2027.

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

(d)         Represents future minimum payments under purchasedpower agreements through 2023.

(e)          Represents construction commitments.

(f)            LG&E does not expect to pay the $246.2million of long-term debt classified as a current liability in the ConsolidatedBalance Sheets in 2004 as explained in (b) above.  LG&E anticipates cash from operations and external financingwill be sufficient to fund future obligations. LG&E anticipates refinancing a portion of its short-term debt withlong-term debt in 2004.

 

LG&E is aparticipant in a sale and leaseback transaction involving its 38% interest intwo jointly-owned CTs at KU’s E.W. Brown generating station (Units 6 and7).  Commencing in December 1999,LG&E and KU entered into a tax-efficient, 18-year lease of the CTs.  LG&E and KU have provided funds to fullydefease the lease,

 

37

----

 

and haveexecuted an irrevocable notice to exercise an early purchase option containedin the lease after 15.5 years.  Thefinancial statement treatment of this transaction is no different than ifLG&E had retained its ownership. The transaction produced a pre-tax gain of approximately $1.2 millionwhich was recorded in other income on the income statement in 2000, pursuant toa Kentucky Commission order.  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 currently exist with respect to the lease.  Upon any termination of the lease, whetherby default or expiration of its term, title to the CTs reverts jointly toLG&E and KU.

 

AtDecember 31, 2003, the maximum aggregate amount of default fees oramounts, which decrease over the term of the lease, was $8.9 million, of whichLG&E would be responsible for 38%. LG&E has made arrangements with LG&E Energy, via guarantee andregulatory commitment, for LG&E Energy to pay its full portion of anydefault fees or amounts.  LG&E paidLG&E Energy a one-time fee of $114,000 to provide the guarantee.

 

MARKET RISKS

 

LG&E is exposed to market risks from changes in interest rates andcommodity prices.  To mitigate changesin cash flows attributable to these exposures, LG&E uses various financialinstruments including derivatives. Derivative positions are monitored using techniques that include marketvalue and sensitivity analysis.  SeeNote 1 and 4 of LG&E’s Notes to Financial Statements under Item 8.

 

Interest Rate Sensitivity

 

LG&E has short-term and long-term variable-rate debt obligationsoutstanding.  At December 31, 2003,the potential change in interest expense associated with a 1% change in baseinterest rates of LG&E’s unhedged debt is estimated at $4.4 million afterthe impact of interest rate swaps.

 

Interest rate swaps are used to hedge LG&E’s underlyingvariable-rate debt obligations.  Theseswaps hedge specific debt issuances and, consistent with management’sdesignation, are accorded hedge accounting treatment.  See Note 4 of LG&E’s Notes to Financial Statements under Item8.

 

As of December 31, 2003, LG&E had swaps with a combinednotional value of $228.3 million.  Theswaps exchange floating-rate interest payments for fixed rate interest paymentsto reduce the impact of interest rate changes on LG&E’s pollution controlbonds.  The potential loss in fair valueresulting from a hypothetical 1% adverse movement in base interest rates isestimated at approximately $10 million as of December 31, 2003.  This estimate is derived from third-partyvaluations. Changes in the market value of these swaps if held to maturity, asLG&E intends to do, will have no effect on LG&E’s net income or cashflow.  See Note 4 of LG&E’s Notes toFinancial Statements under Item 8.

 

Commodity Price Sensitivity

 

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

 

38

----

 

# **Energy Trading & RiskManagement Activities**

# ** **

LG&E conducts energy trading and risk management activities tomaximize the value of power sales from physical assets it owns, in addition tothe wholesale sale of excess asset capacity. Certain energy trading activities are accounted for on a mark-to-marketbasis in accordance with SFAS No. 133*, Accounting for Derivative Instruments and HedgingActivities,* and SFAS No. 138*, Accounting for Certain Derivative Instruments andCertain Hedging Activities*. Wholesale sales of excess asset capacity and wholesale purchases aretreated as normal sales and purchases under SFAS No. 133 and SFAS No. 138 andare not marked to market.

 

The rescission of EITF No. 98-10 for fiscal periods ending afterDecember 15, 2002, had no impact on LG&E’s energy trading and riskmanagement reporting as all forward and option contracts marked to market underEITF No. 98-10 are also within the scope of SFAS No. 133.

 

The table below summarizes LG&E’s energy trading and risk managementactivities for 2003 and 2002.

 
| **(in thousands)**                                             |   | **2003** |   | **2002** |   |
|----------------------------------------------------------------|--------|----------|--------|----------|--------|
| Fair value of contracts at beginning of  period, net liability |   | $        | (156   | )        | $      | (186 | ) |
| Fair value of contracts when entered into  during the period   |   | 2,654    |   | (65      | )      |
| Contracts realized or otherwise settled  during the period     |   | (569     | )      | 448      |   |
| Changes in fair values due to changes in  assumptions          |   | (1,357   | )      | (353     | )      |
| Fair value of contracts at end of period,  net liability       |   | $        | 572    |     | $      | (156 | ) |

 

No changes to valuation techniques for energy trading and riskmanagement activities occurred during 2003. Changes in market pricing, interest rate and volatility assumptions weremade during both years.  All contractsoutstanding at December 31, 2003, have a maturity of less than one yearand are valued using prices actively quoted for proposed or executedtransactions or quoted by brokers.

 

LG&E maintains policies intended to minimize credit risk andrevalues credit exposures daily to monitor compliance with those policies.  At December 31, 2003, 100% of thetrading and risk management commitments were with counterparties ratedBBB-/Baa3 equivalent or better.

 

Accounts Receivable Securitization

 

On February 6, 2001, LG&E implemented an accounts receivablesecuritization program.  The purpose ofthis program was to enable LG&E to accelerate the receipt of cash from thecollection of retail accounts receivable, thereby reducing dependence upon morecostly sources of working capital.  Thesecuritization program allowed for a percentage of eligible receivables to besold.  Eligible receivables aregenerally all receivables associated with retail sales that have standard termsand are not past due.  LG&E was ableto terminate the program at any time without penalty.

 

LG&E terminated the accounts receivable securitization program inJanuary 2004 and replaced it with intercompany loans from an E.ONaffiliate.  The accounts receivableprogram required LG&E R to maintain minimum levels of net worth.  The program also contained a cross-defaultprovision if LG&E defaulted on debt obligations in excess of $25million.  If there was a significantdeterioration in the payment record of the receivables by the retail customersor if LG&E failed to meet certain covenants regarding the program, theprogram could terminate at the election of the financial institutions.  In this case, payments from retail customerswould first be used to repay the financial institutions participating in theprogram, and would then be available for use by LG&E.  LG&E did not violate any covenants withregard to the accounts receivable

 

39

----

 

securitization program.

 

As part of the program, LG&E sold retail accounts receivables to awholly owned subsidiary, LG&E R. Simultaneously, LG&E R entered into two separate three-year accountsreceivable securitization facilities with two financial institutions and theiraffiliates whereby LG&E R could sell, on a revolving basis, an undividedinterest in certain of its receivables and receive up to $75 million from anunrelated third-party purchaser.  Theeffective cost of the receivables program was comparable to LG&E’s lowestcost source of capital, and was based on prime rated commercial paper.  LG&E retained servicing rights of thesold receivables through two separate servicing agreements with the third-partypurchasers.  LG&E obtained anopinion from independent legal counsel indicating these transactions qualifiedas a true sale of receivables.  As ofDecember 31, 2003, the outstanding program balance was $58.0 million.

 

To determine LG&E’s retained interest, the proceeds on the sale ofreceivables to the financial institutions were netted against the amount ofeligible receivables sold by LG&E to LG&E R.  Interest expense, program fees, and facility fees paid to thefinancial institutions and an allowance for doubtful accounts were deducted toarrive at the future value of retained interest.  The future value was discounted using the prime rate plus 25basis points, assuming a 45-day receivable life.  Pre-tax gains and losses from the sale of the receivables in2003, 2002 and 2001 were gains of $20,648, $46,727 and a loss of $206,578,respectively.  LG&E’s net cash flowsfrom LG&E R were $(6.2) million, $20.2 million and $39.7 million for 2003,2002 and 2001, respectively.

 

The allowance for doubtful accounts associated with the eligiblesecuritized receivables at December 31 was $1.4 million, $1.9 million and$1.3 million in 2003, 2002 and 2001, respectively.  This allowance was based on historical experience of LG&E.Each securitization facility contained a fully funded reserve for uncollectiblereceivables.

 

RATES AND REGULATION

 

LG&E is subject to the jurisdiction of the Kentucky Commission invirtually all matters related to electric and gas utility regulation, and assuch, its accounting is subject to SFAS No. 71, *Accounting for the Effects of CertainTypes of Regulation*.  GivenLG&E’s competitive position in the marketplace and the status of regulationin Kentucky, LG&E has no plans or intentions to discontinue its applicationof SFAS No. 71.  See Note 3 ofLG&E’s Notes to Financial Statements under Item 8.

 

**Kentucky CommissionSettlement Order - VDT Costs, ESM and Depreciation.**  During the first quarter of 2001, LG&Erecorded a $144 million charge for a workforce reduction program.  Primary components of the charge were separationbenefits, enhanced early retirement benefits, and healthcare benefits.  The result of this workforce reduction wasthe elimination of approximately 700 positions, accomplished primarily througha voluntary enhanced severance program.

 

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

 

LG&E reached a settlement in the VDT case as well as other casesinvolving the depreciation rates and ESM with all intervening parties.  The settlement agreement was approved by aKentucky Commission order in December 2001.  The order allowed LG&E

 

40

----

 

to set up a regulatory asset of $141 million for the workforcereduction costs and begin amortizing these costs over a five year periodstarting in April 2001.  The firstquarter 2001 charge of $144 million represented all employees who had accepteda voluntary enhanced severance program. Some employees rescinded their participation in the voluntary enhancedseverance program, thereby decreasing the original charge to the regulatoryasset from $144 million to $141 million. The settlement reduces revenues approximately $26 million through asurcredit on bills to ratepayers over the same five-year period.  The surcredit represents stipulated netsavings LG&E is expected to realize from implementation of best practicesthrough the VDT.  The agreement alsoestablished new depreciation rates in effect December 2001, retroactive toJanuary 2001.  The new depreciationrates decreased depreciation expense by $5.6 million in 2001.

 

**ECR.**  In June 2000, the Kentucky Commissionapproved LG&E’s application for a CCN to construct up to three SCR NOxreduction facilities. The construction and subsequent operation of the SCRs isintended to reduce NOx emission levels to meet the EPA’s mandated NOx emissionlevel of 0.15 lbs./ Mmbtu by May 2004. In its order, the Kentucky Commission ruled that LG&E’s proposedplan for construction was “reasonable, cost-effective and will not result inthe wasteful duplication of facilities.” In October 2000, LG&E filed an application with the KentuckyCommission to amend its Environmental Compliance Plan to reflect the additionof the proposed NOx reduction technology projects and to amend itsEnvironmental Cost Recovery Tariff to include an overall rate of return oncapital investments. Approval of LG&E’s application in April 2001allowed LG&E to begin to recover the costs associated with these newprojects, subject to Kentucky Commission oversight during normal six-month andtwo-year reviews.

 

In May 2002, the Kentucky Commission initiated a periodic two-yearreview of LG&E’s environmental surcharge. The review included the operation of the surcharge mechanism,determination of the appropriateness of costs included in the surchargemechanism, recalculation of the cost of debt to reflect actual costs for theperiod under review, final determination of the amount of environmentalrevenues over-collected from customers, and a final determination of the amountof environmental costs and revenues to be “rolled-in” to base rates.  A final order was issued inOctober 2002, in which LG&E was ordered to refund $0.3 million tocustomers over the four month period beginning November 2002 and endingFebruary 2003.  Additionally,LG&E was ordered to roll $4.1 million into base rates and makecorresponding adjustments to the monthly environmental surcharge filings toreflect that portion of environmental rate base now included in base ratesgoing forward.

 

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

 

In January 2003, the Kentucky Commission initiated a six-monthreview of LG&E’s environmental surcharge. 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 Commissioninitiated a two-year review of LG&E’s environmental surcharge.  A final order was issued inDecember 2003, in which LG&E was ordered to roll $15.2 million ofenvironmental assets into base rates and make corresponding adjustments to themonthly environmental surcharge filings to reflect that portion ofenvironmental rate base now included in base rates on a going-forwardbasis.  Additionally, LG&E wasordered to collect $0.2 million to correct for amounts under-collected

 

41

----

from customers.  The rates of return for LG&E’s 1995 andpost-1995 plans were reset to 3.32% and 10.92%, respectively.

 

**ESM. **LG&E’selectric rates are subject to an ESM. The ESM, initially in place for three years beginning in 2000, sets anupper and lower point for rate of return on equity, whereby if LG&E’s rateof return for the calendar year falls within the range of 10.5% to 12.5%, noaction is necessary.  If earnings areabove the upper limit, the excess earnings are shared 40% with ratepayers and 60%with shareholders; if earnings are below the lower limit, the earningsdeficiency is recovered 40% from ratepayers and 60% from shareholders.  By order of the Kentucky Commission, ratechanges prompted by the ESM filing go into effect in April of each year subjectto a balancing adjustment in successive periods.

 

In November 2002, LG&Efiled a revised ESM tariff which proposed continuance of the existing ESMthrough December 2005.  In addition, theKentucky Commission initiated a focused management audit to review the ESM planand reassess its reasonableness, and recently concluded discovery in thecase.  LG&E and interested partieshad the opportunity to provide recommendations for modification and continuanceof the ESM or other forms of alternative or incentive regulation.  Continuance of the ESM is still beingdeliberated by the Kentucky Commission and a final order is not expected untilthe second quarter of 2004.  The ESMtariff remains in effect pending the resolution of the case.

 

LG&E made its third ESMfiling in February 2003, for the calendar year 2002 reporting period.  LG&E is in the process of recovering$13.6 million from customers for the 2002 reporting period.  LG&E estimated that the rate of returnwill fall below the lower limit, subject to Kentucky Commission approval, forthe year ended December 31, 2003.  The2003 financial statements include an accrual to reflect the earnings deficiencyof $8.9 million to be recovered from customers commencing in April 2004.

 

**DSM. **LG&E’s ratescontain a DSM provision.  The provisionincludes a rate mechanism that provides concurrent recovery of DSM costs andprovides an incentive for implementing DSM programs.  This provision allowed LG&E to recover revenues from lostsales associated with the DSM programs. In May 2001, the Kentucky Commission approved LG&E’s plan tocontinue DSM programs.  This plan calledfor the expansion of the DSM programs into the service territory served by KUand proposed a mechanism to recover revenues from lost sales associated withDSM programs based on program plan engineering estimates andpost-implementation evaluation.

 

**Gas Supply Cost PBR Mechanism. **Since November 1,1997, LG&E has operated under an experimental PBR mechanism related to itsgas procurement activities.  For each ofthe last five years, LG&E’s rates have been adjusted to recover its portionof the savings (or expenses) incurred during each of the five 12-month periodsbeginning November 1 and ending October 31. Since its implementation onNovember 1, 1997, through October 31, 2003, LG&E has achieved $51.7 millionin savings. Of that total savings amount, LG&E’s portion has been $20.5million and the ratepayers’ portion has been $31.2 million.  Pursuant to the extension of LG&E gassupply cost PBR mechanism effective November 1, 2001, the sharing mechanismunder the PBR requires savings (and expenses) to be shared 25% withshareholders and 75% with ratepayers up to 4.5% of the benchmarked gascosts.  Savings (and expenses) in excessof 4.5% of the benchmarked gas costs are shared 50% with shareholders and 50%with ratepayers.  LG&E is obligatedto file a report and assessment with the Kentucky Commission by December 31,2004, seeking an extension or modification of the mechanism.

 

**FAC. **LG&Eemploys an FAC mechanism, which under Kentucky law allows LG&E to recoverfrom customers the actual fuel costs associated with retail electricsales.  In February 1999, LG&Ereceived orders from the Kentucky Commission requiring a refund to retailelectric customers of approximately $3.9 million

 

42

----

 

resulting from reviews of theFAC from November 1994 through April 1998. While legal challenges to the Kentucky Commission order were pending, a comprehensive settlement was reached byall parties and approved by the Kentucky Commission in May 2002.  Thereunder, LG&E agreed to credit itsfuel clause in the amount of $0.7 million (such credit provided over the courseof June and July 2002), and the parties agreed on a prospective interpretationof the state’s fuel adjustment clause regulation to ensure consistent andmutually acceptable application going forward.

 

In January 2003, the KentuckyCommission reviewed KU’s FAC for the six-month period ending October 2002 and,as part of the Order in that case, required that an independent audit beconducted to examine operational and management aspects of both KU’s andLG&E’s fuel procurement functions. The final report was issued in February 2004.  The report’s recommendations related to documentation and processimprovements will be addressed with the Kentucky Commission staff as ManagementAudit Action Plans are developed in the second quarter of 2004.

 

The Kentucky Commissionrequires 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.  No significant issueshave been identified as a result of these reviews.

 

**Electric and Gas Rate Cases. **In December 2003,LG&E filed applications with the Kentucky Commission requesting adjustmentsin LG&E’s electric and gas rates. LG&E requested general adjustments in electric and gas rates basedon the twelve month test year ended September 30, 2003.  The revenue increases requested were $63.8million for electric and $19.1 million for gas.  The Kentucky Commission has suspended the effective date of theproposed new tariffs for five months, so that the rates may go into effectsubject to refund by July 1, 2004.  TheKentucky Commission established a procedural schedule for the cases pertainingto discovery and hearings.  Hearings arescheduled in May 2004.  LG&E expectsthe Kentucky Commission to issue orders in the cases before new rates go intoeffect July 1, 2004.

 

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

 

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

 

In April 2003, LG&Eproposed a hedge plan for the 2003/2004 winter heating season with twoalternatives, the first relying upon LG&E’s storage and the second relyingupon a combination of LG&E’s storage and financial hedge instruments.  In July 2003, the Kentucky Commissionapproved LG&E’s first alternative which relies upon storage to mitigate theprice volatility to which customers might otherwise be exposed.  The Kentucky Commission validated theeffectiveness of storage to mitigate potential volatility associated with highwinter gas prices by approving this natural gas hedge plan.

 

**Kentucky CommissionAdministrative Case for Affiliate Transactions. **In December 1997, the KentuckyCommission opened Administrative Case No. 369 to consider Kentucky Commissionpolicy regarding cost allocations, affiliate transactions and codes of conductgoverning the relationship between utilities and their non-utility operationsand affiliates.  The Kentucky Commissionintended to address two major areas in the proceedings: the tools andconditions needed to prevent cost shifting and cross-subsidization betweenregulated and non-utility operations; and whether a code of conduct should beestablished to assure that

 

43

----

 

 non utility segments of the holding company are not engaged inpractices that could result in unfair competition caused by cost shifting fromthe non-utility affiliate to the utility. In early 2000, the  KentuckyGeneral Assembly enacted legislation, House Bill 897, which authorized theKentucky Commission to require utilities that provide nonregulated activitiesto keep separate accounts and allocate costs in accordance with proceduresestablished by the Kentucky Commission. In the same bill, the General Assembly set forth provisions to govern autility’s activities related to the sharing of information, databases, andresources between its employees or an affiliate involved in the marketing orthe provision of nonregulated activities and its employees or an affiliateinvolved in the provision of regulated services. The legislation became law inJuly 2000 and LG&E has been operating pursuant thereto since thattime.  In February 2001, the KentuckyCommission published notice of their intent to promulgate new administrativeregulations under the auspices of the new law. This effort is still ongoing.

 

**Kentucky CommissionAdministrative Case for System Adequacy. **In June 2001, Kentucky’s Governor issuedExecutive Order 2001-771, which directed the Kentucky Commission to review andstudy issues relating to the need for and development of new electricgenerating capacity in Kentucky.  Inresponse to that Executive Order, the Kentucky Commission opened AdministrativeCase No. 387 to review the adequacy of Kentucky’s generation capacity andtransmission system.  Specifically, theitems reviewed were the appropriate level of reliance on purchased power, theappropriate reserve margins to meet existing and future electric demand, theimpact of spikes in natural gas prices on electric utility planning strategies,and the adequacy of Kentucky’s electric transmission facilities.  In December 2001, the Kentucky Commissionissued an order in which it noted that LG&E is responsibly addressing thelong-term supply needs of native load customers and that current reserve marginsare appropriate.  However, due to the rapidpace of change in the industry, the order also requires LG&E to provide anannual assessment of supply resources, future demand, reserve margin, and theneed for new resources.

 

Regarding the transmissionsystem, the Kentucky Commission concluded that the transmission system withinKentucky can reliably serve native load and a significant portion of theproposed new unregulated power plants. However, it will not be able to handlethe volume of transactions envisioned by FERC without future upgrades, thecosts of which should be borne by those for whom the upgrades are required.

 

The Kentucky Commission pledgedto continue to monitor all relevant issues and advocate Kentucky’s interests atall opportunities.

 

**FERC SMD NOPR. **On July 31, 2002, FERC issued a NOPR inDocket No. RM01-12-000 which would substantially alter the regulationsgoverning the nation’s wholesale electricity markets by establishing a commonset of rules, defined as SMD. The SMD NOPR would require each public utilitythat owns, operates, or controls interstate transmission facilities to becomean Independent Transmission Provider (ITP), belong to an RTO that is an ITP, orcontract with an ITP for operation of its transmission assets. It would alsoestablish a standardized congestion management system, real-time and day-aheadenergy markets, and a single transmission service for network andpoint-to-point transmission customers. Review of the proposed rulemaking isunderway and no time frame has been established by the FERC for adoption of afinal rule.  While it is expected thatthe SMD final rule will affect LG&E revenues and expenses, the specificimpact of the rulemaking is not known at this time.

 

**MISO. **LG&E and KU are founding members of theMISO.  Membership was obtained in 1998in response to and consistent with federal policy initiatives.  In February 2002, LG&E and KU turnedover operational control of their high voltage transmission facilities (100kVand above) to the MISO.  The MISOcurrently controls over 100,000 miles of transmission over 1.1 million squaremiles located in the northern Midwest between Manitoba,

 

44

----

 

Canada and Kentucky.  In September 2002, FERC granted a 12.88% ROEon transmission facilities for LG&E, KU and the rest of the MISO owners.

 

In October 2001, the FERCissued an order requiring that the bundled retail load and grandfatheredwholesale load of each member transmission owner be included in the currentcalculation of the MISO’s “cost-adder,” the Schedule 10 charges designed torecover the MISO’s costs of operation, including start-up capital (debt)costs.  LG&E and KU, along withseveral other transmission owners, opposed the FERC’s ruling on this matter.The opposition was rejected by the FERC in 2002.  Later that year, the MISO’s transmission owners, appealed theFERC’s decision to the United States Court of Appeals for the District ofColumbia Circuit.  In response, inNovember 2002, the FERC requested that the Court issue a partial remand of itschallenged orders to allow the FERC to revisit certain issues, and requestedthat the case be held in abeyance pending the agency’s resolution of suchissues.  The Court granted the FERC’spetition in December 2002.  In February2003, FERC issued an order reaffirming its position concerning the calculationof the Schedule 10 charges and in July 2003 denied a rehearing.  LG&E and KU, along with several othertransmission owners, have again petitioned the District Court of ColumbiaCircuit for review.  This case is currentlypending.

 

As a separate matter, MISO, itstransmission owners and other interested industry segments reached a settlementin mid-2002 regarding the level**of cost responsibility properly borne bybundled and grandfathered load under these FERC rulings (such settlementexpressly not prejudicing the transmission owners’ and LG&E’s right tochallenge the FERC’s ruling imposing cost responsibility on bundled loads inthe first instance).  In February 2003,FERC accepted a partial settlement between MISO and the transmissionowners.  FERC did not accept the onlycontested section of the settlement, which would have allowed the transmissionowners to immediately treat unrecoverable Schedule 10 charges as regulatoryassets.  FERC will consider allowing regulatoryasset treatment of unrecoverable Schedule 10 charges on a case-by-case basis.

 

The MISO plans to implement acongestion management system in December 2004, in compliance with FERC Order2000.  This system will be similar tothe Locational Marginal Pricing (LMP) system currently used by the PJM RTO andcontemplated in FERC’s SMD NOPR, currently being discussed.  The MISO filed with FERC a mechanism forrecovery of costs for the congestion management system.  They proposed the addition of two new Schedules,16 and 17.  Schedule 16 is the MISO’scost recovery mechanism for the Financial Transmission Rights AdministrativeService it will provide.  Schedule 17 isthe MISO’s mechanism for recovering costs it will incur for providing EnergyMarketing Support Administrative Service. The MISO transmission owners, including LG&E and KU, have objectedto the allocation of costs among market participants and retail nativeload.  A hearing at FERC has beencompleted, but a ruling has not been issued.

 

The Kentucky Commission openedan investigation into LG&E’s and KU’s membership in MISO in July 2003. TheKentucky Commission directed LG&E and KU to file testimony addressing thecosts and benefits of MISO membership both currently and over the next five yearsand other legal issues surrounding continued membership.  LG&E and KU engaged an independentthird-party to conduct a cost benefit analysis on this issue.  The information was filed with the KentuckyCommission in September 2003.  Theanalysis and testimony supported the exit from MISO, under certainconditions.  The MISO filed its owntestimony and cost benefit analysis in December 2003.  A final Kentucky Commission order is expected in the secondquarter of 2004.

 

**Merger Surcredit. **As part of the LG&E Energy mergerwith KU Energy in 1998, LG&E Energy estimated non-fuel savings over aten-year period following the merger. Costs to achieve these savings for LG&E of $50.2 million wererecorded in the second quarter of 1998, $18.1 million of which was deferred andamortized over a five-year period pursuant to regulatory orders.  Primary components of the merger costs wereseparation

 

45

----

 

benefits, relocation costs, andtransaction fees, the majority of which were paid by December 31, 1998.  LG&E expensed the remaining costsassociated with the merger ($32.1 million) in the second quarter of 1998.

 

In approving the merger, theKentucky Commission adopted LG&E’s proposal to reduce its retail customers’bills based on one-half of the estimated merger-related savings, net ofdeferred and amortized amounts, 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 KU and 47% to LG&E.  In that same order, the Kentucky Commissionrequired LG&E and KU, after the end of the five-year period, to present aplan for sharing with ratepayers the then-projected non-fuel savings associatedwith 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 Kentucky Commission issued an order approving asettlement agreement reached with the parties in the case. LG&E’s mergersurcredit will remain in place for another five-year term beginning July 1,2003 and the merger savings will continue to be shared 50% with ratepayers and50% with shareholders.

 

Any fuel cost savings arepassed to Kentucky customers through the fuel adjustment clause.  See FAC above.

 

**EnvironmentalMatters.**  LG&E is subject to SO2 and NOx emission limits onits electric generating units pursuant to the Clean Air Act.  LG&E was not subject to Phase I SO2emissions reduction requirements. LG&E’s strategy for Phase II SO2 reductions, whichcommenced January 1, 2000, is to increase FGD removal efficiency to delayadditional capital expenditures and may also include fuel switching orupgrading FGDs.  LG&E met the NOxemission requirements of the Act through installation of low-NOx burnersystems.  LG&E’s compliance plansare subject to many factors including developments in the emission allowanceand fuel markets, future regulatory and legislative initiatives, and advancesin clean air control technology. LG&E will continue to monitor these developments to ensure that itsenvironmental obligations are met in the most efficient and cost-effectivemanner.

 

In September 1998, the EPAannounced its final “NOx SIP Call” rule requiring states to impose significantadditional reductions in NOx emissions by May 2003, in order to mitigatealleged ozone transport impacts on the Northeast region.  The Commonwealth of Kentucky SIP, which wasapproved by EPA June 24, 2003, requires reductions in NOx emissions fromcoal-fired generating units to the 0.15 lb./Mmbtu level on a system-widebasis.  In related proceedings inresponse to petitions filed by various Northeast states, in December 1999, EPAissued a final rule pursuant to Section 126 of the Clean Air Act directingsimilar NOx reductions from a number of specifically targeted generating unitsincluding all LG&E units.  As aresult of appeals to both rules, the compliance date was extended to May2004.  All LG&E generating units aresubject to the May 2004 compliance date under these NOx emissions reductionrules.

 

LG&E is currentlyimplementing a plan for adding significant additional NOx controls to itsgenerating units.  Installation ofadditional NOx controls will proceed on a phased basis, with installation ofcontrols commencing in late 2000 and continuing through the final compliancedate.  LG&E estimates that it willincur total capital costs of approximately $185 million to reduce its NOxemissions to the 0.15 lb./Mmbtu level on a company-wide basis.  As of December 31, 2003, LG&E hasincurred approximately $177 million of these capital costs related to thereduction of its NOx emissions.  Inaddition, LG&E will incur additional operating and maintenance costs inoperating new NOx controls.  LG&Ebelieves its costs in this regard to be comparable to those of similarly situatedutilities with like generation assets. LG&E had anticipated that such capital and operating costs are thetype of costs that are eligible for recovery from customers under itsenvironmental surcharge mechanism and

 

46

----

 

believed that a significantportion of such costs could be recovered. In April 2001, the Kentucky Commission granted recovery of these costsfor LG&E.

 

LG&E is also monitoringseveral other air quality issues which may potentially impact coal-fired powerplants, including EPA’s revised air quality standards for ozone and particulatematter, measures to implement EPA’s regional haze rule, and EPA’s December 2003proposals to regulate mercury emissions from steam electric generating unitsand to further reduce emissions of sulfur dioxide and nitrogen oxides under theInterstate Air Quality Rule.  Inaddition, LG&E is currently working with local regulatory authorities toreview the effectiveness of remedial measures aimed at controlling particulatematter emissions from its Mill Creek Station. LG&E previously settled a number of property damage claims fromadjacent residents and completed significant remedial measures as part of itsongoing capital construction program. LG&E is in the process of convertingthe Mill Creek Station to wet stack operation in an effort to resolve alloutstanding issues related to particulate matter emissions.

 

LG&E owns or formerly ownedthree properties which are the location of past MGP operations.  Various contaminants are typically found atsuch former MGP sites and environmental remediation measures are frequentlyrequired.  With respect to the sites,LG&E has completed cleanups, obtained regulatory approval of sitemanagement plans, or reached agreements for other parties to assumeresponsibility for cleanup.  Based oncurrently available information, management estimates that it will incuradditional costs of $0.4 million.  Accordingly,an accrual of $0.4 million has been recorded in the accompanying financialstatements at December 31, 2003 and 2002.

 

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

 

**Deferred Income Taxes. **LG&E expects tohave adequate levels of taxable income to realize its recorded deferred taxassets.  At December 31, 2003, deferredtax assets totaled $80.7 million and were principally related to expensesattributable to LG&E’s pension plans and post retirement benefit obligations.

 

FUTURE OUTLOOK

 

Competition and Customer Choice

 

In the last several years,LG&E has taken many steps to keep its rates low while maintaining highlevels of customer satisfaction, including a reduction in the number ofemployees; aggressive cost cutting; an increase in focus on commercial, industrialand residential customers; an increase in employee involvement and training;and continuous modifications of its organizational structure.

 

At this time, neither theKentucky General Assembly nor the Kentucky Commission has adopted or approved aplan or timetable for retail electric industry 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.

 

47

----

 

KU

 

RESULTS OF OPERATIONS

 

Net Income

 

KU’s net income in 2003decreased $2.0 million (2.1%) compared to 2002.  The decrease resulted primarily from increased depreciationexpense due to plant additions, partially offset by increased sales to retailand wholesale customers.

 

KU’s net income in 2002decreased $3.0 million (3.1%) compared to 2001.  The decrease resulted primarily from higher transmissionexpenses, increased amortization of the VDT regulatory asset, and increasedproperty insurance, partially offset by an increase in sales to retailcustomers and lower interest expenses.

 

Revenues

 

A comparison of operatingrevenues for the years 2003 and 2002, excluding the provision for ratecollections (refunds), with the immediately preceding year reflects bothincreases and decreases which have been segregated by the following principalcauses:

 
|                                  |   | **Increase  (Decrease)  From Prior Period** | ** ** |
|---------------------------------------|--------|---------------------------------------------|------------|
| **Cause (in thousands)**              |   | **2003**                                    | ** ** | **2002** | ** ** |
| Retail sales:                         |   |                                        |       |   |   |
| Fuel clause adjustments               |   | $                                           | 20,959     |   | $ | 18,223 |   |
| KU/LG&E Merger surcredit          |   | (1,254                                      | )          | (2,641 | ) |
| Environmental cost recovery surcharge |   | 6,038                                       |       | 3,781 |   |
| Earnings sharing mechanism            |   | 8,718                                       |       | (612 | ) |
| Demand side management                |   | 365                                         |       | 1,570 |   |
| VDT surcredit                         |   | (1,740                                      | )          | (527 | ) |
| Variation in sales volumes, and other |   | (1,755                                      | )          | 45,514 |   |
| Total retail sales                    |   | 31,331                                      |       | 65,308 |   |
| Wholesale sales                       |   | 20,751                                      |       | (47,178 | ) |
| Other                                 |   | 2,047                                       |       | 7,133 |   |
| Total                                 |   | $                                           | 54,129     |   | $ | 25,263 |   |

 

Electric revenues increased in2003 primarily due to an increase in the recovery of fuel costs passed throughthe FAC and higher wholesale sales. Retail volumes decreased 0.2% as lower sales due to a milder summer thanthe previous year were offset by higher sales during the winter, when weatherwas colder than the previous year. Cooling degree days for 2003 decreased 38%from 2002 and were 21% below the 20-year average while heating degree daysincreased 3% from 2002 and 3% above the 20-year average.  Wholesale revenues increased due to acombination of a 28.6% increase in volumes and 3.8% higher prices. Electricrevenues increased in 2002 primarily due to an increase in retail sales volumesby 6% due to warmer summer weather and an increase in the recovery of fuelcosts passed through the FAC.  Coolingdegree days for 2002 increased 26% over 2001 and were 28% above the 20-yearaverage. The increase in retail sales was partially offset by a decrease inwholesale sales volumes. The decrease in wholesale sales was due in large partto fewer megawatts available due to increased retail sales.

 

The decrease in the provisionfor rate collections (refunds) in 2003 from 2002 ($24.0 million) resultsprimarily from ESM revenues billed to customers during 2003 ($8.0 million), adecrease in the ESM accruals ($5.5 million), a decrease in 2003 fuel accruals($6.0 million), and a decrease in ECR accruals during 2003 ($4.5 million). Theincrease in the provision for rate collections (refunds) in 2002 over 2001($15.7 million) is due

 

48

----

 

primarily to the ESM accruals($13.0 million) and an increase in 2002 fuel accruals ($4.2 million), partiallyoffset by a decrease in 2002 ECR accruals ($1.5 million).

 

Expenses

 

Fuel for electric generationcomprises a large component of KU’s total operating expenses.  KU’s Kentucky jurisdictional electric ratesare subject to an FAC whereby increases or decreases are reflected in the FACfactor, subject to the approval of the Kentucky Commission and passed through toKU’s retail customers.  KU’s municipaland Virginia jurisdictional electric rates contain a fuel adjustment clausewhereby increases or decreases in the cost of fuel are reflected in rates,subject to the approval of FERC and the Virginia Commission, respectively.

 

Fuel for electric generationincreased $15.8 million (6.3%) in 2003 because of an increase in the cost ofcoal burned ($18.9 million), partially offset by a decrease in generation ($3.1million).  Fuel for electric generationincreased $13.1 million (5.5%) in 2002 because of an increase in the cost ofcoal burned ($29.7 million), partially offset by a decrease in generation($16.5 million).  The average deliveredcost per ton of coal purchased was $34.91 in 2003, $31.44 in 2002 and $27.84 in2001.

 

Power purchased expense in 2003increased $8.7 million (6.6%) over 2002, primarily due to an increase inpurchases to meet off-system sales requirements partially offset by a decreasein purchase price.  Power purchasedexpense in 2002 increased $13.0 million (11.0%) over 2001, primarily due to anincrease in purchases to meet requirements for native load and off-system salesand an increase in purchase price.

 

Other operation expensesincreased $1.5 million (1.0%) in 2003 due primarily to increased employeebenefits costs ($4.7 million) and increased property insurance expenses ($1.4million), partially offset by a decrease in expenses from the amortization ofregulatory assets ($4.7 million).  Otheroperation expenses increased $25.8 million (21.8%) in 2002. The primary causefor the increase was the full year amortization in 2002 of a regulatory assetcreated as a result of the workforce reduction associated with KU’s VDT ($6.5million), higher costs for electric transmission primarily resulting fromincreased MISO costs ($7.4 million), an increase in property insurance costs($2.8 million), an increase in employee benefit costs due to changes in pensionassumptions to reflect current market conditions and changes in market value ofplan assets at the measurement date ($1.7 million), and an increase in outsideservices ($4.9 million).

 

Maintenance expenses decreased$2.6 million (4.2%) in 2003 due primarily to a decrease in maintenance of steampowered and combustion turbine generation ($5.1 million) due to cancellationand postponement of scheduled outages and a decrease in communicationsmaintenance expenses ($1.0 million), partially offset by an increase in repairsto electric distribution equipment due to an ice storm ($4.1 million, net of$8.9 million in insurance recoveries). Maintenance expenses increased $5.9 million (10.3%) in 2002 primarilydue to increases in steam maintenance ($6.1 million) related to annual outagesat the Ghent, Green River, and Tyrone steam facilities.

 

Depreciation and amortizationincreased $6.3 million (6.6%) in 2003 and $5.2 million (5.7%) in 2002 primarilydue to an increase in plant in service.

 

Variations in income taxexpense are largely attributable to changes in pre-tax income.  The 2003 effective income tax rate increasedto 35.4% from the 34.9% rate in 2002. See Note 7 of KU’s Notes to FinancialStatements under Item 8.

 

49

----

 

Property and other taxesincreased $0.9 million (6.0%) in 2003 due to higher property taxes and anincrease in the Kentucky Commission assessment.  Property and other taxes increased $1.1 million (7.6%) in 2002due to higher property taxes and payroll taxes.

 

Other income - net decreased$1.3 million (12.8%) in 2003 due primarily to a decrease in earnings from KU’sequity earnings in a minority interest ($3.4 million) and write-off from CWIPfor a terminated software project partially offset by a decrease in benefitcosts ($1.3 million) and an increase in AFUDC income ($1.0 million) associatedprimarily with construction on NOx and CT projects.  Other income - net increased $1.5 million (16.8%) in 2002primarily due to a non-recurring increase in earnings from KU’s equity earningsin a minority interest ($5.2 million), partially offset by a gain ondisposition of property in 2001 ($1.8 million), lower interest and dividendincome from investments ($0.7 million), and higher benefit and other costs($1.4 million).  The increased equityearnings in 2002 are due to the gain on the sale of emissions allowances.

 

Interest charges decreased $0.4million (1.7%) in 2003 due primarily to savings from lower average interestrates on variable-rate long-term bonds ($6.6 million), the maturing firstmortgage bonds Series Q in June 2003 ($2.1 million), and an increase ininterest income from interest rate swaps ($0.8 million) offset by interestexpense on new fixed-rate debt with an affiliated company ($4.7 million) andadditional expenses recognized from mark-to-market adjustments of underlyingdebt associated with the interest rate swaps ($5.1 million).  Interest charges decreased $8.3 million(24.5%) in 2002 as compared to 2001 due to lower interest rates onvariable-rate debt and refinancing of long-term debt with lower interest rates($8.0 million).

 

The weighted average interestrate on variable-rate long-term bonds for 2003, 2002 and 2001 was 1.07%, 1.56%and 3.02%, respectively.  At December31, 2003, 2002 and 2001, KU’s percentage of long-term debt having avariable-rate, including the impact of interest rate swaps, was 53.6% at $368.6million, 73.8% at $369.5 million and 45.8% at $223.6 million, respectively.  KU’s weighted average cost of long-termdebt, including amortization of debt expense and interest rate swaps, was 2.96%and 3.30% at December 31, 2003 and 2002, respectively.  See Note 9 of KU’s Notes to the FinancialStatements under Item 8.

 

The rate of inflation may havea significant impact on KU’s operations, its ability to control costs and theneed to seek timely and adequate rate adjustments.  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 the applicationof appropriate technical accounting rules and guidance, as well as the use ofestimates.  The application of thesepolicies necessarily involves judgments regarding future events, includinglegal and regulatory challenges and anticipated recovery of costs.  These judgments, in and of themselves, couldmaterially impact the financial statements and disclosures based on varyingassumptions, which may be appropriate to use. In addition, the financial and operating environment also may have asignificant effect, not only on the operation of the business, but on theresults reported through the application of accounting measures used inpreparing the financial statements and related disclosures, even if the natureof the accounting policies applied has not changed.  Specific risks for these critical accounting policies aredescribed in the following paragraphs. Each of these has a higher likelihood of resulting in materially differentreported amounts under different conditions or using different assumptions.  Events rarely develop exactly as forecastand the best estimates routinely require adjustment.  See also Note 1 of KU’s Notes to Financial Statements under Item8.

 

50

----

 

Financial Instruments**–** KU uses over-the-counter interest-rateswap agreements to hedge its exposure to interest rates.  Gains and losses on interest-rate swaps usedto hedge interest rate risk are reflected in interest charges monthly.  KU uses sales of market-traded electricforward contracts for periods less than one year to hedge the price volatilityof its forecasted peak electric off-system sales.  Gains and losses resulting from ineffectiveness are shown inother income (expense) and to the extent that the hedging relationship has beeneffective, gains and losses are reflected in other comprehensive income.  See Note 4 – Financial Instruments.

 

Unbilled Revenue – At eachmonth end KU prepares a financial estimate that projects electric usage thathas been used by customers, but not 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 is then multiplied by eachday’s system net deliveries to determine an estimated billed and unbilledvolume for each day of the accounting period. At December 31, 2003, a 10% change in these estimated quantities wouldcause revenue and accounts receivable to change by approximately $3.9million.  See also Note 1 of KU’s Notesto Financial Statements under Item 8.

 

Allowance for Doubtful Accounts– At December 31, 2003 and 2002, the KU allowance for doubtful accounts was$0.7 million and $0.8 million, respectively. The allowance is based on theratio of the amounts charged-off during the last twelve months to the retailrevenues billed over the same period multiplied by the retail revenues billedover the last four months.  Accountswith no payment activity are charged-off after four months.

 

Benefit Plan Accounting –Judgments and uncertainties in benefit plan accounting include future rate ofreturns on pension plan assets, interest rates used in valuing benefitobligation, healthcare cost trend rates and other actuarial assumptions.

 

KU’s costs of providing defined-benefit pension retirement plans isdependent upon a number of factors, such as the rates of return on plan assets,discount rate, and contributions made to the plan.  At December 31, 2002, KU was required to recognize an additionalminimum liability as prescribed by SFAS No. 87 *Employers’ Accounting for Pensions*.  The liability was recorded as a reduction toother comprehensive income, and did not affect net income.  The amount of the liability depended uponthe asset returns experienced in 2002 and contributions made by KU to the planduring 2002.  If the fair value of theplan assets exceeds the accumulated benefit obligation, the recorded liabilitywill be reduced and other comprehensive income will be restored in theconsolidated balance sheet.

 

During 2002, the combination of poor market performance andhistorically low corporate bond rates created a divergence in the potentialvalue of the pension liabilities and the actual value of the pensionassets.  Market performance in 2003reversed the negative trend.  Shouldpoor market conditions return, these conditions could result in an increase inKU’s funded accumulated benefit obligations and future pension expense.  The primary assumptions that drive the valueof the unfunded accumulated benefit obligations are the discount rate andexpected return on plan assets.

 

KU made contributions to thepension plan of $3.5 million in January 2003, $6.0 million in September 2003and $43.4 million in January 2004.

 

A 1% increase or decrease in the assumed discount rate could have anapproximate $27 million positive or negative impact to the accumulated benefitobligation of KU.

 

51

----

 

See also Note 6 of KU’s Notesto Financial Statements under Item 8.

 

Regulatory Mechanisms –Judgments and uncertainties include future regulatory decisions, the impact ofderegulation and competition on the ratemaking process and external regulatordecisions.

 

Regulatory assets represent incurred costs that have been deferredbecause they are probable of future recovery in customer rates based uponKentucky Commission orders.  Regulatoryliabilities generally represent obligations to make refunds to customers forprevious collections based upon orders by the Kentucky Commission.  Management believes, based on orders, theexisting regulatory assets and liabilities are probable of recovery.  This determination reflects the current regulatoryclimate in the state.  If futurerecovery of costs ceases to be probable the assets would be required to berecognized in current period earnings.

 

KU has accrued in the financial statements an estimate of $9.3 millionfor 2003 ESM, with collection from customers commencing in April 2004.  The ESM is subject to Kentucky Commissionapproval.  See also Note 3 of KU’s Notesto Financial Statements under Item 8.

 

NEW ACCOUNTING PRONOUNCEMENTS

 

The following accounting pronouncements were implemented by KU in 2003:

 

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

 

The effective implementationdate for SFAS No. 143 was January 1, 2003. Management has calculated the impact of SFAS No. 143 and FERC FinalOrder No. 631 issued in Docket No. RM02-7, *Accounting, Financial Reporting, and Rate Filing Requirementsfor Asset Retirement Obligations. *TheCompany evaluated the impact of SFAS 143 from both a legal and operationsperspective, reviewing applicable laws and regulations affecting theindustry,  contracts, permits,certificates of need and right of way agreements, to determine if legalobligations existed.   The fair value offuture removal obligations was calculated based on the Company’s engineeringestimates, costs expended for similar retirements and third party estimates atcurrent market prices inflated at a rate of 2.31% per year to the expectedretirement date of the asset.  Thefuture removal obligations were then discounted to their net present value atthe original asset in-service date based on a discount rate of 6.61%.  ARO assets equal to the net present valuewere recorded on the Company’s books at implementation.  An amount equal to the net present valueplus the accretion the Company would have accrued had the standard been ineffect at the original in service date was also recorded on the Company’s booksas an ARO liability at implementation. Additionally, the Company contracted with an independent consultant toquantify the cost of removal included in its accumulated depreciation underregulatory accounting practices.

 

As of January 1, 2003, KUrecorded asset retirement obligation (ARO) assets in the amount of $8.6 millionand liabilities in the amount of $18.5 million.  KU also recorded a cumulative effect adjustment in the amount of$9.9 million to reflect the accumulated depreciation and accretion of AROassets at the transition date less amounts previously accrued under regulatorydepreciation.  KU recorded offsettingregulatory assets of $9.9 million, pursuant to regulatory treatment prescribedunder SFAS No. 71, *Accounting for the Effects of Certain Types ofRegulation*.  Also pursuant toSFAS No. 71, KU recorded regulatory liabilities in the amount of $0.9 millionoffsetting removal costs previously accrued under regulatory accounting inexcess of amounts allowed under SFAS No. 143.

 

Had SFAS No. 143 been in effectfor the 2002 reporting period, KU would have established asset retirementobligations as described in the following table:

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

 

As of December 31, 2003, KUrecorded ARO assets, net of accumulated depreciation, of $8.4 million andliabilities of $19.7 million.  KUrecorded offsetting regulatory assets of $11.3 million and regulatory liabilitiesof $1.2 million.

 

For the year endedDecember 31, 2003, KU recorded ARO accretion expense of $1.2 million, AROdepreciation

 

52

----

 

expense of $0.2 million and anoffsetting regulatory credit in the income statement of $1.4 million, pursuantto regulatory treatment prescribed under SFAS No. 71.  SFAS No. 143 has no impact on the results of the operation of KU.

 

KU AROs are primarily relatedto final retirement of assets associated 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 year endedDecember 31, 2003, KU recorded $0.3 million in depreciation expenserelated to the cost of removal of ARO related assets.  An offsetting regulatory liability was established pursuant toregulatory treatment prescribed under SFAS No. 71.

 

KU also continues to include acost of removal component in depreciation for assets that do not have a legalARO.  As of December 31, 2003 and 2002,KU has segregated this cost of removal, included in accumulated depreciation,of $266.8 million and $248.6 million, respectively, in accordance with FERCOrder No. 631*.*  For reporting purposes in its ConsolidatedBalance Sheets included in Item 8, KU has presented this cost of removal as aregulatory liability pursuant to SFAS No. 71.

 

KU transmission anddistribution lines largely operate under perpetual property easement agreementswhich do not generally require restoration upon removal of the property.  Therefore, under SFAS No. 143, no materialasset retirement obligations are recorded for transmission and distributionassets.

 

KU adopted EITF No. 98-10, *Accountingfor Energy Trading and Risk Management Activities,*effective January1, 1999.  This pronouncement requiredthat energy trading contracts be marked to market on the balance sheet, withthe gains and losses shown net in the income statement.  Effective January 1, 2003, KU adopted EITFNo. 02-03, *IssuesInvolved in Accounting for Derivative Contracts Held for Trading Purposes andContracts Involved in Energy Trading and Risk Management Activities*.  EITF No. 02-03 established the following:

 

•                  Rescinded EITFNo. 98-10,

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

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

 

With the rescission of EITF No.98-10, energy trading contracts that do not also meet the definition of aderivative under SFAS No. 133 must be accounted for as executorycontracts.  Contracts previously recordedat fair value under EITF No. 98-10 that are not also derivatives under SFAS No.133, *Accountingfor Derivative Instruments**and**Hedging Activities*, must be restated tohistorical cost through a cumulative effect adjustment.  The rescission of this standard had noimpact on financial position or results of operations of KU since all forwardand option contracts marked to market under EITF No. 98-10 were also within thescope of SFAS No. 133.

 

As a result of EITF No. 02-03,KU has netted the power purchased expense for trading activities againstelectric operating revenue to reflect this accounting change.  KU applied this guidance to all priorperiods, which had no impact on previously reported net income or commonequity.

 

53

----

 
| **(in thousands)**                            |   | **2002** |    | **2001** |   |
|-----------------------------------------------|--------|----------|---------|----------|--------|
|                                          |   |     |    |     |   |
| Gross electric operating revenues             |   | $        | 888,219 |     | $      | 859,472 |   |
| Less costs reclassified from power  purchased |   | 26,555   |    | 38,751   |   |
| Net electric operating revenues reported      |   | $        | 861,664 |     | $      | 820,721 |   |
|                                          |   |     |    |     |   |
| Gross power purchased                         |   | $        | 157,955 |     | $      | 157,161 |   |
| Less costs reclassified to revenues           |   | 26,555   |    | 38,751   |   |
| Net power purchased reported                  |   | $        | 131,400 |     | $      | 118,410 |   |

 

In May 2003, the Financial AccountingStandards Board issued SFAS No. 150, *Accounting for Certain Financial Instruments withCharacteristics of Both Liabilities and Equity*.  SFAS No. 150 was effective immediately forfinancial instruments entered into or modified after May 31, 2003, andotherwise was effective for interim reporting periods beginning after June 15,2003, except for certain instruments and certain entities which have beendeferred by the FASB.  Such deferrals donot affect KU.

 

KU has no financial instruments that fallwithin the scope of SFAS No. 150.

 

In January 2003, the FinancialAccounting Standards Board issued Financial Accounting Standards BoardInterpretation No. 46, *Consolidation of Variable Interest Entities*,an Interpretation of ARB No. 51 (FIN 46). FIN 46 requires certain variable interest entities to be consolidated bythe primary beneficiary of the entity if the equity investors in the entity donot have the characteristics of a controlling financial interest or do not havesufficient equity at risk for the entity to finance its activities withoutadditional subordinated financial support from other parties.  FIN 46 was effective immediately for all newvariable interest entities created or acquired after January 31, 2003.  For variable interest entities created oracquired prior to February 1, 2003, the provisions of FIN 46 must have beenapplied for the first interim or annual period beginning after June 15, 2003.

 

In December 2003, FIN 46 wasrevised, delaying the effective dates for certain entities created beforeFebruary 1, 2003, and making other amendments to clarify application of theguidance.  For potential variableinterest entities other than special purpose entities, the revised FIN 46 (FIN46R) is now required to be applied no later than the end of the first fiscalyear or interim reporting period ending after March 15, 2004.  The original guidance under FIN 46 wasapplicable, however, for all special purpose entities created prior to February1, 2003, at the end of the first interim or annual reporting period endingafter December 15, 2003.  FIN 46R may beapplied prospectively with a cumulative-effect adjustment as of the date it isfirst applied, or by restating previously issued financial statements with acumulative-effect adjustment as of the beginning of the first year restated.  FIN 46R also requires certain disclosures ofan entity’s relationship with variable interest entities.

 

KU has no special purposeentities that fall within the scope of FIN 46R.  KU continues to evaluate the impact that FIN 46R may have on itsfinancial position and results of operations.

 

LIQUIDITY AND CAPITAL RESOURCES

 

KU uses net cash generated fromits operations and external financing (including financing from affiliates) tofund construction of plant and equipment and the payment of dividends.  KU believes that such sources of funds willbe sufficient to meet the needs of its business in the foreseeable future.

 

Operating Activities

 

Cash provided by operations was$237.0 million, $175.8 million and $188.1 million in 2003, 2002, and 2001,respectively.  The 2003 increase comparedto 2002 of $59.6 million was primarily the result of an increase in accruedtaxes of $19.4 million, an increase in deferred income taxes of $17.3 million,a decrease in pension funding of $6.5 million and the change in accountsreceivable balances of $4.6 million, including the sale of

 

54

----

 

accounts receivable through theaccounts receivable securitization program. The 2002 decrease of $12.4 million resulted primarily from the change inaccounts receivable balances of $49.4 million, partially offset by the changein the materials and supplies balance of $28.3 million.  See Note 1 of KU’s Notes to FinancialStatements under Item 8 for a discussion of accounts receivable securitization.

 

Investing Activities

 

KU’s primary use of funds forinvesting activities continues to be for capital expenditures.  Capital expenditures were $341.9 million,$237.9 million and $142.4 million in 2003, 2002, and 2001, respectively.  KU expects its capital expenditures for 2004and 2005 to total approximately $312.0 million, which consists primarily ofconstruction estimates associated with installation of NOx equipment asdescribed in the section titled “Environmental Matters,” construction ofjointly owned CTs with LG&E and on-going construction for the distributionsystems.

 

Net cash used for investmentactivities increased $107.5 million in 2003 compared to 2002 primarily due tothe level of construction expenditures. NOx expenditures were approximately $110.0 million in 2003 and $56.0million in 2002, while CT expenditures were approximately $117.2 million in2003 and $85.3 million in 2002.  The$99.0 million increase in net cash used in 2002 as compared to 2001 was due toNOx expenditures and CT expenditures.

 

Financing Activities

 

Net cash inflows from financingactivities were $107.8 million and $64.2 million in 2003 and 2002,respectively, and outflows of $46.2 million in 2001.  In 2003, long-term borrowings from an affiliated company increased$283.0 million which were used in part for repayment of short-term borrowingsfrom LG&E Energy and retirement of $95.0 million in first mortgagebonds.  In 2002, short-term debtincreased $72.0 from 2001.

 

In May 2002, KU issued $37.93million variable-rate pollution control Series 12, 13, 14 and 15 due February1, 2032, and exercised its call option on $37.93 million, 6.25% pollutioncontrol Series 1B, 2B, 3B, and 4B due February 1, 2018.

 

In September 2002, KU issued$96 million variable-rate pollution control Series 16 due October 1, 2032, andexercised its call option on $96 million, 7.45% pollution control Series 8 dueSeptember 15, 2016.

 

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

 

In November 2003, KU called itsfirst mortgage bond, Series P 8.55% of $33 million, due in 2007, and replacedit with a loan from an affiliated company.

 

During 2003, KU entered intofour long-term loans from an affiliated company totaling $283 million.  $100 million of this total is unsecured andthe remaining $183 million is secured by a lien subordinated to the firstmortgage bond lien.  The second lienapplies to substantially all utility assets of KU.

 

Future Capital Requirements

 

Future capital requirements maybe affected in varying degrees by factors such as load growth, changes inconstruction expenditure levels, rate actions by regulatory agencies, newlegislation, market entry of competing electric power generators, changes inenvironmental regulations and other regulatory requirements.  KU

 

55

----

 

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

 

KU has a variety ofintercompany funding alternatives available to meet its capital requirements.  KU participates in an intercompany moneypool agreement wherein LG&E Energy and LG&E make funds available to KUat market-based rates up to $400 million. Likewise, LG&E Energy and KU make funds available to LG&E atmarket-based rates up to $400 million. Fidelia Corporation, an affiliated company, also provides long-termintercompany funding to KU.

 

Certain regulatory approvalsare required for the Company to incur additional debt.  FERC, the Virginia Commission, and the SECauthorize the issuance of short-term debt while the Kentucky Commission, theVirginia Commission, and the TRA authorize issuance of long-term debt.  As of December 31, 2003 the Company hasreceived approvals from FERC, the Virginia Commission and the SEC to borrow upto $400 million in short-term funds, and approvals from the KentuckyCommission, the Virginia Commission, and the TRA for $100 million in additionallong-term loans.  New long-term loanstotaling $50 million were completed in January 2004.

 

KU’s debt ratings as of December31, 2003, were:

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

 

These ratings reflect the viewsof 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.  Fitch withdrew its ratings on KU securitieseffective October 14, 2003.

 

Contractual Obligations

 

The following is provided tosummarize KU’s contractual cash obligations for periods after December 31,2003:

 
|                                                |   | **Payments  Due by Period** |       |
|-----------------------------------------------------|--------|-----------------------------|------------|
| **(in thousands)****Contractual  Cash Obligations** |   | **2004**                    | ** ** | **2005-  2006** | ** ** | **2007-  2008** | ** ** | **After  2008** | ** ** | **Total** | ** ** |
| Short-term debt (a)                                 |   | $                           | 43,231     |   | $ | — |   | $ | — |   | $ | — |   | $ | 43,231 |   |
| Long-term debt (b)                                  |   | 91,930                      |       | 111,000 |   | 53,000 |   | 431,646 |   | 687,576 |   |
| Unconditional purchase obligations (c)              |   | 37,433                      |       | 76,419 |   | 79,733 |   | 686,420 |   | 880,005 |   |
| Other long-term obligations (d)                     |   | 82,100                      |       | — |   | — |   | — |   | 82,100 |   |
| Total contractual cash obligations (e)              |   | $                           | 254,694    |   | $ | 187,419 |   | $ | 132,733 |   | $ | 1,118,066 |   | $ | 1,692,912 |   |

 

----

(a)          Represents borrowings from affiliated company due within one year.

 

(b)         Includes long-term debt of $91.9 million classified as a currentliability because the bonds are subject to tender for purchase at the option ofthe holder and to mandatory tender for purchase upon the occurrence of certainevents.  Maturity dates for the bondsrange from 2024 to 2032.

 

(c)          Represents future minimum payments under purchased power agreementsthrough 2023.

 

(d)         Represents construction commitments.

 

(e)          KU does not expect to pay the $91.9 million of long-term debt classifiedas a current liability in the Consolidated Balance Sheets

 

56

----

 

in 2004 as explained in (b)above.  KU anticipates cash fromoperations and external financing will be sufficient to fund futureobligations.  KU anticipates refinancinga portion of its short-term debt with long-term debt in 2004.

 

KU is a participant in a sale and leasebacktransaction involving its 62% interest in two jointly-owned CTs at KU’s E.W.Brown generating station (Units 6 and 7). Commencing in December 1999, LG&E and KU entered into atax-efficient, 18-year lease of the CTs. 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 transaction produced a pre-tax gain ofapproximately $1.9 million which was recorded in other income on the incomestatement in 2000, pursuant to a Kentucky Commission order.  The leasing transaction was entered intofollowing receipt of required state and federal regulatory approvals.

 

In case of default under the lease, KU isobligated to pay to the lessor its share of certain fees or amounts. Primaryevents of default include loss or destruction of the CTs, failure to insure ormaintain the CTs and unwinding of the transaction due to governmentalactions.  No events of default currentlyexist with respect to the lease.  Uponany termination of the lease, whether by default or expiration of its term,title to the CTs reverts jointly to KU and LG&E.

 

At December 31, 2003, the maximum aggregateamount of default fees or amounts, which decrease over the term of the lease,was $8.9 million, of which KU would be responsible for 62%.  KU has made arrangements with LG&EEnergy, via guarantee and regulatory commitment, for LG&E Energy to pay itsfull portion of any default fees or amounts. KU paid LG&E Energy a one-time fee of $186,000 to provide theguarantee.

 

MARKET RISKS

 

KU is exposed to market risksfrom changes in interest rates and commodity prices.  To mitigate changes in cash flows attributable to theseexposures, KU uses various financial instruments including derivatives.  Derivative positions are monitored usingtechniques that include market value and sensitivity analysis.  See Notes 1 and 4 of KU’s Notes to FinancialStatements under Item 8.

 

Interest Rate Sensitivity

 

KU has short-term and long-termvariable-rate debt obligations outstanding. At December 31, 2003, the potential change in interest expenseassociated with a 1% change in base interest rates of KU’s variable-rate debtis estimated at $4.5 million after the impact of interest rate swaps.

 

Interest rate swaps are used tohedge KU’s underlying debt obligations. These swaps hedge specific debt issuances and, consistent withmanagement’s designation, are accorded hedge accounting treatment.  See Note 4 of KU’s Notes to FinancialStatements under Item 8.

 

As of December 31, 2003, KU hasswaps with a combined notional value of $153 million.  The swaps exchange fixed-rate interest payments for floating rateinterest payments on KU’s Series P and R first mortgage bonds and Series 9pollution control bonds.  The potentialloss in fair value resulting from a hypothetical 1% adverse movement in baseinterest rates is estimated at $9.2 million as of December 31, 2003.  This estimate is derived from third-partyvaluations. Changes in the market value of these swaps, 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 February 2004, KU terminatedthe swaps it had in place at December 31, 2003 related to the Series 9pollution control bonds.  The notionalamount of the terminated swap was $50 million and KU received a

 

57

----

 

payment of $2.0 million as partof the termination.  The swap wasterminated because it was no longer an effective hedge of the underlying bond.

 

Commodity Price Sensitivity

 

KU has limited exposure tomarket price volatility in prices of fuel and electricity, since its retailtariffs include the FAC commodity price pass-through mechanism.  KU is exposed to market price volatility offuel and electricity in its wholesale activities.

 

# **Energy Trading & Risk Management Activities**

# ** **

KU conducts energy trading andrisk management activities to maximize the value of power sales from physicalassets it owns, in addition to the wholesale sale of excess assetcapacity.  Certain energy tradingactivities are accounted for on a mark-to-market basis in accordance with SFASNo. 133*,Accounting for Derivative Instruments and Hedging Activities,* andSFAS No. 138,*Accounting for Certain Derivative Instruments and Certain HedgingActivities*.  Wholesale salesof excess asset capacity and wholesale purchases are treated as normal salesand purchases under SFAS No. 133 and SFAS No. 138 and are not marked to market.

 

The rescission of EITF No.98-10 for fiscal periods ending after December 15, 2002, had no impact on KU’senergy trading and risk management reporting as all forward and option contractsmarked to market under EITF No. 98-10 are also within the scope of SFAS No.133.

 

The table below summarizes KU’senergy trading and risk management activities for 2003 and 2002.

 
| **(in thousands)**                                             |   | **2003** |   | **2002** |   |
|----------------------------------------------------------------|--------|----------|--------|----------|--------|
| Fair value of contracts at beginning of period,  net liability |   | $        | (156   | )        | $      | (186 | ) |
| Fair value of contracts when entered into  during the period   |   | 2,654    |   | (65      | )      |
| Contracts realized or otherwise settled  during the period     |   | (569     | )      | 448      |   |
| Changes in fair values due to changes in  assumptions          |   | (1,357   | )      | (353     | )      |
| Fair value of contracts at end of period,  net liability       |   | $        | 572    |     | $      | (156 | ) |

 

No changes to valuationtechniques for energy trading and risk management activities occurred during2003.  Changes in market pricing,interest rate and volatility assumptions were made during both years. Allcontracts outstanding at December 31, 2003 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 intendedto minimize credit risk and revalues credit exposures daily to monitorcompliance with those policies.  AtDecember 31, 2003, 100% of the trading and risk management commitments werewith counterparties rated BBB-/Baa3 equivalent or better.

 

Accounts ReceivableSecuritization

 

On February 6, 2001, KUimplemented an accounts receivable securitization program.  The purpose of this program was to enable KUto accelerate the receipt of cash from the collection of retail accountsreceivable, thereby reducing dependence upon more costly sources of workingcapital. The securitization program allowed for a percentage of eligiblereceivables to be sold.  Eligiblereceivables were generally all receivables associated with retail sales thathave standard terms and are not past due. KU was able to terminate this program at any time without penalty.

 

58

----

 

KU terminated the accountsreceivable securitization program in January 2004 and replaced it withlong-term loans from an E.ON affiliate. The accounts receivable program required KU R to maintain minimum levelsof net worth.  The program alsocontained a cross-default provision if KU defaulted on debt obligations inexcess of $25 million.  If there was asignificant deterioration in the payment record of the receivables by theretail customers or if KU failed to meet certain covenants regarding theprogram, the program could terminate at the election of the financial institutions.  In this case, payments from retail customerswould first be used to repay the financial institutions participating in theprogram, and would then be available for use by KU.  KU did not violate any covenants with regard to the accountsreceivable securitization program.

 

As part of the program, KU soldretail accounts receivables to a wholly owned subsidiary KU R.  Simultaneously, KU R entered into twoseparate three-year accounts receivable securitization facilities with twofinancial institutions and their affiliates whereby KU R could sell, on a revolvingbasis, an undivided interest in certain of its receivables and receive up to$50 million from an unrelated third-party purchaser.  The effective cost of the receivable program was comparable toKU’s lowest cost source of capital, and is based on prime rated commercialpaper.  KU retained servicing rights ofthe sold receivables through two separate servicing agreements with thethird-party purchaser.  KU obtained anopinion from independent legal counsel indicating these transactions qualifiedas a true sale of receivables.  As ofDecember 31, 2003, the outstanding program balance was $50.0 million.

 

To determine KU’s retainedinterest, the proceeds on the sale of receivables to the financial institutionswas netted against the amount of eligible receivables sold by KU to KU R.  Interest expense, program fees, and facilityfees paid to the financial institutions and an allowance for doubtful accountswere deducted to arrive at the future value of retained interest.  The future value was discounted using theprime rate plus 25 basis points, assuming a 45-day receivable life.  Pre-tax gains and losses from the sale ofthe receivables in 2003, 2002 and 2001 were a gain of $41,057 and losses of$317 and $155,734, respectively.  KU’snet cash flows from KU R were $(0.1) million, $3.3 million and $43.5 millionfor 2003, 2002 and 2001, respectively.

 

The allowance for doubtfulaccounts associated with the eligible securitized receivables at December 31was $0.5 million in 2003, 2002 and 2001. This allowance was based on historical experience of KU. Each securitizationfacility contained a fully funded reserve for uncollectible receivables.

 

RATES AND REGULATION

 

KU is subject to thejurisdiction of the Kentucky Commission, the Virginia Commission and FERC invirtually all matters related to electric utility regulation, and as such, itsaccounting is subject to SFAS No. 71, *Accounting for the Effects of Certain Types ofRegulation*.  Given KU’scompetitive position in the market and the status of regulation in the statesof Kentucky and Virginia, KU has no plans or intentions to discontinue itsapplication of SFAS No. 71.  See Note 3of KU’s Notes to Financial Statements under Item 8.

 

**Kentucky Commission Settlement Order - VDTCosts, ESM and Depreciation. **Duringthe first quarter 2001, KU recorded a $64 million charge for a workforcereduction program.  Primary componentsof the charge were separation benefits, enhanced early retirement benefits, andhealthcare benefits. The result of this workforce reduction was the eliminationof approximately 300 positions, accomplished primarily through a voluntaryenhanced severance program.

 

In June 2001, KU filed anapplication (VDT case) with the Kentucky Commission to create a regulatoryasset

 

59

----

 

relating to these first quarter2001 charges.  The application requestedpermission to amortize these costs over a four-year period.  The Kentucky Commission also opened a caseto review a new depreciation study and resulting depreciation rates implementedin 2001.

 

KU reached a settlement in theVDT case as well as other cases involving the depreciation rates and ESM withall intervening parties.  The settlementagreement was approved by the Kentucky Commission in December 2001.  The order allowed KU to set up a regulatoryasset of $54 million for the workforce reduction costs and begin amortizingthese costs over a five-year period starting in April 2001. The first quarter2001 charge of $64 million represented all employees who had accepted avoluntary enhanced severance program. Some employees rescinded their participation in the voluntary enhancedseverance program which, along with the non-recurring charge of $6.9 millionfor FERC and Virginia jurisdictions, decreased the original charge to theregulatory asset from $64 million to $54 million. The settlement reducesrevenues approximately $11 million through a surcredit on bills to ratepayersover the same five-year period.  Thesurcredit represents stipulated net savings KU is expected to realize fromimplementation of best practices through the VDT. The agreement alsoestablished KU’s new depreciation rates in effect December 2001, retroactive toJanuary 2001.  The new depreciationrates decreased depreciation expense by $6.0 million in 2001.

 

**ECR**.  In August 2002, KU filed an application withthe Kentucky Commission to amend its compliance plan to allow recovery of thecost of a new and additional environmental compliance facility.  The estimated capital cost of the additionalfacilities is $17.3 million.  A finalorder was issued in February 2003. The final order approved recovery of the newenvironmental compliance facility totaling $17.3 million.  Cost recovery through the environmentalsurcharge of the approved project commenced with bills rendered in April 2003.

 

In March2003, the Kentucky Commission initiated a series of six-month and two-yearreviews of the operation of KU’s Environmental Surcharge.  A final order was issued in October 2003,resolving all outstanding issues related to over-recovery from customers andunder-recovery of allowed O&M expense. The Commission found that KU had over-collected a net $6.0 million fromcustomers and ordered the refund to occur through adjustments to thecalculation of the monthly surcharge billing factor over the subsequent 12month period.  The Kentucky Commissionfurther ordered KU to roll $17.9 million of environmental assets into baserates and make corresponding adjustments to the monthly environmental surchargefilings to reflect that portion of environmental rate base now included in baserates going forward.  The rates ofreturn for KU’s 1994 and post-1994 plans were reset to 1.24% and 12.60%,respectively.

 

**ESM**.  KU’s electric rates are subject to anESM.  The ESM, initially in place forthree years beginning in 2000, sets an upper and lower point for rate of returnon equity, whereby if KU’s rate of return for the calendar year falls withinthe range of 10.5% to 12.5%, no action is necessary.  If earnings are above the upper limit, the excess earnings areshared 40% with ratepayers and 60% with shareholders; if earnings are below thelower limit, the earnings deficiency is recovered 40% from ratepayers and 60%from shareholders.  By order of theKentucky Commission, rate changes prompted by the ESM filing go into effect inApril of each year subject to a balancing adjustment in successive periods.

 

In November 2002, KU filed arevised ESM tariff which proposed continuance of the existing ESM throughDecember 2005.  In addition, theKentucky Commission initiated a focused management audit to review the ESM planand reassess its reasonableness, and recently concluded discovery in thecase.  KU and interested parties had theopportunity to provide recommendations for modification and continuance of theESM or other forms of alternative or incentive regulation.  Continuance of the ESM is still beingdeliberated by the Kentucky Commission and a final order is not expected untilthe second quarter of 2004.  The ESMtariff remains in effect pending the resolution of the case.

 

60

----

 

KU made its third ESM filing inFebruary 2003 for the calendar year 2002 reporting period.  KU is in the process of recovering $11.6million from ratepayers for the 2002 reporting period.  KU estimated that the rate of return willfall below the lower limit, subject to Kentucky Commission approval, for theyear ended December 31, 2003. The 2003 financial statements include an accrualto reflect the earnings deficiency of $9.3 million to be recovered fromcustomers commencing in April 2004.

 

**DSM.**  In May 2001, the Kentucky Commissionapproved a plan that would expand LG&E’s current DSM programs into theservice territory served by KU.  Theplan included a rate mechanism that provided for concurrent recovery of DSMcosts, provided an incentive for implementing DSM programs, and recoveredrevenues from lost sales associated with the DSM programs based on program planengineering estimates and post-implementation evaluations.

 

**FAC. **KU employs an FACmechanism, which under Kentucky law allows KU to recover from customers theactual fuel costs associated with retail electric sales.  In July 1999, the Kentucky Commission issueda series of orders requiring KU to refund approximately $10.1 million resultingfrom reviews of the FAC from November 1994 to October 1998.  In August 1999, after a rehearing request byKU, the Kentucky Commission issued a final order that reduced the refund obligationto $6.7 million ($5.8 million on Kentucky jurisdictional basis) from theoriginal order amount of $10.1 million. KU implemented the refund from October 1999 through September 2000.  Both KU and the KIUC appealed theorder.  Pending a decision on this appeal, a comprehensive settlement was reachedby all parties and approved by the Kentucky Commission in May 2002.  Thereunder, KU agreed to credit its fuelclause in the amount of $1.0 million (refund made in June and July 2002), andthe parties agreed on a prospective interpretation of the state’s fueladjustment clause regulation to ensure consistent and mutually acceptableapplication going forward.

 

In January 2003, the KentuckyCommission reviewed KU’s FAC for the six month period ended October 31, 2002.The Kentucky Commission ordered KU to reduce its fuel costs for purposes ofcalculating its FAC by $0.7 million. At issue was the purchase of approximately102,000 tons of coal from Western Kentucky Energy Corporation, a non-regulatedaffiliate, for use at KU’s Ghent facility. The Kentucky Commission furtherordered that an independent audit be conducted to examine operational andmanagement aspects of both KU’s and LG&E’s fuel procurement functions. Thefinal report was issued in February 2004. The report’s recommendations related to documentation and processimprovements will be addressed with the Kentucky Commission staff as ManagementAudit Plans are developed in the second quarter of 2004.

 

The Kentucky Commissionrequires public hearings at six-month intervals to examine past fuel adjustments,and at two-year intervals to review past operations of the fuel clause andtransfer of the then current fuel adjustment charge or credit to the basecharges.  KU also employs a FACmechanism for Virginia customers that uses an average fuel cost factor basedprimarily on projected fuel costs.  Thefuel cost factor may be adjusted annually for over or under collections of fuelcosts from the previous year.  No othersignificant issues have been identified as a result of these reviews.

 

**Electric Rate Case.**  InDecember 2003, KU filed an application with the Kentucky Commission requestingan adjustment in KU’s electric rates. KU asked for a general adjustment in electric rates based on the twelvemonth test year ended September 30, 2003. The revenue increase requested was $58.3 million.  The Kentucky Commission has suspended theeffective date of the proposed new tariffs for five months, so that the ratesmay go into effect subject to refund by July 1, 2004.  The Kentucky Commission established a procedural schedule for thecase pertaining to discovery and a hearing. The hearing will be held in May 2004. KU expects the Kentucky Commission to issue an order in the case beforenew rates go into effect July 1, 2004.

 

61

----

 

**Kentucky CommissionAdministrative Case for Affiliate Transactions. **In December 1997, the KentuckyCommission opened Administrative Case No. 369 to consider Kentucky Commissionpolicy regarding cost allocations, affiliate transactions and codes of conductgoverning the relationship between utilities and their non-utility operationsand affiliates.  The Kentucky Commissionintended to address two major areas in the proceedings: the tools and conditionsneeded to prevent cost shifting and cross-subsidization between regulated andnon-utility operations; and whether a code of conduct should be established toassure that non-utility segments of the holding company are not engaged inpractices that could result in unfair competition caused by cost shifting fromthe non-utility affiliate to the utility. In early 2000, the Kentucky General Assembly enacted legislation, HouseBill 897, which authorized the Kentucky Commission to require utilities thatprovide nonregulated activities to keep separate accounts and allocate costs inaccordance with procedures established by the Kentucky Commission. In the samebill, the General Assembly set forth provisions to govern a utility’sactivities related to the sharing of information, databases, and resourcesbetween its employees or an affiliate involved in the marketing or theprovision of nonregulated activities and its employees or an affiliate involvedin the provision of regulated services. The legislation became law in July 2000and KU has been operating pursuant thereto since that time.  In February 2001, the Kentucky Commissionpublished notice of their intent to promulgate new administrative regulationunder the auspices of the new law.  Thiseffort is still on-going.

 

**Kentucky CommissionAdministrative Case for System Adequacy.**  In June 2001, Kentucky’s Governor issuedExecutive Order 2001-771, which directed the Kentucky Commission to review andstudy issues relating to the need for and development of new electricgenerating capacity in Kentucky.  Inresponse to that Executive Order, the Kentucky Commission opened AdministrativeCase No. 387 to review the adequacy of Kentucky’s generation capacity andtransmission system.  Specifically, theitems reviewed were the appropriate level of reliance on purchased power, theappropriate reserve margins to meet existing and future electric demand, theimpact of spikes in natural gas prices on electric utility planning strategies,and the adequacy of Kentucky’s electric transmission facilities.  In December 2001, the Kentucky Commissionissued an order in which it noted that KU is responsibly addressing thelong-term supply needs of native load customers and that current reservemargins are appropriate.  However, dueto the rapid pace of change in the industry, the order also requires KU toprovide an annual assessment of supply resources, future demand, reservemargin, and the need for new resources.

 

Regarding the transmissionsystem, the Kentucky Commission concluded that the transmission system withinKentucky can reliably serve native load and a significant portion of theproposed new unregulated power plants. However, it will not be able to handlethe volume of transactions envisioned by FERC without future upgrades, thecosts of which should be borne by those for whom the upgrades are required.

 

The Kentucky Commission pledgedto continue to monitor all relevant issues and advocate Kentucky’s interests atall opportunities.

 

**FERC SMD NOPR. **On July 31, 2002, the FERC issued a NOPRin Docket No. RM01-12-000 which would substantially alter the regulationsgoverning the nation’s wholesale electricity markets by establishing a commonset of rules, defined as SMD. The SMD NOPR would require each public utilitythat owns, operates, or controls interstate transmission facilities to becomean Independent Transmission Provider (ITP), belong to an RTO that is an ITP, orcontract with an ITP for operation of its transmission assets. It would alsoestablish a standardized congestion management system, real-time and day-aheadenergy markets, and a single transmission service for network andpoint-to-point transmission customers. Review of the proposed rulemaking isunderway and no time frame has been established by the FERC for adoption of afinal rule.  While it is expected thatthe SMD final rule will affect KU revenues and expenses, the specific impact ofthe rulemaking is not

 

62

----

 

known at this time.

 

**MISO. **KU and LG&E are founding members of theMISO.  Membership was obtained in 1998in response to and consistent with federal policy initiatives.  In February 2002, KU and LG&E turnedover operational control of their high voltage transmission facilities (100kVand above) to the MISO.  The****MISOcurrently controls****over 100,000 miles of transmission over1.1 million square miles located in the northern Midwest between Manitoba,Canada and Kentucky.  In September 2002,FERC granted a 12.88% ROE on transmission facilities for KU, LG&E and therest of the MISO owners.

 

In October 2001, the FERCissued an order requiring that the bundled retail load and grandfatheredwholesale load of each member transmission owner be included in the currentcalculation of the MISO’s “cost-adder,” the Schedule 10 charges designed torecover the MISO’s costs of operation, including start-up capital (debt)costs.  KU and LG&E, along withseveral other transmission owners, opposed the FERC’s ruling on this matter.The opposition was rejected by the FERC in 2002.  Later that year, the MISO’s transmission owners appealed theFERC’s decision to the United States Court of Appeals for the District ofColumbia Circuit.  In response, inNovember 2002, the FERC requested that the Court issue a partial remand of itschallenged orders to allow the FERC to revisit certain issues, and furtherrequested that the case be held in abeyance pending the agency’s resolution ofsuch issues.  The Court granted theFERC’s petition in December 2002.  InFebruary 2003, FERC issued an order reaffirming its position concerning thecalculation of the Schedule 10 charges and in July 2003 denied arehearing.  KU and LG&E, along withseveral other transmission owners, have again petitioned the District Court ofColumbia Circuit for review.  This caseis currently pending.

 

As a separate matter, MISO, itstransmission owners and other interested industry segments reached a settlementin mid-2002 regarding the level**of cost responsibility properly borne bybundled and grandfathered load under these FERC rulings (such settlementexpressly not prejudicing the transmission owners’ and KU’s right to challengethe FERC’s ruling imposing cost responsibility on bundled loads in the firstinstance).  In February 2003, FERCaccepted a partial settlement between MISO and the transmission owners.  FERC did not accept the only contestedsection of the settlement, which would have allowed the transmission owners toimmediately treat unrecoverable Schedule 10 charges as regulatory assets.  FERC will consider allowing regulatory assettreatment of unrecoverable Schedule 10 charges on a case-by-case basis.

 

The MISO plans to implement acongestion management system in December 2004, in compliance with FERC Order2000.  This system will be similar tothe Locational Marginal Pricing (LMP) system currently used by the PJM RTO andcontemplated in FERC’s SMD NOPR, currently being discussed.  The MISO filed with FERC a mechanism forrecovery of costs for the congestion management system.  They proposed the addition of two newSchedules, 16 and 17.  Schedule 16 isthe MISO’s cost recovery mechanism for the Financial Transmission RightsAdministrative Service it will provide. Schedule 17 is the MISO’s mechanism for recovering costs it will incurfor providing Energy Marketing Support Administrative Service.  The MISO transmission owners, including KUand LG&E, have objected to the allocation of costs among marketparticipants and retail native load.  Ahearing at FERC has been completed, but a ruling has not been issued.

 

The Kentucky Commission openedan investigation into KU’s and LG&E’s membership in MISO in July 2003. TheKentucky Commission directed KU and LG&E to file testimony addressing thecosts and benefits of MISO membership both currently and over the next fiveyears and other legal issues surrounding continued membership.  KU and LG&E engaged an independent thirdparty to conduct a cost benefit analysis on this issue.  The information was filed with the KentuckyCommission in September 2003.  Theanalysis and testimony supported the exit from MISO, under certainconditions.  The MISO filed its owntestimony and cost benefit analysis in December 2003.  A final Kentucky Commission order is expected in the secondquarter of

 

63

----

 

2004.

 

**Merger Surcredit. **As part of the LG&E Energy mergerwith KU Energy in 1998, LG&E Energy estimated non-fuel savings over aten-year period following the merger. Costs to achieve these savings for KU of $42.3 million were recorded inthe second quarter of 1998, $20.5 million of which was deferred and amortizedover a five-year period pursuant to regulatory orders.  Primary components of the merger costs wereseparation benefits, relocation costs, and transaction fees, the majority ofwhich were paid by December 31, 1998. KU expensed the remaining costs associated with the merger ($21.8million) in the second quarter of 1998.

 

In approving the merger, theKentucky Commission adopted KU’s proposal to reduce its retail customers’ billsbased on one-half of the estimated merger-related savings, net of deferred andamortized amounts, over a five-year period. 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 LG&E and KU over afive-year period.  The surcredit wasallocated 53% to KU and 47% to LG&E. In that same order, the Kentucky Commission required LG&E and KU,after the end of the five-year period, to present a plan for sharing with customersthe then-projected non-fuel savings associated with the merger.  The Companies submitted this filing inJanuary 2003, proposing to continue to share with ratepayers, on a 50%/50%basis, the estimated fifth-year gross level of non-fuel savings associated withthe merger.  In October 2003, theKentucky Commission issued an order approving a settlement agreement reachedwith the parties in the case. KU’s merger surcredit will remain in place foranother five-year term beginning July 1, 2003 and the merger savings willcontinue to be shared 50% with ratepayers and 50% with shareholders.

 

Any fuel cost savings arepassed to Kentucky customers through the fuel adjustment clause.  See FAC above.

 

**Environmental Matters. **KU is subject to SO2and NOx emission limits on its electric generating units pursuant to the CleanAir Act.  KU met its Phase I SO2requirements primarily through installation of FGD equipment on Ghent Unit1.  KU’s strategy for Phase II SO2 reductions,which commenced January 1, 2000, was to use accumulated emissions allowances todelay additional capital expenditures and will include fuel switching or theinstallation of additional FGDs as necessary. KU met the NOx emission requirements of the Act through installation oflow-NOx burner systems. KU’s compliance plans are subject to many factorsincluding developments in the emission allowance and fuel markets, futureregulatory and legislative initiatives, and advances in clean air controltechnology.  KU will continue to monitorthese developments to ensure that its environmental obligations are met in themost efficient and cost-effective manner.

 

In September 1998, the EPAannounced its final “NOx SIP Call” rule requiring states to impose significantadditional reductions in NOx emissions by May 2003, in order to mitigatealleged ozone transport impacts on the Northeast region.  The Commonwealth of Kentucky SIP, which wasapproved by EPA June 24, 2003, requires reductions in NOx emissions fromcoal-fired generating units to the 0.15 lb./Mmbtu level on a system-widebasis.  In related proceedings inresponse to petitions filed by various Northeast states, in December 1999, EPAissued a final rule pursuant to Section 126 of the Clean Air Act directing similarNOx reductions from a number of specifically targeted generating unitsincluding all KU units in the eastern half of Kentucky.  Additional petitions currently pendingbefore EPA may potentially result in rules encompassing KU’s remaininggenerating units.  As a result ofappeals to both rules, the compliance date was extended to May 2004.  All KU generating units are subject to theMay 2004 compliance date under these NOx emissions reduction rules.

 

KU is currently implementing aplan for adding significant additional NOx controls to its generatingunits.  Installation of additional NOxcontrols will proceed on a phased basis, with installation of controlscommencing

 

64

----

 

in late 2000 and continuingthrough the final compliance date.  KUestimates that it will incur total capital costs of approximately $230 millionto reduce its NOx emissions to the 0.15 lb./Mmbtu level on a company-widebasis.  As of December 31, 2003, KU hasincurred $172 million of these capital costs related to the reduction of itsNOx emissions.  In addition, KU willincur additional operating and maintenance costs in operating new NOxcontrols.  KU believes its costs in thisregard to be comparable to those of similarly situated utilities with likegeneration assets.  KU had anticipatedthat such capital and operating costs are the type of costs that are eligiblefor recovery from customers under its environmental surcharge mechanism andbelieved that a significant portion of such costs could be recovered.  In April 2001, the Kentucky Commissiongranted recovery of these costs for KU.

 

KU is also monitoring severalother air quality issues which may potentially impact coal-fired power plants,including EPA’s revised air quality standards for ozone and particulate matter,measures to implement EPA’s regional haze rule, and EPA’s December 2003proposals to regulate mercury emissions from steam electric generating unitsand to further reduce emission of sulfur dioxide and nitrogen oxides under theInterstate Air Quality Rule.

 

KU owns or formerly ownedseveral properties that were used for company or company-predecessoroperations, including MGP’s, power production facilities and substations.  While KU has completed a cleanup of one suchsite in 1995, evaluations of these types of properties generally have notidentified issues of significance.  Withregard to these properties, KU is unaware of any imminent exposure orliability.

 

In October 1999, approximately38,000 gallons of diesel fuel leaked from a cracked valve in an undergroundpipeline at KU’s E.W. Brown Station.  KUcommenced immediate spill containment and recovery measures which continuedunder the oversight of EPA and state officials and prevented the spill fromreaching the Kentucky River.  KUultimately recovered approximately 34,000 gallons of diesel fuel.  In November 1999, the Kentucky Division ofWater issued a notice of violation for the incident.  KU has settled all outstanding issues for this incident with theCommonwealth of Kentucky.  KU incurredcosts of approximately $1.8 million and received insurance reimbursement of$1.2 million.  In December 2002, theDepartment of Justice (DOJ) sent correspondence to KU regarding a potentialper-day fine for failure to timely submit a facility response plan and aper-gallon fine for the amount of oil discharged.  KU and the DOJ have commenced settlement discussions usingexisting DOJ settlement guidelines on this matter.

 

In April 2002, the EPA sentcorrespondence to KU regarding potential exposure in connection with $1.5 millionin completed remediation costs associated with a transformer scrap-yard.  KU believes it is one of the more remoteamong a number of potentially responsible parties and has entered intosettlement discussions with the EPA on this matter.

 

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

 

**Deferred Income Taxes. **KU expects to haveadequate levels of taxable income to realize its recorded deferred taxassets.  At December 31, 2003, deferredtax assets totaled $48.6 million and were principally related to expensesattributable to KU’s post retirement benefits and asset retirement obligations.

 

65

----

 

FUTURE OUTLOOK

 

Competition and Customer Choice

 

In the last several years, KUhas taken many steps to keep its rates low while maintaining high levels ofcustomer satisfaction, including a reduction in the number of employees;aggressive cost cutting; an increase in focus on commercial, industrial andresidential customers; an increase in employee involvement and training; andcontinuous modifications of its organizational structure.

 

At this time, neither theKentucky General Assembly nor the Kentucky Commission has adopted or approved aplan or timetable for retail electric industry 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.

 

Virginia has enacted a phase-inof customer choice through the Virginia Electric Restructuring Act.  On March19, 2003, the General Assembly of Virginia amended and reenacted Section 56-580of the Code of Virginia with language that effectively exempts all KU Virginiaservice territory from retail choice until such time as retail choice isoffered to other customers in KU’s other service territories.

 

# **ITEM 7A**.  Quantitative and Qualitative DisclosureAbout Market Risk.

# ** **

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

 

# **ITEM 8**. Financial Statementsand Supplementary Data.

 

66

----

 

INDEX OF ABBREVIATIONS

 
| AFUDC               |   | Allowance for Funds Used During Construction                |
|---------------------|--------|-------------------------------------------------------------|
| ARO                 |   | Asset Retirement Obligation                                 |
| Capital Corp.       |   | LG&E Capital Corp.                                      |
| Clean Air Act       |   | The Clean Air Act, as amended in 1990                       |
| CCN                 |   | Certificate of Public Convenience and Necessity             |
| CT                  |   | Combustion Turbines                                         |
| CWIP                |   | Construction Work in Progress                               |
| DSM                 |   | Demand Side Management                                      |
| ECR                 |   | Environmental Cost Recovery                                 |
| EEI                 |   | Electric Energy, Inc.                                       |
| EITF                |   | Emerging Issues Task Force Issue                            |
| E.ON                |   | E.ON AG                                                     |
| EPA                 |   | U.S. Environmental Protection Agency                        |
| ESM                 |   | Earnings Sharing Mechanism                                  |
| F                   |   | Fahrenheit                                                  |
| FAC                 |   | Fuel Adjustment Clause                                      |
| FERC                |   | Federal Energy Regulatory Commission                        |
| FGD                 |   | Flue Gas Desulfurization                                    |
| FPA                 |   | Federal Power Act                                           |
| FT and FT-A         |   | Firm Transportation                                         |
| GSC                 |   | Gas Supply Clause                                           |
| IBEW                |   | International Brotherhood of Electrical Workers             |
| IMEA                |   | Illinois Municipal Electric Agency                          |
| IMPA                |   | Indiana Municipal Power Agency                              |
| Kentucky Commission |   | Kentucky Public Service Commission                          |
| KIUC                |   | Kentucky Industrial Utility Consumers, Inc.                 |
| KU                  |   | Kentucky Utilities Company                                  |
| KU Energy           |   | KU Energy Corporation                                       |
| KU R                |   | KU Receivables LLC                                          |
| kV                  |   | Kilovolts                                                   |
| Kva                 |   | Kilovolt-ampere                                             |
| KW                  |   | Kilowatts                                                   |
| Kwh                 |   | Kilowatt hours                                              |
| LEM                 |   | LG&E Energy Marketing Inc.                              |
| LG&E            |   | Louisville Gas and Electric Company                         |
| LG&E Energy     |   | LG&E Energy LLC (as successor to LG&E Energy Corp.) |
| LG&E R          |   | LG&E Receivables LLC                                    |
| LG&E Services   |   | LG&E Energy Services Inc.                               |
| Mcf                 |   | Thousand Cubic Feet                                         |
| MGP                 |   | Manufactured Gas Plant                                      |
| MISO                |   | Midwest Independent Transmission System Operator            |
| Mmbtu               |   | Million British thermal units                               |
| Moody’s        |   | Moody’s Investor Services, Inc.                        |
| Mw                  |   | Megawatts                                                   |
| Mwh                 |   | Megawatt hours                                              |
| NNS                 |   | No-Notice Service                                           |
| NOPR                |   | Notice of Proposed Rulemaking                               |
| NOx                 |   | Nitrogen Oxide                                              |
| OATT                |   | Open Access Transmission Tariff                             |
| OMU                 |   | Owensboro Municipal Utilities                               |
| OVEC                |   | Ohio Valley Electric Corporation                            |
| PBR                 |   | Performance-Based Ratemaking                                |
| PJM                 |   | Pennsylvania,  New Jersey, Maryland Interconnection         |
| Powergen            |   | Powergen Limited (formerly Powergen plc)                    |
| PUHCA               |   | Public  Utility Holding Company Act of 1935                 |
| ROE                 |   | Return on Equity                                            |
| RTO                 |   | Regional Transmission Organization                          |
| S&P             |   | Standard & Poor’s Rating Services                  |

 

67

----

 
| SCR                 |   | Selective Catalytic Reduction               |
|---------------------|--------|---------------------------------------------|
| SEC                 |   | Securities  and Exchange Commission         |
| SERP                |   | Supplemental Employee Retirement Plan       |
| SFAS                |   | Statement of Financial Accounting Standards |
| SIP                 |   | State Implementation Plan                   |
| SMD                 |   | Standard Market Design                      |
| SO2                 |   | Sulfur Dioxide                              |
| Tennessee Gas       |   | Tennessee Gas Pipeline Company              |
| Texas Gas           |   | Texas Gas Transmission LLC                  |
| TRA                 |   | Tennessee Regulatory Authority              |
| Trimble County      |   | LG&E’s Trimble County Unit 1       |
| USWA                |   | United Steelworkers of America              |
| Utility Operations  |   | Operations of LG&E and KU               |
| VDT                 |   | Value Delivery Team Process                 |
| Virginia Commission |   | Virginia State Corporation Commission       |
| Virginia Staff      |   | Virginia State Corporation Commission Staff |
| WNA                 |   | Weather Normalization Adjustment            |

 

68

----

 

Louisville Gasand Electric Company and Subsidiary

ConsolidatedStatements of Income

(Thousands of $)

 
|                                                |   | **Years  Ended December 31** |    |
|-----------------------------------------------------|--------|------------------------------|---------|
|                                                |   | **2003**                     |    | **2002** | ** ** | **2001** | ** ** |
|                                                |   |                         |    |   |   |   |   |
| OPERATING REVENUES:                                 |   |                         |    |   |   |   |   |
| Electric (Note 14)                                  |   | $                            | 768,600 |   | $ | 724,386 |   | $ | 672,184 |   |
| Gas                                                 |   | 325,333                      |    | 267,693 |   | 290,775 |   |
| Provision for rate collections (refunds)  (Note 3)  |   | (412                         | )       | 11,656 |   | 1,588 |   |
| Total operating revenues (Note 1)                   |   | 1,093,521                    |    | 1,003,735 |   | 964,547 |   |
|                                                |   |                         |    |   |   |   |   |
| OPERATING EXPENSES:                                 |   |                         |    |   |   |   |   |
| Fuel for electric generation                        |   | 196,965                      |    | 194,900 |   | 159,231 |   |
| Power purchased (Note 14)                           |   | 79,621                       |    | 61,881 |   | 49,322 |   |
| Gas supply expenses                                 |   | 233,601                      |    | 182,108 |   | 206,165 |   |
| Other operation expenses                            |   | 217,060                      |    | 208,322 |   | 167,818 |   |
| Maintenance                                         |   | 57,170                       |    | 60,210 |   | 58,687 |   |
| Depreciation and amortization (Note 1)              |   | 113,288                      |    | 105,906 |   | 100,356 |   |
| Federal and state income taxes (Note 7)             |   | 56,066                       |    | 55,035 |   | 63,452 |   |
| Property and other taxes                            |   | 17,065                       |    | 17,459 |   | 17,743 |   |
| Total operating expenses                            |   | 970,836                      |    | 885,821 |   | 822,774 |   |
|                                                |   |                         |    |   |   |   |   |
| Net operating income                                |   | 122,685                      |    | 117,914 |   | 141,773 |   |
|                                                |   |                         |    |   |   |   |   |
| Other income (expense) - net (Note 8)               |   | (1,205                       | )       | 815 |   | 2,930 |   |
| Other income from affiliated company (Note  14)     |   | 6                            |    | 5 |   | — |   |
| Interest expense                                    |   | 23,863                       |    | 27,630 |   | 34,907 |   |
| Interest expense to affiliated companies  (Note 14) |   | 6,784                        |    | 2,175 |   | 3,015 |   |
|                                                |   |                         |    |   |   |   |   |
| Net income                                          |   | $                            | 90,839  |   | $ | 88,929 |   | $ | 106,781 |   |

 

ConsolidatedStatements of Retained Earnings

(Thousands of $)

 
|                                             |   | **Years  Ended December 31** | ** ** |
|--------------------------------------------------|--------|------------------------------|------------|
|                                             |   | **2003**                     |       | **2002** | ** ** | **2001** | ** ** |
|                                             |   |                         |       |   |   |   |   |
| Balance January 1                                |   | $                            | 409,319    |   | $ | 393,636 |   | $ | 314,594 |   |
| Add net income                                   |   | 90,839                       |       | 88,929 |   | 106,781 |   |
|                                             |   | 500,158                      |       | 482,565 |   | 421,375 |   |
|                                             |   |                         |       |   |   |   |   |
| Deduct:  Cash  dividends declared on stock: |   |                         |       |   |   |   |   |
| 5% cumulative preferred                          |   | 1,075                        |       | 1,075 |   | 1,075 |   |
| Auction rate cumulative preferred                |   | 908                          |       | 1,702 |   | 2,195 |   |
| $5.875 cumulative preferred (Note 1)             |   | 734                          |       | 1,469 |   | 1,469 |   |
| Common                                           |   | —                       |       | 69,000 |   | 23,000 |   |
|                                             |   | 2,717                        |       | 73,246 |   | 27,739 |   |
|                                             |   |                         |       |   |   |   |   |
| Balance December 31                              |   | $                            | 497,441    |   | $ | 409,319 |   | $ | 393,636 |   |

 

The accompanying notes are anintegral part of these consolidated financial statements.

 

69

----

 

Louisville Gas and Electric Company and Subsidiary

ConsolidatedStatements of Comprehensive Income

(Thousands of $)

 
|                                                                                                                                                                       |   | **Years  Ended December 31** | ** ** |
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|------------------------------|------------|
|                                                                                                                                                                       |   | **2003**                     |       | **2002** | ** ** | **2001** | ** ** |
|                                                                                                                                                                       |   |                         |       |   |   |   |   |
| Net income                                                                                                                                                                 |   | $                            | 90,839     |   | $ | 88,929 |   | $ | 106,781 |   |
|                                                                                                                                                                       |   |                         |       |   |   |   |   |
| Cumulative effect of change in accounting  principle – Accounting for derivative instruments and hedging activities, net  of tax benefit/(expense) of $2,399 for 2001 |   | —                       |       | — |   | (3,599 | ) |
|                                                                                                                                                                       |   |                         |       |   |   |   |   |
| Gain/(losses) on derivative instruments and  hedging activities, net of tax benefit/(expense) of $(358), $3,404 and $1,043  for 2003, 2002 and 2001, respectively (Note 1) |   | 544                          |       | (5,107 | ) | (1,563 | ) |
|                                                                                                                                                                       |   |                         |       |   |   |   |   |
| Additional minimum pension liability adjustment,  net of tax benefit/(expense) of $(1,257), $10,494 and $9,974 for 2003, 2002  and 2001, respectively (Note 6)             |   | 1,857                        |       | (15,505 | ) | (14,738 | ) |
|                                                                                                                                                                       |   |                         |       |   |   |   |   |
| Other comprehensive income (loss), net of  tax                                                                                                                             |   | 2,401                        |       | (20,612 | ) | (19,900 | ) |
|                                                                                                                                                                       |   |                         |       |   |   |   |   |
| Comprehensive income                                                                                                                                                       |   | $                            | 93,240     |   | $ | 68,317 |   | $ | 86,881 |   |

 

The accompanying notes are anintegral part of these consolidated financial statements.

 

70

----

 

Louisville Gas and Electric Company and Subsidiary

ConsolidatedBalance Sheets

(Thousands of $)

 
|                                                                        |   | **December  31** |      |
|-----------------------------------------------------------------------------|--------|------------------|-----------|
|                                                                        |   | **2003**         |      | **2002** | ** ** |
| ASSETS:                                                                     |   |             |      |   |   |
| Utility plant, at original cost (Note 1):                                   |   |             |      |   |   |
| Electric                                                                    |   | $                | 2,809,957 |   | $ | 2,717,187 |   |
| Gas                                                                         |   | 468,504          |      | 435,235 |   |
| Common                                                                      |   | 186,556          |      | 169,577 |   |
|                                                                        |   | 3,465,017        |      | 3,321,999 |   |
| Less:   reserve for depreciation                                       |   | 1,319,768        |      | 1,255,822 |   |
|                                                                        |   | 2,145,249        |      | 2,066,177 |   |
| Construction work in progress                                               |   | 339,166          |      | 300,986 |   |
|                                                                        |   | 2,484,415        |      | 2,367,163 |   |
|                                                                        |   |             |      |   |   |
| Other property and investments – less  reserve of $63 in 2003 and 2002 |   | 611              |      | 764 |   |
|                                                                        |   |             |      |   |   |
| Current assets:                                                             |   |             |      |   |   |
| Cash (Note 1)                                                               |   | 1,706            |      | 17,015 |   |
| Accounts receivable - less reserve of  $3,515 in 2003 and $2,125 in 2002    |   | 84,585           |      | 68,440 |   |
| Materials and supplies - at average cost:                                   |   |             |      |   |   |
| Fuel (predominantly coal) (Note 1)                                          |   | 25,260           |      | 36,600 |   |
| Gas stored underground (Note 1)                                             |   | 69,884           |      | 50,266 |   |
| Other (Note 1)                                                              |   | 24,971           |      | 25,651 |   |
| Prepayments and other                                                       |   | 5,281            |      | 5,298 |   |
|                                                                        |   | 211,687          |      | 203,270 |   |
|                                                                        |   |             |      |   |   |
| Deferred debits and other assets:                                           |   |             |      |   |   |
| Unamortized debt expense (Note 1)                                           |   | 8,468            |      | 6,532 |   |
| Regulatory assets (Note 3)                                                  |   | 142,772          |      | 153,446 |   |
| Other                                                                       |   | 40,975           |      | 37,755 |   |
|                                                                        |   | 192,215          |      | 197,733 |   |
|                                                                        |   | $                | 2,888,928 |   | $ | 2,768,930 |   |
| CAPITAL AND LIABILITIES:                                                    |   |             |      |   |   |
| Capitalization (see statements of  capitalization):                         |   |             |      |   |   |
| Common equity                                                               |   | $                | 923,664   |   | $ | 833,141 |   |
| Cumulative preferred stock                                                  |   | 70,140           |      | 95,140 |   |
|                                                                        |   | 993,804          |      | 928,281 |   |
| Long-term debt:                                                             |   |             |      |   |   |
| Long-term bonds (Note 9)                                                    |   | 328,104          |      | 328,104 |   |
| Long-term notes to affiliated company (Note  9)                             |   | 200,000          |      | — |   |
| Mandatorily redeemable preferred stock  (Note 9)                            |   | 22,500           |      | — |   |
|                                                                        |   | 550,604          |      | 328,104 |   |
|                                                                        |   | 1,544,408        |      | 1,256,385 |   |
|                                                                        |   |             |      |   |   |
| Current liabilities:                                                        |   |             |      |   |   |
| Current portion of long-term debt:                                          |   |             |      |   |   |
| Long-term bonds (Note 9)                                                    |   | 246,200          |      | 288,800 |   |
| Mandatorily redeemable preferred stock  (Note 9)                            |   | 1,250            |      | — |   |
|                                                                        |   | 247,450          |      | 288,800 |   |
| Notes payable to affiliated company (Notes  10 and 14)                      |   | 80,332           |      | 193,053 |   |
| Accounts payable                                                            |   | 93,118           |      | 96,410 |   |
| Accounts payable to affiliated companies  (Note 14)                         |   | 38,343           |      | 26,361 |   |
| Accrued taxes                                                               |   | 18,615           |      | 1,450 |   |
| Customer deposits                                                           |   | 10,493           |      | 9,735 |   |
| Other                                                                       |   | 9,308            |      | 9,801 |   |
|                                                                        |   | 250,209          |      | 336,810 |   |
|                                                                        |   | 497,659          |      | 625,610 |   |
| Deferred credits and other liabilities:                                     |   |             |      |   |   |
| Accumulated deferred income taxes (Notes 1  and 7)                          |   | 337,704          |      | 313,225 |   |
| Investment tax credit, in process of  amortization                          |   | 50,329           |      | 54,536 |   |
| Accumulated provision for pensions and  related benefits (Note 6)           |   | 140,598          |      | 224,703 |   |
| Asset retirement obligations                                                |   | 9,747            |      | — |   |
| Regulatory liabilities (Note 3):                                            |   |             |      |   |   |
| Accumulated cost of removal of utility  plant                               |   | 223,622          |      | 207,852 |   |
| Other                                                                       |   | 51,822           |      | 52,424 |   |
| Other                                                                       |   | 33,039           |      | 34,195 |   |
|                                                                        |   | 846,861          |      | 886,935 |   |
|                                                                        |   |             |      |   |   |
| Commitments and contingencies (Note 11)                                     |   | $                | 2,888,928 |   | $ | 2,768,930 |   |

 

The accompanying notes are an integral part ofthese consolidated financial statements.

 

71

----

 

Louisville Gas and Electric Company and Subsidiary

ConsolidatedStatements of Cash Flows

(Thousands of $)

 
|                                                        |   | **Years  Ended December 31** |   |
|-------------------------------------------------------------|--------|------------------------------|--------|
|                                                        |   | **2003**                     |   | **2002** | ** ** | **2001** | ** ** |
|                                                        |   |                         |   |   |   |   |   |
| CASH FLOWS FROM OPERATING ACTIVITIES:                       |   |                         |   |   |   |   |   |
| Net income                                                  |   | $                            | 90,839 |   | $ | 88,929 |   | $ | 106,781 |   |
| Items not requiring cash currently:                         |   |                         |   |   |   |   |   |
| Depreciation and amortization                               |   | 113,288                      |   | 105,906 |   | 100,356 |   |
| Deferred income taxes - net                                 |   | 20,123                       |   | 11,915 |   | 3,021 |   |
| Investment tax credit - net                                 |   | (4,207                       | )      | (4,153 | ) | (4,290 | ) |
| LG&E/KU merger amortization                             |   | 1,815                        |   | 3,629 |   | 3,629 |   |
| VDT amortization                                            |   | 30,400                       |   | 30,000 |   | 13,000 |   |
| Mark-to-market financial instruments                        |   | (1,149                       | )      | 8,512 |   | 8,604 |   |
| One utility amortization                                    |   | 954                          |   | 2,688 |   | 2,689 |   |
| Other                                                       |   | 8,042                        |   | 4,909 |   | 1,239 |   |
| Change in certain net current assets:                       |   |                         |   |   |   |   |   |
| Accounts receivable                                         |   | (10,945                      | )      | (3,973 | ) | 43,185 |   |
| Materials and supplies                                      |   | (7,598                       | )      | (15,048 | ) | (2,018 | ) |
| Accounts payable                                            |   | 8,690                        |   | (26,299 | ) | 14,678 |   |
| Accrued taxes                                               |   | 17,165                       |   | (18,807 | ) | 12,184 |   |
| Prepayments and other                                       |   | 906                          |   | 321 |   | (10,500 | ) |
| Sale of accounts receivable (Note 1)                        |   | (5,200                       | )      | 21,200 |   | 42,000 |   |
| Pension funding                                             |   | (89,125                      | )      | 336 |   | 374 |   |
| VDT expenses                                                |   | (166                         | )      | (514 | ) | (140,529 | ) |
| Pension liability                                           |   | 3,908                        |   | 11,904 |   | 66,865 |   |
| Provision for post-retirement benefits                      |   | 4,031                        |   | 1,775 |   | 38,459 |   |
| Gas supply clause                                           |   | (4,712                       | )      | 3,873 |   | (4,138 | ) |
| Other                                                       |   | (13,809                      | )      | (14,722 | ) | (8,526 | ) |
| Net cash flows from operating activities                    |   | 163,250                      |   | 212,381 |   | 287,063 |   |
|                                                        |   |                         |   |   |   |   |   |
| CASH FLOWS FROM INVESTING ACTIVITIES:                       |   |                         |   |   |   |   |   |
| Proceeds from sales of securities                           |   | 153                          |   | 412 |   | 4,237 |   |
| Construction expenditures                                   |   | (212,957                     | )      | (220,416 | ) | (252,958 | ) |
| Net cash flows from investing activities                    |   | (212,804                     | )      | (220,004 | ) | (248,721 | ) |
|                                                        |   |                         |   |   |   |   |   |
| CASH FLOWS FROM FINANCING ACTIVITIES:                       |   |                         |   |   |   |   |   |
| Long-term borrowings from affiliated  company               |   | 200,000                      |   | — |   | — |   |
| Short-term borrowings                                       |   | —                       |   | — |   | 29,944 |   |
| Repayment of short-term borrowings                          |   | —                       |   | (29,944 | ) | — |   |
| Short-term borrowings from affiliated  company              |   | 602,700                      |   | 652,300 |   | 656,282 |   |
| Repayment of short-term borrowings from  affiliated company |   | (715,421                     | )      | (523,500 | ) | (706,618 | ) |
| Retirement of first mortgage bonds                          |   | (42,600                      | )      | — |   | — |   |
| Issuance of pollution control bonds                         |   | 128,000                      |   | 161,665 |   | 10,104 |   |
| Issuance expense on pollution control bonds                 |   | (5,843                       | )      | (3,030 | ) | (442 | ) |
| Retirement of pollution control bonds                       |   | (128,000                     | )      | (161,665 | ) | — |   |
| Retirement of manditorily redeemable  preferred stock       |   | (1,250                       | )      | — |   | — |   |
| Payment of dividends                                        |   | (3,341                       | )      | (73,300 | ) | (27,995 | ) |
| Net cash flows from financing activities                    |   | 34,245                       |   | 22,526 |   | (38,725 | ) |
|                                                        |   |                         |   |   |   |   |   |
| Change in cash and temporary cash  investments              |   | (15,309                      | )      | 14,903 |   | (383 | ) |
|                                                        |   |                         |   |   |   |   |   |
| Cash and temporary cash investments at  beginning of year   |   | 17,015                       |   | 2,112 |   | 2,495 |   |
|                                                        |   |                         |   |   |   |   |   |
| Cash and temporary cash investments at end  of year         |   | $                            | 1,706  |   | $ | 17,015 |   | $ | 2,112 |   |
|                                                        |   |                         |   |   |   |   |   |
| Supplemental disclosures of cash flow  information:         |   |                         |   |   |   |   |   |
|                                                        |   |                         |   |   |   |   |   |
| Cash paid during the year for:                              |   |                         |   |   |   |   |   |
| Income taxes                                                |   | $                            | 24,868 |   | $ | 51,540 |   | $ | 35,546 |   |
| Interest on borrowed money                                  |   | 23,829                       |   | 25,673 |   | 30,989 |   |
| Interest to affiliated companies on  borrowed money         |   | 4,162                        |   | 1,850 |   | 2,966 |   |

 

The accompanying notes are anintegral part of these consolidated financial statements.

 

72

----

 

Louisville Gas and Electric Company and Subsidiary

ConsolidatedStatements of Capitalization

(Thousands of $)

 
|                                                                                           |   |                    |       |                          |       | **December  31** |       |
|------------------------------------------------------------------------------------------------|--------|-------------------------|------------|-------------------------------|------------|------------------|------------|
|                                                                                           |   |                    |       |                          |       | **2003**         |       | **2002** | ** ** |
| COMMON EQUITY:                                                                                 |   |                    |       |                          |       |             |       |   |   |
| Common stock, without par value -  Authorized 75,000,000 shares, outstanding 21,294,223 shares |   |                    |       |                          |       | $                | 425,170    |   | $ | 425,170 |   |
| Common stock expense                                                                           |   |                    |       |                          |       | (836             | )          | (836 | ) |
| Additional paid-in capital                                                                     |   |                    |       |                          |       | 40,000           |       | 40,000 |   |
| Accumulated other comprehensive income                                                         |   |                    |       |                          |       | (38,111          | )          | (40,512 | ) |
| Retained earnings                                                                              |   |                    |       |                          |       | 497,441          |       | 409,319 |   |
|                                                                                           |   |                    |       |                          |       |             |       |   |   |
|                                                                                           |   |                    |       |                          |       | 923,664          |       | 833,141 |   |
|                                                                                           |   |                    |       |                          |       |             |       |   |   |
|                                                                                           |   | **Shares  Outstanding** | ** ** | **Current  Redemption Price** | ** ** |             | ** ** |   | ** ** |
| CUMULATIVE PREFERRED STOCK:                                                                    |   |                    |       |                          |       |             |       |   |   |   |
| $25 par value, 1,720,000 shares authorized  - 5% series                                        |   | 860,287                 |       | $                             | 28.00      |             | 21,507     |   | 21,507 |   |
| Without par value, 6,750,000 shares  authorized - Auction rate                                 |   | 500,000                 |       | 100.00                        |       | 50,000           |       | 50,000 |   |
| $5.875 series                                                                                  |   | 237,500                 |       | 100.00                        |       | —           |       | 25,000 |   |
| Preferred stock expense                                                                        |   |                    |       |                          |       | (1,367           | )          | (1,367 | ) |
|                                                                                           |   |                    |       |                          |       |             |       |   |   |
|                                                                                           |   |                    |       |                          |       | 70,140           |       | 95,140 |   |
| LONG-TERM DEBT (Note 9):                                                                       |   |                    |       |                          |       |             |       |   |   |
| First mortgage bonds -                                                                         |   |                    |       |                          |       |             |       |   |   |
| Series due August 15, 2003, 6%                                                                 |   |                    |       |                          |       | —           |       | 42,600 |   |
| Pollution control series:                                                                      |   |                    |       |                          |       |             |       |   |   |
| S due September 1, 2017, variable %                                                            |   |                    |       |                          |       | 31,000           |       | 31,000 |   |
| T due September 1, 2017, variable %                                                            |   |                    |       |                          |       | 60,000           |       | 60,000 |   |
| U due August 15, 2013, variable %                                                              |   |                    |       |                          |       | 35,200           |       | 35,200 |   |
| V due August 15, 2019, 5.625%                                                                  |   |                    |       |                          |       | —           |       | 102,000 |   |
| W due October 15, 2020, 5.45%                                                                  |   |                    |       |                          |       | —           |       | 26,000 |   |
| X due April 15, 2023, 5.90%                                                                    |   |                    |       |                          |       | 40,000           |       | 40,000 |   |
| Y due May 1, 2027, variable %                                                                  |   |                    |       |                          |       | 25,000           |       | 25,000 |   |
| Z due August 1, 2030, variable %                                                               |   |                    |       |                          |       | 83,335           |       | 83,335 |   |
| AA due September 1, 2027, variable %                                                           |   |                    |       |                          |       | 10,104           |       | 10,104 |   |
| BB due September 1, 2026, variable %                                                           |   |                    |       |                          |       | 22,500           |       | 22,500 |   |
| CC due September 1, 2026, variable %                                                           |   |                    |       |                          |       | 27,500           |       | 27,500 |   |
| DD due November 1, 2027, variable %                                                            |   |                    |       |                          |       | 35,000           |       | 35,000 |   |
| EE due November 1, 2027, variable %                                                            |   |                    |       |                          |       | 35,000           |       | 35,000 |   |
| FF due October 1, 2032, variable %                                                             |   |                    |       |                          |       | 41,665           |       | 41,665 |   |
| GG due October 1, 2033, variable %                                                             |   |                    |       |                          |       | 128,000          |       | — |   |
| Notes payable to Fidelia:                                                                      |   |                    |       |                          |       |             |       |   |   |
| Due April 30, 2013, 4.55%, unsecured                                                           |   |                    |       |                          |       | 100,000          |       | — |   |
| Due August 15, 2013, 5.31%, secured                                                            |   |                    |       |                          |       | 100,000          |       | — |   |
| Mandatorily redeemable preferred stock:                                                        |   |                    |       |                          |       |             |       |   |   |
| $5.875 series, outstanding shares of  237,500 in 2003 and 250,000 in 2002                      |   |                    |       |                          |       | 23,750           |       | — |   |
|                                                                                           |   |                    |       |                          |       |             |       |   |   |
| Total long-term debt outstanding                                                               |   |                    |       |                          |       | 798,054          |       | 616,904 |   |
|                                                                                           |   |                    |       |                          |       |             |       |   |   |
| Less current portion of long-term debt                                                         |   |                    |       |                          |       | 247,450          |       | 288,800 |   |
|                                                                                           |   |                    |       |                          |       |             |       |   |   |
| Long-term debt                                                                                 |   |                    |       |                          |       | 550,604          |       | 328,104 |   |
|                                                                                           |   |                    |       |                          |       |             |       |   |   |
| Total capitalization                                                                           |   |                    |       |                          |       | $                | 1,544,408  |   | $ | 1,256,385 |   |

 

The accompanying notes are anintegral part of these consolidated financial statements.

 

73

----

 

Louisville Gas and Electric Company and Subsidiary

Notes toConsolidated Financial Statements

 

**Note 1 - Summary of Significant AccountingPolicies**

 

LG&E, a subsidiary ofLG&E Energy and an indirect subsidiary of E.ON, is a regulated publicutility engaged in the generation, transmission, distribution, and sale ofelectric energy and the storage, distribution, and sale of natural gas inLouisville and adjacent areas in Kentucky. LG&E Energy is a registered public utility holding company withwholly owned subsidiaries including LG&E, KU, Capital Corp., LEM, andLG&E Services.  All of LG&E’scommon stock is held by LG&E Energy. LG&E has one wholly owned consolidated subsidiary, LG&E R.  The consolidated financial statementsinclude the accounts of LG&E and LG&E R with the elimination ofintercompany accounts and transactions.

 

On December 11, 2000,LG&E Energy was acquired by Powergen. On July 1, 2002, E.ON, a German company, completed its acquisition ofPowergen plc (now Powergen Limited).  E.ON had announced itspre-conditional cash offer of £5.1 billion ($7.3 billion) for Powergen on April9, 2001.  E.ON and Powergen areregistered public utility holding companies under PUHCA.

 

No costs associated with the E.ONpurchase of Powergen or the Powergen purchase of LG&E Energy nor anyeffects of purchase accounting have been reflected in the financial statementsof LG&E.

 

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

 

Certain reclassificationentries have been made to the previous years’ financial statements to conformto the 2003 presentation with no impact on the balance sheet net assets orpreviously reported income.

 

**RegulatoryAccounting. **Accountingfor the regulated utility business conforms with generally accepted accountingprinciples as applied to regulated public utilities and as prescribed by FERCand the Kentucky Commission.  LG&Eis subject to SFAS No. 71, *Accounting for the Effects of Certain Types ofRegulation*, under which certain costs that would otherwise becharged to expense are deferred as regulatory assets based on expected recoveryfrom customers in future rates. Likewise, certain credits that would otherwise be reflected as incomeare deferred as regulatory liabilities based on expected return to customers infuture rates.  LG&E’s current orexpected recovery of deferred costs and expected return of deferred credits isgenerally based on specific ratemaking decisions or precedent for eachitem.  See Note 3 for additional detailregarding regulatory assets and liabilities.

 

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

 

The cost of plant retired ordisposed of in the normal course of business is deducted from plant accountsand such cost, plus removal expense less salvage value, is charged to thereserve 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 is provided on thestraight-line method over the estimated service lives of depreciableplant.  The amounts provided were approximately3.3% in 2003 (2.9% electric, 2.8% gas, and

 

74

----

 

9.4% common); 3.1% in 2002(2.9% electric, 2.8% gas and 6.6% common); and 3.0% for 2001 (2.9% electric,2.9% gas and 5.7% common), of average depreciable plant.  Of the amount provided for depreciation, atDecember 31, 2003, approximately 0.4% electric, 0.8% gas and 0.1% commonwere related to the retirement, removal and disposal costs of long lived assets.

 

**Cash and Temporary Cash Investments. **LG&E considersall debt instruments purchased with a maturity of three months or less to becash equivalents.  Temporary cashinvestments are carried at cost, which approximates fair value.

 

**Fuel Inventory.**  Fuel inventories of $25.3 million and $36.6million at December 31, 2003, and 2002, respectively, are included in Fuel inthe balance sheet.  The inventory isaccounted for using the average-cost method.

 

**Gas Stored Underground.**  Gas inventories of $69.9 million and $50.3million at December 31, 2003, and 2002, respectively, are included in Gasstored underground in the balance sheet. The inventory is accounted for using the average-cost method.

 

**Other Materials and Supplies. **Non-fuel materialsand supplies of $25.0 million and $25.7 million at December 31, 2003 and 2002,respectively, are accounted for using the average-cost method.

 

**FinancialInstruments.** LG&E uses over-the-counter interest-rate swap agreements to hedgeits exposure to fluctuations in the interest rates it pays on variable-ratedebt.  Gains and losses on interest-rateswaps used to hedge interest rate risk are reflected in other comprehensiveincome.  LG&E uses sales ofmarket-traded electric forward contracts for periods less than one year tohedge the price volatility of its forecasted peak electric off-systemsales.  Gains and losses resulting fromineffectiveness are shown in other income (expense) and to the extent that thehedging relationship has been effective, gains and losses are reflected inother comprehensive income.  See Note 4- Financial Instruments.

 

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

 

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

 

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

 

**Revenue Recognition.**  Revenues are recorded based on servicerendered to customers through month-end. LG&E accrues an estimate for unbilled revenues from each meterreading date to the end of the accounting period based on allocating the dailysystem net deliveries between billed volumes and unbilled volumes. Theallocation is based on a daily ratio of the number of meter reading cyclesremaining in the month to the total number of meter reading cycles in eachmonth.  Each day’s ratio is thenmultiplied by each day’s system net deliveries to determine an estimated billedand unbilled volume for each day of the accounting period.  The unbilled revenue estimates included inaccounts receivable were approximately $50.8 million and $40.7 million atDecember 31, 2003 and 2002, respectively.

 

**Allowance for Doubtful Accounts.**At December 31, 2003 and 2002, the LG&E allowance for doubtful accounts was$3.5 million and $2.1 million, respectively. The allowance is based on theratio of the amounts charged-off during the last twelve months to the retailrevenues billed over the same period multiplied by the retail revenues billedover the last four months.  Accountswith no payment activity are charged-off after four

 

75

----

 

months.

 

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

 

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

 

**New AccountingPronouncements.** The following accountingpronouncements were implemented by LG&E in 2003:

 

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

 

The effective implementationdate for SFAS No. 143 was January 1, 2003. Management has calculated the impact of SFAS No. 143 and FERC FinalOrder No. 631 issued in Docket No. RM02-7, *Accounting, Financial Reporting, and Rate FilingRequirements for Asset Retirement Obligations. *The Company evaluated the impact of SFAS 143 from both alegal and operations perspective, reviewing applicable laws and regulationsaffecting the industry, contracts, permits, certificates of need and right ofway agreements, to determine if legal obligations existed.   The fair value of future removalobligations was calculated based on the Company’s engineering estimates, costsexpended for similar retirements and third party estimates at current marketprices inflated at a rate of 2.31% per year to the expected retirement date ofthe asset.  The future removalobligations were then discounted to their net present value at the originalasset in-service date based on a discount rate of 6.61%.  ARO assets equal to the net present valuewere recorded on the Company’s books at implementation.  An amount equal to the net present valueplus the accretion the Company would have accrued had the standard been in effectat the original in-service date was also recorded on the Company’s books as anARO liability at implementation. Additionally, the Company contracted with an independent consultant toquantify the cost of removal included in its accumulated depreciation underregulatory accounting practices.

 

As of January 1, 2003, LG&Erecorded asset retirement obligation (ARO) assets in the amount of $4.6 millionand liabilities in the amount of $9.3 million. LG&E also recorded a cumulative effect adjustment in the amount of$5.3 million to reflect the accumulated depreciation and accretion of AROassets at the transition date less amounts previously accrued under regulatorydepreciation.  LG&E recordedoffsetting regulatory assets of $5.3 million, pursuant to regulatory treatmentprescribed under SFAS No. 71, *Accounting for the Effects of Certain Types ofRegulation*.  Also pursuant toSFAS No. 71, LG&E recorded regulatory liabilities in the amount of $0.1million offsetting removal costs previously accrued under regulatory accountingin excess of amounts allowed under SFAS No. 143.

 

Had SFAS No. 143 been in effectfor the 2002 reporting period, LG&E would have established asset retirementobligations as described in the following table:

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

 

As of December 31, 2003,LG&E recorded ARO assets, net of accumulated depreciation, of $4.5 millionand liabilities of $9.7 million. LG&E recorded regulatory assets of $6.0 million and regulatoryliabilities of $0.1 million.

 

For the year endedDecember 31, 2003, LG&E recorded ARO accretion expense ofapproximately $0.6 million, ARO depreciation expense of $0.1 million and anoffsetting regulatory credit in the income statement of $0.7 million, pursuantto regulatory treatment prescribed under SFAS No. 71.  Approximately $0.2 million of removal costs were incurred andcharged against the ARO liability during 2003. SFAS No. 143 has no impact on the results of the operation of LG&E.

 

76

----

 

LG&E AROs are primarilyrelated to final retirement of assets associated 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 year endedDecember 31, 2003, LG&E recorded approximately $25,000 of depreciationexpense related to the cost of removal of ARO related assets.  An offsetting regulatory liability wasestablished pursuant to regulatory treatment prescribed under SFAS No. 71.

 

LG&E also continues toinclude a cost of removal component in depreciation for assets that do not havea legal ARO.  As of December 31, 2003and 2002, LG&E has segregated this cost of removal, included in accumulateddepreciation, of $223.6 million and $207.9 million, respectively, in accordancewith FERC Order No. 631*.*  For reporting purposes in its ConsolidatedBalance Sheets, LG&E has presented this cost of removal as a regulatoryliability pursuant to SFAS No. 71.

 

LG&E transmission anddistribution lines largely operate under perpetual property easement agreementswhich do not generally require restoration upon removal of the property.  Therefore, under SFAS No. 143, no materialasset retirement obligations are recorded for transmission and distributionassets.

 

LG&E adopted EITF No.98-10, *Accountingfor Energy Trading and Risk Management Activities,*effective January1, 1999.  This pronouncement requiredthat energy trading contracts be marked to market on the balance sheet, withthe gains and losses shown net in the income statement.  Effective January 1, 2003, LG&E adoptedEITF No. 02-03, *Issues Involved in Accounting for Derivative Contracts Held for TradingPurposes and Contracts Involved in Energy Trading and Risk ManagementActivities*.  EITF No. 02-03established the following:

 

•                  Rescinded EITFNo. 98-10,

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

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

 

With the rescission of EITF No.98-10, energy trading contracts that do not also meet the definition of aderivative under SFAS No. 133 must be accounted for as executorycontracts.  Contracts previouslyrecorded at fair value under EITF No. 98-10 that are not also derivatives underSFAS No. 133, *Accounting for Derivative Instruments**and**Hedging Activities*, must berestated to historical cost through a cumulative effect adjustment.  The rescission of this standard had noimpact on financial position or results of operations of LG&E since allforward and option contracts marked to market under EITF No. 98-10 were alsowithin the scope of SFAS No. 133.

 

As a result of EITF No. 02-03,LG&E has netted the power purchased expense for trading activities againstelectric operating revenue to reflect this accounting change.  LG&E applied this guidance to all priorperiods, which had no impact on previously reported net income or commonequity.

 
| **(in  thousands)**                           |   | **2002** |      | **2001** |   |
|-----------------------------------------------|--------|----------|-----------|----------|--------|
| Gross operating revenues                      |   | $        | 1,026,184 |     | $      | 996,700 |   |
| Less costs reclassified from power  purchased |   | 22,449   |      | 32,153   |   |
| Net operating revenues reported               |   | $        | 1,003,735 |     | $      | 964,547 |   |
|                                          |   |     |      |     |   |
| Gross power purchased                         |   | $        | 84,330    |     | $      | 81,475 |   |
| Less costs reclassified to revenues           |   | 22,449   |      | 32,153   |   |
| Net power purchased reported                  |   | $        | 61,881    |     | $      | 49,322 |   |

 

77

----

 

In May 2003, the Financial AccountingStandards Board issued SFAS No. 150, *Accounting for Certain Financial Instruments withCharacteristics of both Liabilities and Equity*.  SFAS No. 150 was effective immediately forfinancial instruments entered into or modified after May 31, 2003, andotherwise was effective for interim reporting periods beginning after June 15,2003, except for certain instruments and certain entities which have been deferredby the FASB.  Such deferrals do notaffect LG&E.

 

LG&E has existing $5.875 seriesmandatorily redeemable preferred stock outstanding having a current redemptionprice of $100 per share. The preferred stock has a sinking fund requirementsufficient to retire a minimum of 12,500 shares on July 15 of each yearcommencing with July 15, 2003, and the remaining 187,500 shares on July 15,2008 at $100 per share.  LG&Eredeemed 12,500 shares in accordance with these provisions on July 15, 2003,leaving 237,500 shares currently outstanding. Beginning with the three months ended September 30, 2003, LG&Ereclassified its $5.875 series preferred stock as long-term debt with theminimum shares mandatorily redeemable within one year classified ascurrent.  Dividends accrued beginningJuly 1, 2003 are charged as interest expense.

 

In January 2003, the FinancialAccounting Standards Board issued Financial Accounting Standards BoardInterpretation No. 46, *Consolidation of Variable Interest Entities*,an Interpretation of ARB No. 51 (FIN 46). FIN 46 requires certain variable interest entities to be consolidated bythe primary beneficiary of the entity if the equity investors in the entity donot have the characteristics of a controlling financial interest or do not havesufficient equity at risk for the entity to finance its activities withoutadditional subordinated financial support from other parties.  FIN 46 was effective immediately for all newvariable interest entities created or acquired after January 31, 2003.  For variable interest entities created oracquired prior to February 1, 2003, the provisions of FIN 46 must have beenapplied for the first interim or annual period beginning after June 15, 2003.

 

In December 2003, FIN 46 wasrevised, delaying the effective dates for certain entities created beforeFebruary 1, 2003, and making other amendments to clarify application of theguidance.  For potential variableinterest entities other than special purpose entities, the revised FIN 46 (FIN46R) is now required to be applied no later than the end of the first fiscalyear or interim reporting period ending after March 15, 2004.  The original guidance under FIN 46 wasapplicable, however, for all special purpose entities created prior to February1, 2003, at the end of the first interim or annual reporting period endingafter December 15, 2003.  FIN 46R may beapplied prospectively with a cumulative-effect adjustment as of the date it isfirst applied, or by restating previously issued financial statements with a cumulative-effectadjustment as of the beginning of the first year restated.  FIN 46R also requires certain disclosures ofan entity’s relationship with variable interest entities.

 

LG&E has no special purposeentities that fall within the scope of FIN 46R.  LG&E continues to evaluate the impact that FIN 46R may have onits financial position and results of operations.

 

**Note 2 – Mergers and Acquisitions**

 

On July 1, 2002, E.ON completed itsacquisition of Powergen, including LG&E Energy, for approximately £5.1billion ($7.3 billion).  As a result ofthe acquisition, LG&E Energy became a wholly owned subsidiary (throughPowergen) of E.ON and, as a result, LG&E also became an indirect subsidiaryof E.ON.  LG&E has continued itsseparate identity and serves customers in Kentucky under its existingname.  The preferred stock and debtsecurities of LG&E were not affected by this transaction and the utilitiescontinue to file SEC reports.  Followingthe acquisition, E.ON became, and Powergen remained, a registered holdingcompany under PUHCA. LG&E, as a subsidiary of a registered holding company,is subject to additional regulations under PUHCA.  As contemplated in their regulatory filings in connection withthe E.ON acquisition, E.ON, Powergen and LG&E Energy completed anadministrative reorganization to move the LG&E Energy group from an

 

78

----

 

indirect Powergen subsidiary to an indirectE.ON subsidiary.  This reorganizationwas effective in March 2003. In early 2004, LG&E Energy commenced directreporting arrangements to E.ON.

 

LG&E Energy and KU Energymerged on May 4, 1998, with LG&E Energy as the surviving corporation.  Management accounted for the merger as apooling of interests and as a tax-free reorganization under the InternalRevenue Code.  Following theacquisition, LG&E has continued to maintain its separate corporate identityand serve customers under its present name.

 

**Note 3 - Rates and Regulatory Matters**

 

The following regulatory assetsand liabilities were included in LG&E’s balance sheets as of December 31:

 
| **(in thousands)**                            |   | **2003** |     | **2002** |   |
|-----------------------------------------------|--------|----------|----------|----------|--------|
|                                          |   |     |     |     |   |
| VDT Costs                                     |   | $        | 67,810   |     | $      | 98,044 |   |
| Gas supply adjustments due from customers     |   | 22,077   |     | 13,714   |   |
| Unamortized loss on bonds                     |   | 21,333   |     | 18,843   |   |
| ESM provision                                 |   | 12,359   |     | 12,500   |   |
| LG&E/KU merger costs                      |   | —   |     | 1,815    |   |
| Merger surcredit                              |   | 6,220    |     | —   |   |
| Manufactured gas sites                        |   | 1,454    |     | 1,757    |   |
| One utility costs                             |   | —   |     | 954      |   |
| ARO                                           |   | 6,015    |     | —   |   |
| Gas performance base ratemaking               |   | 5,480    |     | 4,243    |   |
| DSM                                           |   | 24       |     | 1,576    |   |
| Total regulatory assets                       |   | $        | 142,772  |     | $      | 153,446 |   |
|                                          |   |     |     |     |   |
| Accumulated cost of removal of utility  plant |   | $        | (223,622 | )        | $      | (207,852 | ) |
| Deferred income taxes - net                   |   | (41,180  | )        | (45,536  | )      |
| Gas supply adjustments due to customers       |   | (6,805   | )        | (3,154   | )      |
| ARO                                           |   | (85      | )        | —   |   |
| Gas purchase refund                           |   | —   |     | (328     | )      |
| ESM                                           |   | (79      | )        | (1,479   | )      |
| ECR                                           |   | (17      | )        | (243     | )      |
| FAC                                           |   | (1,950   | )        | —   |   |
| DSM                                           |   | (1,706   | )        | (1,684   | )      |
| Total regulatory liabilities                  |   | $        | (275,444 | )        | $      | (260,276 | ) |

 

LG&E currently earns areturn on all regulatory assets except for gas supply adjustments, ESM, gasperformance based ratemaking and DSM, all of which are separate rate mechanismswith recovery within twelve months. Additionally, no current return is earned on the ARO regulatoryasset.  This regulatory asset will beoffset against the associated regulatory liability, ARO asset, and AROliability at the time the underlying asset is retired.

 

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

 

In June 2001, LG&E filed anapplication (VDT case) with the Kentucky Commission to create a regulatoryasset relating to these first quarter 2001 charges.  The application requested permission to amortize these costs overa four-year period.  The KentuckyCommission also opened a case to review a new depreciation study and

 

79

----

 

resulting depreciation ratesimplemented in 2001.

 

LG&E reached a settlementin the VDT case as well as other cases involving the depreciation rates and ESMwith all intervening parties.  Thesettlement agreement was approved by the Kentucky Commission in December 2001.The order allowed LG&E to set up a regulatory asset of $141 million for theworkforce reduction costs and begin amortizing these costs over a five-yearperiod starting in April 2001. The first quarter 2001 charge of $144 millionrepresented all employees who had accepted a voluntary enhanced severanceprogram.  Some employees rescinded theirparticipation in the voluntary enhanced severance program, thereby decreasingthe original charge to the regulatory asset from $144 million to $141 million.The settlement reduces revenues approximately $26 million through a surcrediton bills to ratepayers over the same five-year period.  The surcredit represents net savingsstipulated by LG&E.  The agreementalso established LG&E’s new depreciation rates in effect December 2001,retroactive to January 2001.  The newdepreciation rates decreased depreciation expense by $5.6 million in 2001.

 

**PUHCA.**  Following the purchases of LG&E Energyby Powergen and Powergen by E.ON, Powergen and E.ON became registered holdingcompanies under PUHCA.  As a result,E.ON, its utility subsidiaries, including LG&E, and certain of its non-utilitysubsidiaries are subject to extensive regulation by the SEC under PUHCA withrespect to issuances and sales of securities, acquisitions and sales of certainutility properties, and intra-system sales of certain goods and services.  In addition, PUHCA generally limits theability of registered holding companies to acquire additional public utilitysystems and to acquire and retain businesses unrelated to the utilityoperations of the holding company. LG&E believes that it has adequate authority (including financingauthority) under existing SEC orders and regulations to conduct itsbusiness.  LG&E will seek additionalauthorization when necessary.

 

**ECR. **InJune 2000, the Kentucky Commission approved LG&E’s application for a CCN toconstruct up to three SCR NOx reduction facilities. The construction andsubsequent operation of the SCRs is intended to reduce NOx emission levels tomeet the EPA’s mandated NOx emission level of 0.15 lbs./ Mmbtu by May2004.  In its order, the KentuckyCommission ruled that LG&E’s proposed plan for construction was“reasonable, cost-effective and will not result in the wasteful duplication offacilities.”  In October 2000, LG&Efiled an application with the Kentucky Commission to amend its EnvironmentalCompliance Plan to reflect the addition of the proposed NOx reductiontechnology projects and to amend its ECR Tariff to include an overall rate ofreturn on capital investments. Approval of LG&E’s application in April 2001allowed LG&E to begin to recover the costs associated with these newprojects, subject to Kentucky Commission oversight during normal six-month andtwo-year reviews.

 

In May 2002, the KentuckyCommission initiated a periodic two-year review of LG&E’s environmentalsurcharge.  The review included theoperation of the surcharge mechanism, determination of the appropriateness ofcosts included in the surcharge mechanism, recalculation of the cost of debt toreflect actual costs for the period under review, final determination of theamount of environmental revenues over-collected from customers, and a finaldetermination of the amount of environmental costs and revenues to be“rolled-in” to base rates.  A finalorder was issued in October 2002, in which LG&E was ordered to refund $0.3million to customers over the four month period beginning November 2002 andending February 2003.  Additionally,LG&E was ordered to roll $4.1 million into base rates and makecorresponding adjustments to the monthly environmental surcharge filings toreflect that portion of environmental rate base now included in base ratesgoing forward.

 

In August 2002, LG&E filedan application with the Kentucky Commission to amend its compliance plan toallow recovery of the cost of new and additional environmental compliancefacilities.  The estimated capital costof the additional facilities is $71.1 million. A final order was issued in February 2003.  The final order

 

80

----

 

approved recovery of four newenvironmental compliance facilities totaling $43.1 million.  A fifth project, expansion of the landfillfacility at the Mill Creek Station, was denied without prejudice with aninvitation to reapply for recovery when required construction permits areapproved.  Cost recovery through theenvironmental surcharge of the four approved projects commenced with billsrendered in April 2003.

 

In January 2003, the KentuckyCommission initiated a six-month review of LG&E’s environmentalsurcharge.  A final order was issued inApril 2003, in which LG&E was ordered to refund $2.9 million it hadpreviously over-collected from customers. In July 2003, the Kentucky Commission initiated a two-year review ofLG&E’s environmental surcharge.  Afinal order was issued in December 2003 in which LG&E was ordered to roll$15.2 million of environmental assets into base rates and make correspondingadjustments to the monthly environmental surcharge filings to reflect thatportion of environmental rate base now included in base rates on agoing-forward basis.  Additionally,LG&E was ordered to collect $0.2 million to correct for amountsunder-collected from customers.  Therates of return for LG&E’s 1995 and post-1995 plans were reset to 3.32% and10.92%, respectively.

 

**ESM.**  LG&E’s electric rates are subject to anESM.  The ESM, initially in place forthree years beginning in 2000, sets an upper and lower point for rate of returnon equity, whereby if LG&E’s rate of return for the calendar year fallswithin the range of 10.5% to 12.5%, no action is necessary.  If earnings are above the upper limit, theexcess earnings are shared 40% with ratepayers and 60% with shareholders; ifearnings are below the lower limit, the earnings deficiency is recovered 40%from ratepayers and 60% from shareholders. By order of the Kentucky Commission, rate changes prompted by the ESMfiling go into effect in April of each year subject to a balancing adjustmentin successive periods.

 

In November 2002, LG&Efiled a revised ESM tariff which proposed continuance of the existing ESMthrough December 2005.  In addition, theKentucky Commission initiated a focused management audit to review the ESM planand reassess its reasonableness, and recently concluded discovery in thecase.  LG&E and interested partieshad the opportunity to provide recommendations for modification and continuanceof the ESM or other forms of alternative or incentive regulation.  Continuance of the ESM is still beingdeliberated by the Kentucky Commission and a final order is not expected untilthe second quarter.  The ESM tariff remainsin effect pending the resolution of the case.

 

LG&E made its third ESMfiling in February 2003 for the calendar year 2002 reporting period.  LG&E is in the process of recovering$13.6 million from customers for the 2002 reporting period.  LG&E estimated that the rate of returnwill fall below the lower limit, subject to Kentucky Commission approval, forthe year ended December 31, 2003.  The2003 financial statements include an accrual to reflect the earnings deficiencyof $8.9 million to be recovered from customers commencing in April 2004.

 

**DSM.**  LG&E’s rates contain a DSMprovision.  The provision includes arate mechanism that provides concurrent recovery of DSM costs and provides anincentive for implementing DSM programs. This provision allowed LG&E to recover revenues from lost salesassociated with the DSM programs.  InMay 2001, the Kentucky Commission approved LG&E’s plan to continue DSMprograms.  This plan called for theexpansion of the DSM programs into the service territory served by KU andproposed a mechanism to recover revenues from lost sales associated with DSMprograms based on program plan engineering estimates and post-implementationevaluation.

 

**Gas Supply Cost PBR Mechanism.**  Since November 1, 1997, LG&E hasoperated under an experimental PBR mechanism related to its gas procurementactivities.  For each of the last fiveyears, LG&E’s rates have been adjusted to recover its portion of thesavings (or expenses) incurred during each of the five 12-month periodsbeginning November 1 and ending October 31. Since its implementation onNovember 1, 1997, through

 

81

----

 

October 31, 2003, LG&E hasachieved $51.7 million in savings. Of that total savings amount, LG&E’sportion has been $20.5 million and the ratepayers’ portion has been $31.2million.  Pursuant to the extension ofLG&E gas supply cost PBR mechanism effective November 1, 2001, the sharingmechanism under PBR requires savings (and expenses) to be shared 25% withshareholders and 75% with ratepayers up to 4.5% of the benchmarked gascosts.  Savings (and expenses) in excessof 4.5% of the benchmarked gas costs are shared 50% with shareholders and 50%with ratepayers.  LG&E is obligatedto file a report and assessment with the Kentucky Commission by December 31,2004, seeking an extension or modification of the mechanism.

 

**FAC. **LG&Eemploys an FAC mechanism, which under Kentucky law allows LG&E to recoverfrom customers the actual fuel costs associated with retail electricsales.  In February 1999, LG&Ereceived orders from the Kentucky Commission requiring a refund to retailelectric customers of approximately $3.9 million resulting from reviews of theFAC from November 1994, through April 1998. While legal challenges to the Kentucky Commission order were pending, a comprehensive settlement was reached byall parties and approved by the Kentucky Commission in May 2002.  Thereunder, LG&E agreed to credit itsfuel clause in the amount of $0.7 million (such credit provided over the courseof June and July 2002), and the parties agreed on a prospective interpretationof the state’s FAC regulation to ensure consistent and mutually acceptableapplication going forward.

 

In January 2003, the KentuckyCommission reviewed KU’s FAC for the six-month period ending October 2002 and,as part of the Order in that case, required that an independent audit beconducted to examine operational and management aspects of both KU’s andLG&E’s fuel procurement functions. The final report was issued in February 2004.  The report’s recommendations related to documentation and processimprovements will be addressed with the Kentucky Commission staff as ManagementAudit Action Plans are developed in the second quarter of 2004.

 

The Kentucky Commissionrequires 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.  No significant issueshave been identified as a result of these reviews.

 

**Electric and Gas Rate Cases.**  In December 2003, LG&E filedapplications with the Kentucky Commission requesting adjustments in LG&E’selectric and gas rates.  LG&E askedfor general adjustments in electric and gas rates based on the twelve monthtest year ended September 30, 2003.  Therevenue increases requested were $63.8 million for electric and $19.1 millionfor gas.  The Kentucky Commission hassuspended the effective date of the proposed new tariffs for five months, sothat the rates may go into effect subject to refund by July 1, 2004.  The Kentucky Commission established aprocedural schedule for the cases pertaining to discovery and hearings.  Hearings will be held in May 2004.  LG&E expects the Kentucky Commission toissue orders in the cases before new rates go into effect July 1, 2004.

 

**Wholesale Natural Gas Prices. **On September 12,2000, the Kentucky Commission issued an order establishing Administrative CaseNo. 384 – “An Investigation of Increasing Wholesale Natural Gas Prices and theImpacts of such Increase on the Retail Customers Served by Kentucky’sJurisdictional Natural Gas Distribution Companies”.

 

Subsequent to thisinvestigation, the Kentucky Commission issued an order on July 17, 2001, encouragingthe natural gas distribution companies in Kentucky to take various actions,among them to propose a natural gas hedge plan, consider performance-basedratemaking mechanisms, and to increase the use of storage.

 

In April 2003, in Case No.2003-00149, LG&E proposed a hedge plan for the 2003/2004 winter heatingseason with two alternatives, the first relying upon LG&E’s storage and thesecond relying upon a combination of

 

82

----

 

LG&E’s storage and financialhedge instruments.  In July 2003, theKentucky Commission approved LG&E’s first alternative which relies uponstorage to mitigate the price volatility to which customers might otherwise beexposed.  The Kentucky Commissionvalidated the effectiveness of storage to mitigate potential volatilityassociated with high winter gas prices by approving this natural gas hedgeplan.

 

**Kentucky Commission Administrative Case forAffiliate Transactions.**  In December 1997, the Kentucky Commission opened AdministrativeCase No. 369 to consider Kentucky Commission policy regarding cost allocations,affiliate transactions and codes of conduct governing the relationship betweenutilities and their non-utility operations and affiliates.  The Kentucky Commission intended to addresstwo major areas in the proceedings: the tools and conditions needed to preventcost shifting and cross-subsidization between regulated and non-utilityoperations; and whether a code of conduct should be established to assure thatnon-utility segments of the holding company are not engaged in practices thatcould result in unfair competition caused by cost shifting from the non-utilityaffiliate to the utility.  In early2000, the  Kentucky General Assemblyenacted legislation, House Bill 897, which authorized the Kentucky Commissionto require utilities that provide nonregulated activities to keep separateaccounts and allocate costs in accordance with procedures established by theKentucky Commission.  In the same bill,the General Assembly set forth provisions to govern a utility’s activitiesrelated to the sharing of information, databases, and resources between itsemployees or an affiliate involved in the marketing or the provision ofnonregulated activities and its employees or an affiliate involved in theprovision of regulated services. The legislation became law in July 2000 andLG&E has been operating pursuant thereto since that time.  In February 2001, the Kentucky Commissionpublished notice of its intent to promulgate new administrative regulationsunder the auspices of this new law. This effort is still on-going.

 

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

 

Regarding the transmissionsystem, the Kentucky Commission concluded that the transmission system withinKentucky can reliably serve native load and a significant portion of theproposed new unregulated power plants. However, it will not be able to handle the volume of transactionsenvisioned by FERC without future upgrades, the costs of which should be borneby those for whom the upgrades are required.

 

The Kentucky Commission pledgedto continue to monitor all relevant issues and advocate Kentucky’s interests atall opportunities.

 

**FERC SMD NOPR. **On July 31, 2002, FERC issued a NOPR inDocket No. RM01-12-000 which would substantially alter the regulationsgoverning the nation’s wholesale electricity markets by establishing a commonset of rules, defined as SMD. The SMD NOPR would require each public utilitythat owns, operates, or controls interstate transmission facilities to becomean Independent Transmission Provider (ITP), belong to an RTO that is an ITP, orcontract with an ITP for operation of its transmission assets. It would alsoestablish a standardized congestion management system, real-time and day-aheadenergy markets, and a single transmission

 

83

----

 

service for network andpoint-to-point transmission customers. Review of the proposed rulemaking isunderway and no timeframe has been established by the FERC for adoption of afinal rule.  While it is expected thatthe SMD final rule will affect LG&E revenues and expenses, the specificimpact of the rulemaking is not known at this time.

 

**MISO.**  LG&E and KU are founding members of theMISO.  Membership was obtained in 1998in response to and consistent with federal policy initiatives.  In February 2002, LG&E and KU turnedover operational control of their high voltage transmission facilities (100kVand above) to the MISO.  The MISOcurrently controls over 100,000 miles of transmission over 1.1 million squaremiles located in the northern Midwest between Manitoba, Canada andKentucky.  In September 2002, FERCgranted a 12.88% ROE on transmission facilities for LG&E, KU and the restof the MISO owners.

 

In October 2001, the FERCissued an order requiring that the bundled retail load and grandfatheredwholesale load of each member transmission owner be included in the currentcalculation of the MISO’s “cost-adder,” the Schedule 10 charges designed torecover the MISO’s costs of operation, including start-up capital (debt)costs.  LG&E and KU, along withseveral other transmission owners, opposed the FERC’s ruling on this matter.The opposition was rejected by the FERC in 2002.  Later that year, the MISO’s transmission owners, appealed theFERC’s decision to the United States Court of Appeals for the District ofColumbia Circuit.  In response inNovember 2002, the FERC requested that the Court issue a partial remand of itschallenged orders to allow the FERC to revisit certain issues, and requestedthat the case be held in abeyance pending the agency’s resolution of suchissues.  The Court granted the FERC’s petitionin December 2002.  In February 2003,FERC issued an order reaffirming its position concerning the calculation of theSchedule 10 charges and in July 2003 denied a rehearing.  LG&E and KU, along with several othertransmission owners, have again petitioned the District Court of ColumbiaCircuit for review.  This case iscurrently pending.

 

As a separate matter, MISO, itstransmission owners and other interested industry segments reached a settlementin mid-2002 regarding the level**of cost responsibility properly borne bybundled and grandfathered load under these FERC rulings (such settlementexpressly not prejudicing the transmission owners’ and LG&E’s right tochallenge the FERC’s ruling imposing cost responsibility on bundled loads inthe first instance).  In February 2003,FERC accepted a partial settlement between MISO and the transmissionowners.  FERC did not accept the onlycontested section of the settlement, which would have allowed the transmissionowners to immediately treat unrecoverable Schedule 10 charges as regulatoryassets.  FERC will consider allowingregulatory asset treatment of unrecoverable Schedule 10 charges on acase-by-case basis.

 

The MISO plans to implement acongestion management system in December 2004, in compliance with FERC Order2000.  This system will be similar tothe Locational Marginal Pricing (LMP) system currently used by the PJM RTO andcontemplated in FERC’s SMD NOPR, currently being discussed.  The MISO filed with FERC a mechanism forrecovery of costs for the congestion management system.  They proposed the addition of two newSchedules, 16 and 17.  Schedule 16 isthe MISO’s cost recovery mechanism for the Financial Transmission RightsAdministrative Service it will provide. Schedule 17 is the MISO’s mechanism for recovering costs it will incurfor providing Energy Marketing Support Administrative Service.  The MISO transmission owners, includingLG&E and KU, have objected to the allocation of costs among market participantsand retail native load.  A hearing atFERC has been completed, but a ruling has not been issued.

 

The Kentucky Commission openedan investigation into LG&E’s and KU’s membership in MISO in July 2003.  The Kentucky Commission directed LG&Eand KU to file testimony addressing the costs and benefits of MISO membershipboth currently and over the next five years and other legal issues surroundingcontinued membership.  LG&E and KUengaged an independent third-party to conduct a cost benefit analysis on thisissue. The information was filed with the Kentucky Commission in September2003.  The analysis and

 

84

----

 

testimony supported the exitfrom MISO, under certain conditions. The MISO filed its own testimony and cost benefit analysis in December2003.  A final Kentucky Commission orderis expected in the second quarter of 2004.

 

**ARO.**  In 2003, LG&E recorded $6.0 million inregulatory assets and $0.1 million in regulatory liabilities related to SFASNo. 143, *Accountingfor Asset Retirement Obligations*.

 

**Accumulated Cost of Removal. **As of December 31,2003 and 2002, LG&E has segregated the cost of removal, embedded inaccumulated depreciation, of $223.6 million and $207.9 million, respectively,in accordance with FERC Order No. 631. For reporting purposes in the Consolidated Balance Sheets, LG&E haspresented this cost of removal as a regulatory liability pursuant to SFAS No.71.

 

**Merger Surcredit.**  As part of the LG&E Energy merger withKU Energy in 1998, LG&E Energy estimated non-fuel savings over a ten-yearperiod following the merger.  Costs toachieve these savings for LG&E of $50.2 million were recorded in the secondquarter of 1998, $18.1 million of which was deferred and amortized over afive-year period pursuant to regulatory orders.  Primary components of the merger costs were separation benefits,relocation costs, and transaction fees, the majority of which were paid byDecember 31, 1998.  LG&E expensedthe remaining costs associated with the merger ($32.1 million) in the secondquarter of 1998.

 

In approving the merger, theKentucky Commission adopted LG&E’s proposal to reduce its retail customers’bills based on one-half of the estimated merger-related savings, net ofdeferred and amortized amounts, 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 KU and 47% to LG&E.  In that same order, the Commission requiredLG&E and KU, after the end of the five-year period, to present a plan forsharing with ratepayers the then-projected non-fuel savings associated with themerger.  The Companies submitted thisfiling in January 2003, proposing to continue to share with ratepayers, on a50%/50% basis, the estimated fifth-year gross level of non-fuel savingsassociated with the merger.  In October2003, the Kentucky Commission issued an order approving a settlement agreementreached with the parties in the case. LG&E’s merger surcredit will remain in place for another five-yearterm beginning July 1, 2003 and the merger savings will continue to be shared50% with ratepayers and 50% with shareholders.

 

Any fuel cost savings arepassed to Kentucky customers through the fuel adjustment clause.  See FAC above.

 

**Note 4 - Financial Instruments**

 

The cost and estimated fairvalues of LG&E’s non-trading financial instruments as of December 31, 2003,and 2002 follow:

 
|                                             |   | **2003** |   | **2002**        |       |
|--------------------------------------------------|--------|----------|--------|-----------------|------------|
| **(in thousands)**                               |   | **Cost** |   | **Fair  Value** | ** ** | **Cost** | ** ** | **Fair  Value** | ** ** |
| Preferred stock subject to mandatory  redemption |   | $        | 23,750 |            | $          | 23,893 |   | $ | 25,000 |   | $ | 25,188 |   |
| Long-term debt (including current portion)       |   | 574,304  |   | 576,174         |       | 616,904 |   | 623,325 |   |
| Long-term debt from Fidelia                      |   | 200,000  |   | 206,333         |       | — |   | — |   |
| Interest-rate swaps                              |   | —   |   | (15,966         | )          | — |   | (17,115 | ) |
|                                                  |        |          |        |                 |            |  |  |  |  |  |  |  |  |

 

All of the above valuationsreflect prices quoted by exchanges except for the swaps and intercompany loans.The

 

85

----

fair values of the swaps and intercompany loans reflect price quotesfrom dealers or amounts calculated using accepted pricing models.

 

**InterestRate Swaps.**  LG&Euses interest rate swaps to hedge exposure to market fluctuations in certain ofits debt instruments.  Pursuant topolicy, use of these financial instruments is intended to mitigate risk andearnings volatility and is not speculative in nature.  Management has designated all of the interest rate swaps as hedgeinstruments.  Financial instruments designatedas cash flow hedges have resulting gains and losses recorded within othercomprehensive income and stockholders’ equity. To the extent a financial instrument or the underlying item being hedgedis prematurely terminated or the hedge becomes ineffective, the resulting gainsor losses are reclassified from other comprehensive income to net income.

 

As of December 31, 2003 and 2002, LG&E was party to variousinterest rate swap agreements with aggregate notional amounts of $228.3 millionand $117.3 million, respectively.  Underthese swap agreements, LG&E paid fixed rates averaging 4.38% and 5.13% andreceived variable rates based on LIBOR or the Bond Market Association’smunicipal swap index averaging 1.11% and 1.52% at December 31, 2003 and2002, respectively. The swap agreements in effect at December 31, 2003have been designated as cash flow hedges and mature on dates ranging from 2005to 2033.  The hedges have been deemed tobe fully effective resulting in a pretax gain of $1.1 million for 2003, recordedin other comprehensive income.  Uponexpiration of these hedges, the amount recorded in other comprehensive incomewill be reclassified into earnings.  Theamounts expected to be reclassified from other comprehensive income to earningsin the next twelve months is immaterial.

 

# **EnergyTrading & Risk Management Activities. **LG&E conducts energy trading and risk management activities tomaximize the value of power sales from physical assets it owns, in addition tothe wholesale sale of excess asset capacity. Certain energy trading activities are accounted for on a mark-to-marketbasis in accordance with SFAS No. 133*, Accounting for Derivative Instruments and HedgingActivities,* and SFAS No. 138*, Accounting for Certain Derivative Instruments andCertain Hedging Activities*. Wholesale sales of excess asset capacity and wholesale purchases aretreated as normal sales and purchases under SFAS No. 133 and SFAS No. 138 andare not marked to market.

# ** **

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

 

The table belowsummarizes LG&E’s energy trading and risk management activities for 2003and 2002.

 
| **(in thousands)**                                             |   | **2003** |   | **2002** |   |
|----------------------------------------------------------------|--------|----------|--------|----------|--------|
| Fair value of contracts at beginning of period, net  liability |   | $        | (156   | )        | $      | (186 | ) |
| Fair value of contracts when entered into during  the period   |   | 2,654    |   | (65      | )      |
| Contracts realized or otherwise settled during the  period     |   | (569     | )      | 448      |   |
| Changes in fair values due to changes in assumptions           |   | (1,357   | )      | (353     | )      |
| Fair value of contracts at end of period, net  liability       |   | $        | 572    |     | $      | (156 | ) |

 

No changes to valuationtechniques for energy trading and risk management activities occurred during2003.  Changes in market pricing,interest rate and volatility assumptions were made during both years.  All contracts outstanding atDecember 31, 2003, have a maturity of less than one year and are valued usingprices actively quoted for proposed or executed transactions or quoted bybrokers.

 

LG&E maintains policies intended to minimize credit risk andrevalues credit exposures daily to monitor compliance with those policies.  At December 31, 2003, 100% of thetrading and risk management commitments were with counterparties ratedBBB-/Baa3 equivalent or better.

 

86

----

 

LG&E hedges the price volatility of its forecasted peak electricoff-system sales with the sale of market-traded electric forward contracts forperiods less than one year.  Theseelectric forward sales have been designated as cashflow hedges and are notspeculative in nature.  Gains or losseson these instruments, to the extent that the hedging relationship has beeneffective, are deferred in other comprehensive income.  Gains and losses resulting fromineffectiveness are shown in LG&E’s Consolidated Statements of Income inother income (expense) – net.  Uponexpiration of these instruments, the amount recorded in other comprehensiveincome is recorded in earnings.  In2003, LG&E recognized a pre-tax loss of approximately $18,000, and a loss,net of tax, deferred in other comprehensive income of approximately $147,000.

 

**Accounts ReceivableSecuritization. **OnFebruary 6, 2001, LG&E implemented an accounts receivablesecuritization program.  The purpose ofthis program was to enable LG&E to accelerate the receipt of cash from thecollection of retail accounts receivable, thereby reducing dependence upon morecostly sources of working capital.  Thesecuritization program allowed for a percentage of eligible receivables to besold.  Eligible receivables weregenerally all receivables associated with retail sales that have standard termsand are not past due.  LG&E was ableto terminate the program at any time without penalty.

 

LG&E terminated the accounts receivable securitization program inJanuary 2004 and replaced it with long-term intercompany loans from anE.ON affiliate.  The accounts receivableprogram required LG&E R to maintain minimum levels of net worth.  The program also contained a cross-defaultprovision if LG&E defaulted on debt obligations in excess of $25 million.  If there was a significant deterioration inthe payment record of the receivables by the retail customers or if LG&Efailed to meet certain covenants regarding the program, the program couldterminate at the election of the financial institutions.  In this case, payments from retail customerswould first be used to repay the financial institutions participating in theprogram, and would then be available for use by LG&E.  LG&E did not violate any covenants withregard to the accounts receivable securitization program.

 

As part of the program, LG&E sold retail accounts receivables to awholly owned subsidiary, LG&E R. Simultaneously, LG&E R entered into two separate three-year accountsreceivable securitization facilities with two financial institutions and theiraffiliates whereby LG&E R could sell, on a revolving basis, an undividedinterest in certain of its receivables and receive up to $75 million from anunrelated third-party purchaser.  Theeffective cost of the receivables program was comparable to LG&E’s lowestcost source of capital, and was based on prime rated commercial paper. LG&Eretained servicing rights of the sold receivables through two separateservicing agreements with the third-party purchaser.  LG&E obtained an opinion from independent legal counselindicating these transactions qualified as a true sale of receivables.  As of December 31, 2003, theoutstanding program balance was $58.0 million.

 

To determine LG&E’s retained interest, the proceeds on the sale ofreceivables to the financial institutions was netted against the amount ofeligible receivables sold by LG&E to LG&E R.  Interest expense, program fees, and facility fees paid to thefinancial institutions and an allowance for doubtful accounts were deducted toarrive at the future value of retained interest.  The future value was discounted using the prime rate plus 25basis points, assuming a 45-day receivable life.  Pre-tax gains and losses from the sale of the receivables in2003, 2002 and 2001 were gains of $20,648, $46,727 and a loss of $206,578,respectively.  LG&E’s net cash flowsfrom LG&E R were $(6.2) million, $20.2 million and $39.7 million for 2003,2002 and 2001, respectively.

 

The allowance for doubtful accounts associated with the eligiblesecuritized receivables at December 31 was $1.4 million, $1.9 million and$1.3 million in 2003, 2002 and 2001, respectively.  This allowance was based on historical experience of LG&E.Each securitization facility contained a fully funded reserve for uncollectiblereceivables.

 

87

----

 

**Note 5 -Concentrations of Credit and Other Risk**

 

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

 

LG&E’s customer receivables and gas and electric revenues arisefrom deliveries of natural gas to approximately 312,000 customers andelectricity to approximately 384,000 customers in Louisville and adjacent areasin Kentucky.  For the year endedDecember 31, 2003, 70% of total revenue was derived from electricoperations and 30% from gas operations.

 

In November 2001, LG&E and IBEW Local 2100 employees, whichrepresent approximately 70% of LG&E’s workforce, entered into a four-yearcollective bargaining agreement and completed wage and benefit re-openernegotiations in October 2003.

 

**Note 6 - Pension andOther Post Retirement Benefit 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 31 as the measurement date for its plans.

 

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

 
| **(in thousands)**                             |   | **2003** |     | **2002** |   | **2001** |   |
|------------------------------------------------|--------|----------|----------|----------|--------|----------|--------|
| Pension Plans:                                 |   |     |     |     |   |     |   |
| Change in benefit obligation                   |   |     |     |     |   |     |   |
| Benefit obligation at beginning of year        |   | $        | 364,794  |     | $      | 356,293  |   | $ | 310,822 |   |
| Service cost                                   |   | 1,757    |     | 1,484    |   | 1,311    |   |
| Interest cost                                  |   | 23,190   |     | 24,512   |   | 25,361   |   |
| Plan amendments                                |   | 3,978    |     | 576      |   | 1,550    |   |
| Change due to transfers                        |   | (2,759   | )        | —   |   | —   |   |
| Curtailment loss                               |   | —   |     | —   |   | 24,563   |   |
| Special termination benefits                   |   | —   |     | —   |   | 53,610   |   |
| Benefits and lump sums paid                    |   | (33,539  | )        | (34,823  | )      | (53,292  | )      |
| Actuarial (gain) or loss and other             |   | 21,270   |     | 16,752   |   | (7,632   | )      |
| Benefit obligation at end of year              |   | $        | 378,691  |     | $      | 364,794  |   | $ | 356,293 |   |
|                                           |   |     |     |     |   |     |   |
| Change in plan assets                          |   |     |     |     |   |     |   |
| Fair value of plan assets at beginning of year |   | $        | 196,314  |     | $      | 233,944  |   | $ | 333,378 |   |
| Actual return on plan assets                   |   | 47,152   |     | (15,648  | )      | (27,589  | )      |
| Employer contributions                         |   | 89,125   |     | 336      |   | 374      |   |
| Changes due to transfers                       |   | 238      |     | 13,814   |   | (17,508  | )      |
| Benefits and lump sums paid                    |   | (33,539  | )        | (34,824  | )      | (53,292  | )      |
| Administrative expenses                        |   | (1,512   | )        | (1,308   | )      | (1,419   | )      |
| Fair value of plan assets at end of year       |   | $        | 297,778  |     | $      | 196,314  |   | $ | 233,944 |   |
|                                           |   |     |     |     |   |     |   |
| Reconciliation of funded status                |   |     |     |     |   |     |   |
| Funded status                                  |   | $        | (80,913  | )        | $      | (168,480 | )      | $ | (122,349 | ) |
| Unrecognized actuarial (gain) or loss          |   | 56,219   |     | 60,313   |   | 18,800   |   |
| Unrecognized transition (asset) or obligation  |   | (2,183   | )        | (3,199   | )      | (4,215   | )      |
| Unrecognized prior service cost                |   | 32,275   |     | 32,265   |   | 35,435   |   |
| Net amount recognized at end of year           |   | $        | 5,398    |     | $      | (79,101  | )      | $ | (72,329 | ) |
|                                           |   |     |     |     |   |     |   |
| Other Benefits:                                |   |     |     |     |   |     |   |
| Change in benefit obligation                   |   |     |     |     |   |     |   |
| Benefit obligation at beginning of year        |   | $        | 93,233   |     | $      | 89,946   |   | $ | 56,981 |   |
| Service cost                                   |   | 604      |     | 444      |   | 358      |   |
| Interest cost                                  |   | 6,872    |     | 5,956    |   | 5,865    |   |
| Plan amendments                                |   | 7,380    |     | —   |   | 1,487    |   |
| Curtailment loss                               |   | —   |     | —   |   | 8,645    |   |
| Special termination benefits                   |   | —   |     | —   |   | 18,089   |   |
| Benefits and lump sums paid                    |   | (9,313   | )        | (4,988   | )      | (4,877   | )      |
| Actuarial (gain) or loss                       |   | 9,254    |     | 1,875    |   | 3,398    |   |
| Benefit obligation at end of year              |   | $        | 108,030  |     | $      | 93,233   |   | $ | 89,946 |   |
|                                           |   |     |     |     |   |     |   |
| Change in plan assets                          |   |     |     |     |   |     |   |
| Fair value of plan assets at beginning of year |   | $        | 1,478    |     | $      | 2,802    |   | $ | 7,166 |   |
| Actual return on plan  assets                  |   | 2,076    |     | (533     | )      | (765     | )      |
| Employer contributions                         |   | 6,401    |     | 4,213    |   | 1,470    |   |
| Changes due to transfers                       |   | —   |     | —   |   | (188     | )      |
| Benefits and lump sums paid                    |   | (9,281   | )        | (5,004   | )      | (4,881   | )      |
| Fair value of plan assets at end of year       |   | $        | 674      |     | $      | 1,478    |   | $ | 2,802 |   |
|                                           |   |     |     |     |   |     |   |
| Reconciliation of funded status                |   |     |     |     |   |     |   |
| Funded status                                  |   | $        | (107,356 | )        | $      | (91,755  | )      | $ | (87,144 | ) |
| Unrecognized actuarial (gain) or loss          |   | 23,724   |     | 16,971   |   | 15,947   |   |
| Unrecognized transition (asset) or obligation  |   | 6,027    |     | 6,697    |   | 7,346    |   |
| Unrecognized prior service cost                |   | 11,482   |     | 5,995    |   | 5,302    |   |
| Net amount recognized at end of year           |   | $        | (66,123  | )        | $      | (62,092  | )      | $ | (58,549 | ) |

 

88

----

 

**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, 2003, 2002 and2001:

 
| **(in thousands)**                                                                                         |   | **2003** |    | **2002** |   | **2001** |   |
|------------------------------------------------------------------------------------------------------------|--------|----------|---------|----------|--------|----------|--------|
|                                                                                                       |   |     |    |     |   |     |   |
| Pension Plans:                                                                                             |   |     |    |     |   |     |   |
| Amounts recognized in the balance sheet consisted  of:                                                     |   |     |    |     |   |     |   |
| Prepaid benefits cost                                                                                      |   | $        | —  |     | $      | —   |   | $ | — |   |
| Accrued benefit liability                                                                                  |   | (74,474  | )       | (162,611 | )      | (108,977 | )      |
| Intangible asset                                                                                           |   | 32,275   |    | 32,799   |   | 11,936   |   |
| Accumulated other comprehensive income                                                                     |   | 47,597   |    | 50,711   |   | 24,712   |   |
| Net amount recognized at year-end                                                                          |   | $        | 5,398   |     | $      | (79,101  | )      | $ | (72,329 | ) |
|                                                                                                       |   |     |    |     |   |     |   |
| Additional year-end  information for plans with accumulated benefit obligations in excess of  plan assets: |   |     |    |     |   |     |   |
| Projected benefit obligation                                                                               |   | $        | 378,691 |     | $      | 364,794  |   | $ | 356,293 |   |
| Accumulated benefit obligation                                                                             |   | 372,252  |    | 358,956  |   | 352,477  |   |
| Fair value of plan assets                                                                                  |   | 297,778  |    | 196,314  |   | 233,944  |   |
|                                                                                                       |   |     |    |     |   |     |   |
| Other Benefits:                                                                                            |   |     |    |     |   |     |   |
| Amounts recognized in the balance sheet consisted  of:                                                     |   |     |    |     |   |     |   |
| Accrued benefit liability                                                                                  |   | $        | (66,123 | )        | $      | (62,092  | )      | $ | (58,549 | ) |
| Additional year-end information for plans with  benefit obligations in excess of plan assets:              |   |     |    |     |   |     |   |
| Projected benefit obligation                                                                               |   | $        | 108,030 |     | $      | 93,233   |   | $ | 89,946 |   |
| Fair value of plan assets                                                                                  |   | 674      |    | 1,478    |   | 2,802    |   |
|                                                                                                       |   |     |    |     |   |     |   |
| Increase (decrease) in minimum liability included  in other comprehensive income                           |   | $        | (3,114  | )        | $      | 25,999   |   | $ | 24,712 |   |

 

89

----

 

**Components of Net Periodic Benefit Cost. **The following tableprovides the components of net periodic benefit cost for the plans for 2003,2002 and 2001:

 
| **(in thousands)**                                |   | **2003** |   | **2002** |   | **2001** |   |
|---------------------------------------------------|--------|----------|--------|----------|--------|----------|--------|
| Pension Plans:                                    |   |     |   |     |   |     |   |
| Components of net periodic benefit cost           |   |     |   |     |   |     |   |
| Service cost                                      |   | $        | 1,756  |     | $      | 1,484    |   | $ | 1,311 |   |
| Interest cost                                     |   | 23,190   |   | 24,512   |   | 25,361   |   |
| Expected return on plan assets                    |   | (22,785  | )      | (21,639  | )      | (26,360  | )      |
| Amortization of prior service cost                |   | 3,792    |   | 3,777    |   | 3,861    |   |
| Amortization of transition  (asset) or obligation |   | (1,016   | )      | (1,016   | )      | (1,000   | )      |
| Recognized actuarial (gain) or loss               |   | 2,219    |   | 21       |   | (777     | )      |
| Net periodic benefit cost                         |   | $        | 7,156  |     | $      | 7,139    |   | $ | 2,396 |   |
|                                              |   |     |   |     |   |     |   |
| Special charges                                   |   |     |   |     |   |     |   |
| Prior service cost recognized                     |   | $        | — |     | $      | —   |   | $ | 10,237 |   |
| Special termination benefits                      |   | —   |   | —   |   | 53,610   |   |
| Settlement loss                                   |   | —   |   | —   |   | (2,244   | )      |
| Total charges                                     |   | $        | — |     | $      | —   |   | $ | 61,603 |   |
|                                              |   |     |   |     |   |     |   |
| Other Benefits:                                   |   |     |   |     |   |     |   |
| Components of net periodic benefit cost           |   |     |   |     |   |     |   |
| Service cost                                      |   | $        | 604    |     | $      | 444      |   | $ | 358 |   |
| Interest cost                                     |   | 6,872    |   | 5,956    |   | 5,865    |   |
| Expected return on plan assets                    |   | (51      | )      | (204     | )      | (420     | )      |
| Amortization of prior service cost                |   | 1,768    |   | 920      |   | 951      |   |
| Amortization of transition (asset) or obligation  |   | 670      |   | 650      |   | 719      |   |
| Recognized actuarial (gain) or loss               |   | 505      |   | 116      |   | (32      | )      |
| Net periodic benefit cost                         |   | $        | 10,368 |     | $      | 7,882    |   | $ | 7,441 |   |
|                                              |   |     |   |     |   |     |   |
| Special charges                                   |   |     |   |     |   |     |   |
| Curtailment loss                                  |   | $        | — |     | $      | —   |   | $ | 6,671 |   |
| Transition obligation recognized                  |   | —   |   | —   |   | 4,743    |   |
| Prior service cost recognized                     |   | —   |   | —   |   | 2,391    |   |
| Special termination benefits                      |   | —   |   | —   |   | 18,089   |   |
| Total charges                                     |   | $        | — |     | $      | —   |   | $ | 31,894 |   |

 

The assumptions used inthe measurement of LG&E’s pension benefit obligation are shown in the followingtable:

 
|                                                  |   | **2003** |   | **2002** |   | **2001** |   |
|-------------------------------------------------------|--------|----------|--------|----------|--------|----------|--------|
| Weighted-average assumptions as of  December 31: |   |     |   |     |   |     |   |
| Discount rate                                         |   | 6.25     | %      | 6.75     | %      | 7.25     | %      |
| Rate of compensation increase                         |   | 3.00     | %      | 3.75     | %      | 4.25     | %      |

 

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

 

90

----

 
|                                     |   | **2003** |   | **2002** |   | **2001** |   |
|------------------------------------------|--------|----------|--------|----------|--------|----------|--------|
| Discount rate                            |   | 6.75     | %      | 7.25     | %      | 7.75     | %      |
| Expected long-term return on plan assets |   | 9.00     | %      | 9.50     | %      | 9.50     | %      |
| Rate of compensation increase            |   | 3.75     | %      | 4.25     | %      | 4.75     | %      |

 

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.  The expected return for each asset class wasthen weighted based on the target asset allocation to develop the expectedlong-term rate of return on assets assumption for the portfolio.

 

**Assumed Healthcare Cost Trend Rates. **For measurementpurposes, a 12.0% annual increase in the per capita cost of covered healthcarebenefits was assumed for 2004.  The ratewas assumed to decrease gradually to 5.0% by 2015 and remain at that levelthereafter.

 

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

 
| **(in thousands)**                                                |   | **1%  Decrease** |   | **1%  Increase** |   |
|-------------------------------------------------------------------|--------|------------------|--------|------------------|--------|
|                                                              |   |             |   |             |   |
| Effect on total of service and interest  cost components for 2003 |   | $                | (276   | )                | $      | 313 |   |
| Effect on year-end 2003 postretirement  benefit obligations       |   | $                | (3,482 | )                | $      | 3,875 |   |

 

**Plan Assets. **The following table shows LG&E’sweighted-average asset allocation by asset category at December 31:

 
|              |   | **2003** |   | **2002** |   | **2001** |   |
|-------------------|--------|----------|--------|----------|--------|----------|--------|
| Pension Plans:    |   |     |   |     |   |     |   |
| Equity securities |   | 66       | %      | 64       | %      | 70       | %      |
| Debt securities   |   | 33       |   | 34       |   | 28       |   |
| Other             |   | 1        |   | 2        |   | 2        |   |
| Totals            |   | 100      | %      | 100      | %      | 100      | %      |
|              |   |     |   |     |   |     |   |
| Other Benefits:   |   |     |   |     |   |     |   |
| Equity securities |   | 0        | %      | 0        | %      | 97       | %      |
| Debt securities   |   | 100      |   | 100      |   | 3        |   |
| Totals            |   | 100      | %      | 100      | %      | 100      | %      |

 

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

 

**Thefund focuses on a long-term investment time horizon of at least three to fiveyears or a complete market cycle.  Theassets of the pension plans are broadly diversified within different assetclasses (equities, fixed income securities and cash equivalents).**

** **

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

 

91

----

 

In addition, theoverall fixed income portfolio holdings have a maximum average weightedmaturity of no more than fifteen (15) years, with the weighted average durationof the portfolio being no more than eight (8) years.  All securities must be rated “investment grade” or better andforeign bonds in the aggregate shall not exceed 10% of the total fund.  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 or to reduce transaction costs and must be used inconjunction with underlying physical assets in the portfolio. Derivativesecurities that involve speculation, leverage, interest rate anticipation, orany undue risk whatsoever are not deemed appropriate investments.

 

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

 

**Contributions. **LG&E made a discretionarycontribution to the pension plan of $34.5 million in January 2004. Nofurther discretionary contributions are planned and no contributions arerequired for 2004.

 

**Thrift Savings Plans.**  LG&E has a thrift savings plan undersection 401(k) of the Internal Revenue Code.  Under the plan, eligible employees may defer and contribute tothe plan a portion of current compensation in order to provide futureretirement benefits. LG&E makes contributions to the plan by matching aportion of the employee contributions. The costs of this matching were approximately $1.8 million for 2003,$1.7 million for 2002 and $1.2 million for 2001.

 

**Note 7 - Income Taxes**

 

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

 
| **(in thousands)**                    |                 | **2003** |   | **2002** |   | **2001** |   |
|---------------------------------------|----------------------|----------|--------|----------|--------|----------|--------|
|                                  |                 |     |   |     |   |     |   |
| Included in operating expenses:       |                 |     |   |     |   |     |   |
| Current                               | - federal            |     | $      | 30,598   |   | $        | 26,231 |   | $ | 42,997 |   |
|                                  | - state              |     | 11,007 |     | 8,083  |     | 8,668  |   |
| Deferred                              | - federal – net |     | 16,922 |     | 20,464 |     | 12,310 |   |
|                                  | - state – net   |     | 1,746  |     | 4,410  |     | 3,767  |   |
| Amortization of investment tax credit |                 | (4,207   | )      | (4,153   | )      | (4,290   | )      |
| Total                                 |                 | 56,066   |   | 55,035   |   | 63,452   |   |
|                                  |                 |     |   |     |   |     |   |   |
| Included in other income - net:       |                 |     |   |     |   |     |   |
| Current                               | - federal            |     | (4,830 | )        | (1,667 | )        | (1,870 | ) |
|                                  | - state              |     | (1,004 | )        | (430   | )        | (483   | ) |
| Deferred                              | - federal – net |     | (129   | )        | (206   | )        | 285    |   |
|                                  | - state – net   |     | (30    | )        | (53    | )        | 73     |   |
| Total                                 |                 | (5,993   | )      | (2,356   | )      | (1,995   | )      |
|                                  |                 |     |   |     |   |     |   |
| Total income tax expense              |                 | $        | 50,073 |     | $      | 52,679   |   | $ | 61,457 |   |

 

Components of net deferred tax liabilities included in the balancesheet are shown below (in thousands of $):

 

92

----

 
|                                                    |   | **2003** |    | **2002** |   |
|---------------------------------------------------------|--------|----------|---------|----------|--------|
| Deferred tax liabilities:                               |   |     |    |     |   |
| Depreciation and other plant-related items              |   | $        | 365,460 |     | $      | 346,737 |   |
| Other liabilities                                       |   | 52,976   |    | 64,734   |   |
|                                                    |   | 418,436  |    | 411,471  |   |
| Deferred tax assets:                                    |   |     |    |     |   |
| Investment tax credit                                   |   | 20,314   |    | 22,012   |   |
| Income taxes due to customers                           |   | 16,620   |    | 18,431   |   |
| Pensions                                                |   | 5,345    |    | 21,056   |   |
| Accrued liabilities not currently  deductible and other |   | 38,453   |    | 36,747   |   |
|                                                    |   | 80,732   |    | 98,246   |   |
|                                                    |   |     |    |     |   |
| Net deferred income tax liability                       |   | $        | 337,704 |     | $      | 313,225 |   |

 

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

 
|                                       |   | **2003** |   | **2002** |   | **2001** |   |
|--------------------------------------------|--------|----------|--------|----------|--------|----------|--------|
|                                       |   |     |   |     |   |     |   |
| Statutory federal income tax rate          |   | 35.0     | %      | 35.0     | %      | 35.0     | %      |
| State income taxes, net of federal benefit |   | 5.4      |   | 5.6      |   | 4.7      |   |
| Amortization of investment tax credit      |   | (3.0     | )      | (2.9     | )      | (2.6     | )      |
| Other differences – net               |   | (1.9     | )      | (0.5     | )      | (0.6     | )      |
| Effective income tax rate                  |   | 35.5     | %      | 37.2     | %      | 36.5     | %      |

 

The decrease in the effective rate in 2003 compared to 2002 relates tothe recognition of tax benefits for prior year audit settlements and excessdeferred tax adjustments.

 

# **Note8 - Other Income (Expense) - Net**

# ** **

Other income (expense) - net consisted of the following atDecember 31:

 
| **(in thousands)**                     |   | **2003** |   | **2002** |   | **2001** |   |
|----------------------------------------|--------|----------|--------|----------|--------|----------|--------|
|                                   |   |     |   |     |   |     |   |
| Interest and dividend income (expense) |   | $        | (1,254 | )        | $      | 554      |   | $ | 856 |   |
| Income and other taxes                 |   | 5,943    |   | 2,305    |   | 1,945    |   |
| Other                                  |   | (5,894   | )      | (2,044   | )      | 129      |   |
|                                   |   | $        | (1,205 | )        | $      | 815      |   | $ | 2,930 |   |

 

**Note 9 - Long-TermDebt**

 

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

 

Long-term debt and the current portion of long-term debt consistsprimarily of first mortgage bonds, pollution control bonds, and long-term loansfrom affiliated companies as summarized below (in thousands of $).  Interest rates and maturities in the tablebelow are for the amounts outstanding at December 31, 2003 and reflect theimpact of interest rate swaps.

 
|               |   | **Stated  Interest Rates** |   | **Weighted  Average  Interest  Rate** |   | **Maturities** |   | **Principal  Amounts** |    |
|--------------------|--------|----------------------------|--------|---------------------------------------|--------|----------------|--------|------------------------|---------|
|               |   |                       |   |                                  |   |           |   |                   |    |
| Noncurrent portion |   | Variable - 5.90            | %      | 4.23                                  | %      | 2027-2033      |   | $                      | 528,104 |   |
| Current portion    |   | Variable                   |   | 1.46                                  | %      | 2017-2027      |   | 246,200                |    |
|                    |        |                            |        |                                       |        |                |        |                        |         |  |

 

93

----

 

Under the provisions for LG&E’s variable-rate pollution controlbonds, Series S, T, U, BB, CC, DD and EE, the bonds are subject to tender forpurchase at the option of the holder and to mandatory tender for purchase uponthe occurrence of certain events, causing the bonds to be classified as currentportion of long-term debt in the Consolidated Balance Sheets.  The average annualized interest rate forthese bonds during 2003 was 1.10%.

 

Interest rate swaps are used to hedge LG&E’s underlyingvariable-rate debt obligations.  Theseswaps hedge specific debt issuances and, consistent with management’sdesignation, are accorded hedge accounting treatment.  As of December 31, 2003, LG&E had swaps with a combinednotional value of $228.3 million.  Theswaps exchange floating-rate interest payments for fixed rate interest paymentsto reduce the impact of interest rate changes on LG&E’s pollution controlbonds.  See Note 4.

 

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

 

LG&E’s first mortgage bond, 6% Series of $42.6 million, matured in2003.

 

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

 

In March 2002, LG&E refinanced four unsecured pollutioncontrol bonds with an aggregate principal balance of $120 million and replacedthem with secured pollution control bonds. The new bonds and the previous bonds were all variable-rate bonds, andthe maturity dates remained unchanged.

 

Annual requirements for the sinking funds of LG&E’s first mortgagebonds (other than the first mortgage bonds issued in connection with certainpollution control bonds) are the amounts necessary to redeem 1% of the highestprincipal amount of each series of bonds at any time outstanding.  Property additions (166 2/3% of principalamounts of bonds otherwise required to be so redeemed) have been applied inlieu of cash such that the sinking fund requirements are fully met.

 

Substantially all of LG&E’s utility plant is pledged as securityfor its first mortgage bonds. LG&E’s first mortgage bond indenture, as supplemented, provides thatportions of retained earnings will not be available for the payment ofdividends on common stock, under certain specified conditions.  LG&E has not violated any of these conditionsthat would cause any portion of retained earnings to be restricted by thisprovision.

 

During 2003, LG&E entered into two long-term loans from anaffiliated company totaling $200 million. Of this total, $100 million is unsecured with an interest rate of 4.55%and matures in April 2013.  Theremaining $100 million is secured by a lien subordinated to the first mortgagebond lien, has an interest rate of 5.31% and matures in August 2013.  The second lien applies to substantially allutility assets of LG&E.

 

LG&E has existing $5.875 series mandatorily redeemable preferredstock outstanding having a current redemption price of $100 per share. Thepreferred stock has a sinking fund requirement sufficient to retire a minimumof 12,500 shares on July 15 of each year commencing with July 15,2003, and the remaining 187,500 shares on July 15, 2008 at $100 pershare.  LG&E redeemed 12,500 sharesin accordance with these provisions on July 15, 2003, leaving 237,500shares 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.

 

The following table reflects the long-term debt maturities:

 

94

----

 
| **(in thousands)**                     |   | **2004** |    | **2005** |   | **2006** |   | **2007** |   | **2008** |   | **Thereafter** |   | **Total** |   |
|----------------------------------------|--------|----------|---------|----------|--------|----------|--------|----------|--------|----------|--------|----------------|--------|-----------|--------|
|                                   |   |     |    |     |   |     |   |     |   |     |   |           |   |      |   |
| Pollution control bonds                |   | $        | 246,200 | (1)      | $      | —   |   | $        | — |     | $      | —         |   | $         | — |   | $ | 328,104 |   | $ | 574,304 |   |
| Notes payable to Fidelia               |   | —   |    | —   |   | —   |   | —   |   | —   |   | 200,000        |   | 200,000   |   |
| Mandatorily redeemable preferred stock |   | 1,250    |    | 1,250    |   | 1,250    |   | 1,250    |   | 18,750   |   | —         |   | 23,750    |   |
|                                   |   | $        | 247,450 |     | $      | 1,250    |   | $        | 1,250  |     | $      | 1,250          |   | $         | 18,750 |   | $ | 528,104 |   | $ | 798,054 |   |

 

----

(1)          Includes $246,200 of bonds with put provisionsthat allow the holders to sell bonds back to LG&E at a specific pricebefore maturity.

 

In January 2004, LG&E entered into one additional long-termloan from an affiliated company totaling $25 million with an interest rate of4.33% that matures in January 2012. The loan is secured by a lien subordinated to the first mortgage bondlien.  The proceeds were used to repayamounts due under the accounts receivable securitization program.

 

# **Note10 - Notes Payable and Other Short-Term Obligations**

 

LG&E participates in an intercompany money pool agreement whereinLG&E Energy and KU make funds available to LG&E at market-based rates(based on an index of highly rated commercial paper issues as of the priormonth end) up to $400 million. Likewise, LG&E Energy and LG&E make funds available to KU atmarket-based rates up to $400 million. The balance of the money pool loan from LG&E Energy (shown as “Notespayable to affiliated company”) was $80.3 million at an average rate of 1.00%and $193.1 million at an average rate of 1.61%, at December 31, 2003 and2002, respectively.  The amountavailable to LG&E under the money pool agreement at December 31, 2003was $319.7 million.  LG&E Energymaintains a revolving credit facility totaling $150 million with an affiliateto ensure funding availability for the money pool.  The outstanding balance under LG&E Energy’s facility as ofDecember 31, 2003 was $111.1 million, and availability of $38.9 millionremained.

 

During July 2003, LG&E entered into five revolving lines ofcredit with banks totaling $185 million. These credit facilities expire in June 2004, and there was nooutstanding balance under any of these facilities at December 31,2003.  The covenants under theserevolving lines of credit include:

 

1.                                       The debt/totalcapitalization ratio must be less than 70%,

2.                                       E.ON AG must ownat least 66.667% of voting stock of LG&E directly or indirectly,

3.                                       the corporatecredit rating of the company must be at or above BBB- and Baa3, and

4.                                       limitation ondisposing assets aggregating more than 15% of total assets as ofDecember 31, 2002.

 

LG&E has not violated anyof the above covenants.

 

In January 2004, LG&E entered into a one year loan totaling$100 million with an affiliated company. The interest rate on the loan is 1.53%, and the proceeds were used torepay notes payable to the parent under the money pool arrangement.  The loan is secured by a second lien onsubstantially all utility assets of LG&E.

 

**Note 11 - Commitmentsand Contingencies**

 

The following is provided to summarize LG&E’s contractual cashobligations for periods after December 31, 2003:

 

95

----

 
| **(in thousands)**                     |   | **Payments  Due by Period** |    |
|----------------------------------------|--------|-----------------------------|---------|
|                                   |   | **2004**                    |    | **2005-  2006** |   | **2007-  2008** |   | **After  2008** |   | **Total** |   |
| Contractual  Cash Obligations          |   |                        |    |   |   |   |   |   |   |   |   |
| Short-term debt (a)                    |   | $                           | 80,332  |   | $ | — |   | $ | — |   | $ | — |   | $ | 80,332 |   |
| Long-term debt (b)                     |   | 247,450                     |    | 2,500 |   | 20,000 |   | 528,104 |   | 798,054 |   |
| Operating lease (c)                    |   | 3,401                       |    | 7,006 |   | 7,290 |   | 26,130 |   | 43,827 |   |
| Unconditional purchase obligations (d) |   | 10,614                      |    | 25,182 |   | 27,195 |   | 254,235 |   | 317,226 |   |
| Other long-term obligations (e)        |   | 20,700                      |    | 3,000 |   | — |   | — |   | 23,700 |   |
| Total contractual cash obligations (f) |   | $                           | 362,497 |   | $ | 37,688 |   | $ | 54,485 |   | $ | 808,469 |   | $ | 1,263,139 |   |

 

(a)          Representsborrowings from affiliated company due within one year.

(b)         Includes long-termdebt of $246.2 million classified as current liabilities because these bondsare subject to tender for purchase at the option of the holder and to mandatorytender for purchase upon the occurrence of certain events.  Maturity dates for these bonds range from2013 to 2027.

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

(d)         Representsfuture minimum payments under purchased power agreements through 2023.

(e)          Representsconstruction commitments.

(f)            LG&E doesnot expect to pay the $246.2 million of long-term debt classified as a currentliability in the Consolidated Balance Sheets in 2004 as explained in (b)above.  LG&E anticipates cash from operationsand external financing will be sufficient to fund future obligations.  LG&E anticipates refinancing a portionof its short-term debt with long-term debt in 2004.

 

**Operating Lease.**  LG&E leases office space, officeequipment and vehicles.  LG&Eaccounts for its leases as operating leases. Total lease expense for 2003, 2002, and 2001, less amounts contributedby affiliated companies occupying a portion of the office space leased byLG&E, was $2.2 million, $2.2 million, and $2.5 million, respectively.  The future minimum annual lease paymentsunder LG&E’s office space lease agreement for years subsequent toDecember 31, 2003, are as follows:

 
| **(in thousands)** |   |   |   |
|--------------------|--------|--------|--------|
| 2004               |   | $      | 3,401  |   |
| 2005               |   | 3.468  |   |
| 2006               |   | 3,538  |   |
| 2007               |   | 3,609  |   |
| 2008               |   | 3,681  |   |
| Thereafter         |   | 26,130 |   |
| Total              |   | $      | 43,827 |   |

 

LG&E is aparticipant in a sale and leaseback transaction involving its 38% interest intwo jointly-owned CTs at KU’s E.W. Brown generating station (Units 6 and7).  Commencing in December 1999,LG&E and KU entered into a tax-efficient, 18-year lease of the CTs.LG&E and KU have provided funds to 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.  The transaction produced a pre-tax gain ofapproximately $1.2 million which was recorded in other income on the incomestatement in 2000, pursuant to a Kentucky Commission order.  The leasing transaction was entered into followingreceipt of required state and federal regulatory approvals.

 

In case ofdefault under the lease, LG&E is obligated to pay to the lessor its shareof certain fees or amounts. Primary events of default include loss ordestruction of the CTs, failure to insure or maintain the CTs and unwinding ofthe transaction due to governmental actions. No events of default currently exist with respect to the lease.  Upon any termination of the lease, whetherby default or expiration of its term, title to the CTs reverts jointly toLG&E and KU.

 

At December 31,2003, the maximum aggregate amount of default fees or amounts, which decreaseover the term of the lease, was $8.9 million, of which LG&E would beresponsible for 38%.  LG&E has madearrangements with LG&E Energy, via guarantee and regulatory commitment, forLG&E Energy to pay its full 

 

96

----

 

portion of anydefault fees or amounts.  LG&E paidLG&E Energy a one-time fee of $114,000 to provide the guarantee.

 

**Letters of Credit.**  LG&E has provided letters of credittotaling $14.3 million as collateral for derivative transactions and to supportcertain obligations related to landfill reclamation.

 

**Purchased Power.**LG&Ehas a contract for purchased power with OVEC for various Mw capacities.  LG&E has an investment of 4.9% ownershipin OVEC’s common stock, which is accounted for under the cost method ofaccounting.  LG&E’s entitlement is7% of OVEC’s generation capacity or approximately 155 Mw.

 

The estimated future minimum annual demand payment under the OVEC purchasedpower agreement for the years subsequent to December 31, 2003, are asfollows:

 
| **(in thousands)** |   |    |    |
|--------------------|--------|---------|---------|
| 2004               |   | $       | 10,614  |   |
| 2005               |   | 10,900  |    |
| 2006               |   | 14,282  |    |
| 2007               |   | 13,426  |    |
| 2008               |   | 13,769  |    |
| Thereafter         |   | 254,235 |    |
| Total              |   | $       | 317,226 |   |

 

**Construction Program.**  LG&E had approximately $20.7 million ofcommitments in connection with its construction program at December 31,2003.  Construction expenditures for theyears 2004 and 2005 are estimated to total approximately $270.0 million,although all of this amount is not currently committed, including theconstruction of four jointly owned CTs, $13.6 million, and construction of NOxequipment, $5.1 million.

 

**Environmental Matters**.  LG&E is subject to SO2 andNOx emission limits on its electric generating units pursuant to the Clean AirAct.  LG&E was not subject to PhaseI SO2 emissions reduction requirements.  LG&E’s strategy for Phase II SO2 reductions, whichcommenced January 1, 2000, is to increase FGD removal efficiency to delayadditional capital expenditures and may also include fuel switching orupgrading FGDs.  LG&E met the NOxemission requirements of the Act through installation of low-NOx burnersystems.  LG&E’s compliance plansare subject to many factors including developments in the emission allowance andfuel markets, future regulatory and legislative initiatives, and advances inclean air control technology.  LG&Ewill continue to monitor these developments to ensure that its environmentalobligations are met in the most efficient and cost-effective manner.

 

In September 1998, the EPA announced its final “NOx SIP Call” rulerequiring states to impose significant additional reductions in NOx emissionsby May 2003, in order to mitigate alleged ozone transport impacts on theNortheast region.  The Commonwealth ofKentucky SIP, which was approved by EPA June 24, 2003, requires reductionsin NOx emissions from coal-fired generating units to the 0.15 lb./Mmbtu levelon a system-wide basis.  In relatedproceedings in response to petitions filed by various Northeast states, inDecember 1999, EPA issued a final rule pursuant to Section 126 of theClean Air Act directing similar NOx reductions from a number of specificallytargeted generating units including all LG&E units.  As a result of appeals to both rules, thecompliance date was extended to May 2004. All LG&E generating units are subject to the May 2004 compliancedate under these NOx emissions reduction rules.

 

LG&E is currently implementing a plan for adding significantadditional NOx controls to its generating units.  Installation of additional NOx controls will proceed on a phasedbasis, with installation of controls commencing in late 2000 and continuingthrough the final compliance date. LG&E estimates that it will incur total capital costs of approximately$185 million to reduce its NOx emissions to the 0.15 lb./Mmbtu level on acompany-

 

97

----

 

wide basis.  As of December 31,2003, LG&E has incurred approximately $177 million of these capital costsrelated to the reduction of its NOx emissions. In addition, LG&E will incur additional operation and maintenancecosts in operating new NOx controls. LG&E believes its costs in this regard to be comparable to those ofsimilarly situated utilities with like generation assets.  LG&E had anticipated that such capitaland operating costs are the type of costs that are eligible for recovery fromcustomers under its environmental surcharge mechanism and believed that a significantportion of such costs could be recovered. In April 2001, the Kentucky Commission granted recovery of thesecosts for LG&E.

 

LG&E is also monitoring several other air quality issues which maypotentially impact coal-fired power plants, including EPA’s revised air qualitystandards for ozone and particulate matter, measures to implement EPA’sregional haze rule, EPA’s December 2003 proposals to regulate mercuryemissions from steam electric generating units and to further reduce emissionsof sulfur dioxide and nitrogen oxides under the Interstate Air QualityRule.  In addition, LG&E iscurrently working with local regulatory authorities to review the effectivenessof remedial measures aimed at controlling particulate matter emissions from itsMill Creek Station.  LG&E previouslysettled a number of property damage claims from adjacent residents andcompleted significant remedial measures as part of its ongoing capitalconstruction program.  LG&E is inthe process of converting the Mill Creek Station to wet stack operation in aneffort to resolve all outstanding issues related to particulate matteremissions.

 

LG&E owns or formerly owned three properties which are the locationof past MGP operations.  Variouscontaminants are typically found at such former MGP sites and environmentalremediation measures are frequently required. With respect to the sites, LG&E has completed cleanups, obtainedregulatory approval of site management plans, or reached agreements for otherparties to assume responsibility for cleanup. Based on currently available information, management estimates that itwill incur additional costs of $0.4 million. Accordingly, an accrual of $0.4 million has been recorded in theaccompanying financial statements at December 31, 2003 and 2002.

 

**Note 12 - JointlyOwned 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 the remaining 25% of the Unit, IMEA owns a 12.12% undividedinterest, and IMPA owns a 12.88% undivided interest.  Each company is responsible for its proportionate ownership shareof fuel cost, operation and maintenance expenses, and incremental assets.

 

The following data represent shares of the jointly owned property:

 
|                                               |   | **Trimble  County** |    |
|----------------------------------------------------|--------|---------------------|---------|
|                                               |   | **LG&E**        |    | **IMPA** |   | **IMEA** |   | **Total** |   |
| Ownership interest                                 |   | 75                  | %       | 12.88 | % | 12.12 | % | 100 | % |
| Mw capacity                                        |   | 386.2               |    | 66.4 |   | 62.4 |   | 515.0 |   |
|                                               |   |                |    |   |   |   |   |   |   |
| LG&E’s 75% ownership (in thousands of $): |   |                |    |   |   |   |   |   |   |
| Cost                                               |   | $                   | 595,313 |   |   |   |   |   |   |   |
| Accumulated depreciation                           |   | 194,343             |    |   |   |   |   |   |   |
| Net book value                                     |   | $                   | 400,970 |   |   |   |   |   |   |   |
|                                               |   |                |    |   |   |   |   |   |   |
| Construction work in progress (included  above)    |   | $                   | 8,374   |   |   |   |   |   |   |   |

 

98

----

 

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

 
| **($ in thousands)**  |   |           |   | **LG&E** |   | **KU** |   | **Total** |   |
|-----------------------|--------|----------------|--------|--------------|--------|--------|--------|-----------|--------|
| Paddy’s Run 13   |   | Ownership %    |   | 53           | %      | 47     | %      | 100       | %      |
|                  |   | Mw capacity    |   | 84           |   | 74     |   | 158       |   |
|                  |   | Cost           |   | $            | 33,919 |   | $      | 29,973    |   | $ | 63,892 |   |
|                  |   | Depreciation   |   | 2,875        |   | 2,527  |   | 5,402     |   |
|                  |   | Net book value |   | $            | 31,044 |   | $      | 27,446    |   | $ | 58,490 |   |
|                  |   |           |   |         |   |   |   |      |   |
| E.W. Brown 5          |   | Ownership %    |   | 53           | %      | 47     | %      | 100       | %      |
|                  |   | Mw capacity    |   | 62           |   | 55     |   | 117       |   |
|                  |   | Cost           |   | $            | 24,111 |   | $      | 20,296    |   | $ | 44,407 |   |
|                  |   | Depreciation   |   | 2,033        |   | 1,700  |   | 3,733     |   |
|                  |   | Net book value |   | $            | 22,078 |   | $      | 18,596    |   | $ | 40,674 |   |
|                  |   |           |   |         |   |   |   |      |   |
| E.W. Brown 6          |   | Ownership %    |   | 38           | %      | 62     | %      | 100       | %      |
|                  |   | Mw capacity    |   | 59           |   | 95     |   | 154       |   |
|                  |   | Cost           |   | $            | 23,975 |   | $      | 36,701    |   | $ | 60,676 |   |
|                  |   | Depreciation   |   | 2,629        |   | 5,447  |   | 8,076     |   |
|                  |   | Net book value |   | $            | 21,346 |   | $      | 31,254    |   | $ | 52,600 |   |
|                  |   |           |   |         |   |   |   |      |   |
| E.W. Brown 7          |   | Ownership %    |   | 38           | %      | 62     | %      | 100       | %      |
|                  |   | Mw capacity    |   | 59           |   | 95     |   | 154       |   |
|                  |   | Cost           |   | $            | 23,824 |   | $      | 38,256    |   | $ | 62,080 |   |
|                  |   | Depreciation   |   | 3,571        |   | 4,039  |   | 7,610     |   |
|                  |   | Net book value |   | $            | 20,253 |   | $      | 34,217    |   | $ | 54,470 |   |
|                  |   |           |   |         |   |   |   |      |   |
| Trimble 5             |   | Ownership %    |   | 29           | %      | 71     | %      | 100       | %      |
|                  |   | Mw capacity    |   | 46           |   | 114    |   | 160       |   |
|                  |   | Cost           |   | $            | 15,970 |   | $      | 39,045    |   | $ | 55,015 |   |
|                  |   | Depreciation   |   | 799          |   | 1,953  |   | 2,752     |   |
|                  |   | Net book value |   | $            | 15,171 |   | $      | 37,092    |   | $ | 52,263 |   |
|                  |   |           |   |         |   |   |   |      |   |
| Trimble 6             |   | Ownership %    |   | 29           | %      | 71     | %      | 100       | %      |
|                  |   | Mw capacity    |   | 46           |   | 114    |   | 160       |   |
|                  |   | Cost           |   | $            | 15,961 |   | $      | 39,025    |   | $ | 54,986 |   |
|                  |   | Depreciation   |   | 798          |   | 1,952  |   | 2,750     |   |
|                  |   | Net book value |   | $            | 15,163 |   | $      | 37,073    |   | $ | 52,236 |   |
|                  |   |           |   |         |   |   |   |      |   |
| Trimble 7             |   | Ownership %    |   | 37           | %      | 63     | %      | 100       | %      |
|                  |   | Mw capacity    |   | 56           |   | 96     |   | 152       |   |
|                  |   | Current CWIP   |   | $            | 17,342 |   | $      | 29,634    |   | $ | 46,976 |   |
|                  |   |           |   |         |   |   |   |      |   |
| Trimble 8             |   | Ownership %    |   | 37           | %      | 63     | %      | 100       | %      |
|                  |   | Mw capacity    |   | 56           |   | 96     |   | 152       |   |
|                  |   | Current CWIP   |   | $            | 17,307 |   | $      | 29,601    |   | $ | 46,908 |   |
|                  |   |           |   |         |   |   |   |      |   |
| Trimble 9             |   | Ownership %    |   | 37           | %      | 63     | %      | 100       | %      |
|                  |   | Mw capacity    |   | 56           |   | 96     |   | 152       |   |
|                  |   | Current CWIP   |   | $            | 17,300 |   | $      | 29,599    |   | $ | 46,899 |   |
|                  |   |           |   |         |   |   |   |      |   |
| Trimble 10            |   | Ownership %    |   | 37           | %      | 63     | %      | 100       | %      |
|                  |   | Mw capacity    |   | 56           |   | 96     |   | 152       |   |
|                  |   | Current CWIP   |   | $            | 17,300 |   | $      | 29,597    |   | $ | 46,897 |   |
|                  |   |           |   |         |   |   |   |      |   |
| Trimble CT Pipeline   |   | Ownership %    |   | 29           | %      | 71     | %      | 100       | %      |
|                  |   | Cost           |   | $            | 1,835  |   | $      | 4,475     |   | $ | 6,310 |   |
|                  |   | Depreciation   |   | 102          |   | 249    |   | 351       |   |
|                  |   | Net book value |   | $            | 1,733  |   | $      | 4,226     |   | $ | 5,959 |   |
|                  |   |           |   |         |   |   |   |      |   |
| Trimble CT Substation |   | Ownership %    |   | 29           | %      | 71     | %      | 100       | %      |
|                  |   | Cost           |   | $            | 1,474  |   | $      | 3,598     |   | $ | 5,072 |   |
|                  |   | Depreciation   |   | 45           |   | 116    |   | 161       |   |
|                  |   | Net book value |   | $            | 1,429  |   | $      | 3,482     |   | $ | 4,911 |   |

 

99

----

 

See also Note 11, Construction Program, for LG&E’s plannedexpenditures for construction of four jointly owned CTs in 2004.

 

**Note 13 - Segments ofBusiness 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 Kentucky Commission and files electric andgas financial information separately with the Kentucky Commission.  The Kentucky Commission establishes ratesspecifically for the electric and gas businesses.  Therefore, management reports and analyzes financial performancebased on the electric and gas segments of the business.  Financial data for business segments follow:

 
| **(in thousands)**            |   | **Electric** |    | **Gas** |   | **Total** |   |
|-------------------------------|--------|--------------|---------|---------|--------|-----------|--------|
| 2003                          |   |         |    |    |   |      |   |
| Operating revenues            |   | $            | 768,188 | (a)     | $      | 325,333   |   | $ | 1,093,521 |   |
| Depreciation and amortization |   | 96,487       |    | 16,801  |   | 113,288   |   |
| Operating income taxes        |   | 49,409       |    | 6,657   |   | 56,066    |   |
| Interest income               |   | 27           |    | 4       |   | 31        |   |
| Interest expense              |   | 25,694       |    | 4,953   |   | 30,647    |   |
| Net income                    |   | 80,612       |    | 10,227  |   | 90,839    |   |
| Total assets                  |   | 2,345,784    |    | 543,144 |   | 2,888,928 |   |
| Construction expenditures     |   | 177,961      |    | 34,996  |   | 212,957   |   |
|                          |   |         |    |    |   |      |   |
| 2002                          |   |         |    |    |   |      |   |
| Operating revenues            |   | $            | 736,042 | (b)     | $      | 267,693   |   | $ | 1,003,735 |   |
| Depreciation and amortization |   | 90,248       |    | 15,658  |   | 105,906   |   |
| Operating income taxes        |   | 49,010       |    | 6,025   |   | 55,035    |   |
| Interest income               |   | 381          |    | 76      |   | 457       |   |
| Interest expense              |   | 24,837       |    | 4,968   |   | 29,805    |   |
| Net income                    |   | 79,246       |    | 9,683   |   | 88,929    |   |
| Total assets                  |   | 2,276,712    |    | 492,218 |   | 2,768,930 |   |
| Construction expenditures     |   | 195,662      |    | 24,754  |   | 220,416   |   |
|                          |   |         |    |    |   |      |   |
| 2001                          |   |         |    |    |   |      |   |
| Operating revenues            |   | $            | 673,772 | (c)     | $      | 290,775   |   | $ | 964,547 |   |
| Depreciation and amortization |   | 85,572       |    | 14,784  |   | 100,356   |   |
| Operating income taxes        |   | 55,527       |    | 7,925   |   | 63,452    |   |
| Interest income               |   | 616          |    | 132     |   | 748       |   |
| Interest expense              |   | 31,295       |    | 6,627   |   | 37,922    |   |
| Net income                    |   | 95,103       |    | 11,768  |   | 106,781   |   |
| Total assets                  |   | 1,985,252    |    | 463,102 |   | 2,448,354 |   |
| Construction expenditures     |   | 227,107      |    | 25,851  |   | 252,958   |   |

 

----

(a)                                  Netof provision for rate refunds of $0.4 million.

(b)                                 Netof provision for rate collections of $11.7 million.

(c)                                  Netof provision for rate collections of $1.6 million.

 

100

----

 

**Note 14 -****RelatedParty Transactions**

 

LG&E, subsidiaries of LG&E Energy and other subsidiaries ofE.ON engage in related party transactions. Transactions between LG&E and its subsidiary LG&E R areeliminated upon consolidation with LG&E. Transactions between LG&E and LG&E Energy subsidiaries areeliminated upon consolidation of LG&E Energy. Transactions between LG&Eand E.ON subsidiaries are eliminated upon consolidation of E.ON. Thesetransactions are generally performed at cost and are in accordance with the SECregulations under the PUHCA and the applicable Kentucky Commissionregulations.  Amounts payable to andreceivable from related parties are netted and presented as accounts payable toaffiliated companies on the balance sheet of LG&E, as allowed due to theright of offset. Obligations related to intercompany debt arrangements withLG&E Energy and Fidelia, an E.ON subsidiary, are presented as separate lineitems on the balance sheet, as appropriate. The significant related partytransactions are disclosed below.

 

Electric Purchases

 

LG&E and KU purchase energy from each other in order to effectivelymanage the load of their retail and off-system customers.  In addition, LG&E and LG&E EnergyMarketing Inc. (“LEM”), a subsidiary of LG&E Energy, purchase energy fromeach other. These sales and purchases are included in the ConsolidatedStatements of Income as Electric Operating Revenues and Purchased PowerOperating Expense.  LG&Eintercompany electric revenues and purchased power expense for the years endedDecember 31, 2003, 2002, and 2001 were as follows:

 
| **(in thousands)**                   |   | **2003** |   | **2002** |   | **2001** |   |
|--------------------------------------|--------|----------|--------|----------|--------|----------|--------|
| Electric operating revenues from KU  |   | $        | 53,747 |     | $      | 41,480   |   | $ | 28,521 |   |
| Electric operating revenues from LEM |   | 9,372    |   | 9,939    |   | 5,564    |   |
| Purchased power from KU              |   | 46,690   |   | 33,249   |   | 31,133   |   |
| Purchased power from LEM             |   | —   |   | 913      |   | —   |   |
|                                      |        |          |        |          |        |          |        |  |  |  |

 

Interest Charges

 

LG&E participates in an intercompany money pool agreement whereinLG&E Energy and KU make funds available to LG&E at market-based rates(based on an index of highly rated commercial paper issues as of the priormonth end) up to $400 million. Likewise, LG&E Energy and LG&E make funds available to KU atmarket-based rates up to $400 million. The balance of the money pool loan from LG&E Energy (shown as “Notespayable to affiliated company”) was $80.3 million at an average rate of 1.00%and $193.1 million at an average rate of 1.61%, at December 31, 2003 and2002, respectively.  The amountavailable to LG&E under the money pool agreement at December 31, 2003was $319.7 million.  LG&E Energymaintains a revolving credit facility totaling $150 million with an affiliateto ensure funding availability for the money pool.  The outstanding balance under LG&E Energy’s facility as ofDecember 31, 2003 was $111.1 million, and availability of $38.9 millionremained.

 

In addition, in 2003 LG&E began borrowing long-term funds fromFidelia Corporation, an affiliate of E.ON (see Note 9).  Fidelia Corporation has a second lien on theproperty subject to the first mortgage bond lien.  The second lien secures $100 million of the loans provided byFidelia.

 

Intercompany agreements do not require interest payments forreceivables related to services provided when settled within 30 days.  The only interest income or expense recordedby the utilities relates to LG&E’s receipt and payment of KU’s portion ofoff-system sales and purchases.

 

LG&E intercompany interest income and expense for the years endedDecember 31, 2003, 2002, and 2001 were as follows:

 

101

----

 
| **(in thousands)**               |   | **2003** |   | **2002** |   | **2001** |   |
|----------------------------------|--------|----------|--------|----------|--------|----------|--------|
| Interest on money pool loans     |   | $        | 1,751  |     | $      | 2,114    |   | 2,719 |   |
| Interest on Fidelia loans        |   | 5,025    |   | —   |   | —   |   |
| Interest expense paid to KU      |   | 8        |   | 61       |   | 296      |   |
| Interest income received from KU |   | 6        |   | 5        |   | —   |   |
|                                  |        |          |        |          |        |          |        |  |  |

 

Other Intercompany Billings

 

LG&E Services provides LG&E with a variety of centralizedadministrative, management, and support services in accordance with agreementsapproved by the SEC under PUHCA. These charges include taxes paid by LG&EEnergy on behalf of LG&E, labor and burdens of LG&E Services employeesperforming services for LG&E, and vouchers paid by LG&E Services onbehalf of LG&E.  The cost of theseservices are directly charged to LG&E, or for general costs which cannot bedirectly attributed, charged based on predetermined allocation factors,including the following ratios: number of customers, total assets, revenues,number of employees, and other statistical information.  These costs are charged on an actual costbasis.

 

In addition, LG&E and KU provide certain services to each other andto L&GE Services, in accordance with exceptions granted under PUHCA.Billings between LG&E and KU relate to labor and overheads associated withunion employees performing work for the other utility, charges related tojointly-owned combustion turbines, and other miscellaneous charges.  Billings from LG&E to LG&E Servicesrelate to information technology-related services provided by LG&Eemployees, cash received by LG&E Services on behalf of LG&E, andservices provided by LG&E to other non-regulated businesses which are paidthrough LG&E Services.

 

Intercompany billings to and from LG&E for the years endedDecember 31, 2003, 2002, and 2001 were as follows:

 
| **(in thousands)**                     |   | **2003** |    | **2002** |   | **2001** |   |
|----------------------------------------|--------|----------|---------|----------|--------|----------|--------|
| LG&E Services billings to LG&E |   | $        | 185,756 |     | $      | 183,124  |   | $ | 193,426 |   |
| LG&E billings to KU                |   | 23,436   |    | 29,659   |   | 31,314   |   |
| KU billings to LG&E                |   | 31,850   |    | 36,404   |   | 87,992   |   |
| LG&E billings to LG&E Services |   | 19,951   |    | 15,079   |   | 26,060   |   |
|                                        |        |          |         |          |        |          |        |  |  |  |

 

**Note 15 - SelectedQuarterly Data (Unaudited)**

 

Selected financial data for the four quarters of 2003 and 2002 areshown below.  Because of seasonalfluctuations in temperature and other factors, results for quarters mayfluctuate throughout the year.

 
|                 |   | **Quarters  Ended** |    |
|----------------------|--------|---------------------|---------|
| **(in thousands)**   |   | **March**           |    | **June** |   | **September** |   | **December** |   |
| 2003                 |   |                |    |   |   |   |   |   |   |
| Operating revenues   |   | $                   | 326,844 |   | $ | 215,373 |   | $ | 262,833 |   | $ | 288,471 |   |
| Net operating income |   | 33,190              |    | 16,290 |   | 47,680 |   | 25,525 |   |
| Net income           |   | 27,264              |    | 7,755 |   | 39,871 |   | 15,949 |   |
|                 |   |                |    |   |   |   |   |   |   |
| 2002                 |   |                |    |   |   |   |   |   |   |
| Operating revenues   |   | $                   | 278,005 |   | $ | 216,163 |   | $ | 243,074 |   | $ | 266,493 |   |
| Net operating income |   | 28,748              |    | 22,410 |   | 41,652 |   | 25,104 |   |
| Net income           |   | 20,943              |    | 15,256 |   | 34,204 |   | 18,526 |   |

 

102

----

 

As the result of EITF No. 02-03, LG&E has netted the powerpurchased expense for trading activities against electric operatingrevenue.  LG&E applied this guidanceto all prior periods beginning with the June 2003 10-Q filing, which hadno impact on previously reported net income or common equity (See Note 1).

 
| **(in thousands)**                            |   | **Quarter  Ended  March** | ** ** |
|-----------------------------------------------|--------|---------------------------|------------|
| 2003                                          |   |                      |       |
| Gross operating revenues                      |   | $                         | 335,117    |   |
| Less costs reclassified from power  purchased |   | 8,273                     |       |
| Net operating revenues reported               |   | $                         | 326,844    |   |
|                                          |   |                      |       |
| 2002                                          |   |                      |       |
| Gross operating revenues                      |   | $                         | 283,365    |   |
| Less costs reclassified from power  purchased |   | 5,360                     |       |
| Net operating revenues reported               |   | $                         | 278,005    |   |

 

**Note 16 - SubsequentEvents**

 

LG&E made a contribution to the pension plan of $34.5 million inJanuary 2004 (see Note 6).

 

LG&E terminated the accounts receivable securitization program inJanuary 2004 (see Note 4).

 

In January 2004, LG&E entered into a one year loan with anaffiliated company totaling $100 million with an interest rate of 1.53%.  The proceeds were used to repay notespayable to affiliated company under the money pool arrangement.  The loan is secured by a second lien onsubstantially all utility assets of LG&E (see Note 10).

 

In January 2004, LG&E entered into a long-term loan with anaffiliated company totaling $25 million with an interest rate of 4.33% thatmatures in January 2012.  Theproceeds were used to repay amounts due under the accounts receivablesecuritization program. The loan is secured by a lien subordinated to the firstmortgage bond lien (see Note 9).

 

103

----

 

Louisville Gasand Electric Company and SubsidiaryREPORT OF MANAGEMENT

 

The management of Louisville Gas and Electric Company and Subsidiary isresponsible for the preparation and integrity of the financial statements andrelated information included in this Annual Report.  These statements have been prepared in accordance with accountingprinciples generally accepted in the United States applied on a consistentbasis and, necessarily, include amounts that reflect the best estimates andjudgment of management.

 

LG&E’s 2003, 2002 and 2001 financial statements have been auditedby PricewaterhouseCoopers LLP, independent auditors.  Management made available to PricewaterhouseCoopers LLP allLG&E’s financial records and related data as well as the minutes of shareholders’and directors’ meetings.

 

Management has established and maintains a system of internal controlsthat provides reasonable assurance that transactions are completed inaccordance with management’s authorization, that assets are safeguarded andthat financial statements are prepared in conformity with generally acceptedaccounting principles.  Managementbelieves that an adequate system of internal controls is maintained through theselection and training of personnel, appropriate division of responsibility,establishment and communication of policies and procedures and by regularreviews of internal accounting controls by LG&E’s internal auditors.  Management reviews and modifies its systemof internal controls in light of changes in conditions and operations, as wellas in response to recommendations from the internal and external auditors.  These recommendations for the year endedDecember 31, 2003, did not identify any material weaknesses in the designand operation of LG&E’s internal control structure.

 

In carrying out its oversight role for the financial reporting andinternal controls of LG&E, the Board of Directors meets regularly withLG&E’s independent auditors, internal auditors and management.  The Board of Directors reviews the resultsof the independent auditors’ audit of the financial statements and their auditprocedures, and discusses the adequacy of internal accounting controls.  The Board of Directors also approves theannual internal auditing program and reviews the activities and results of theinternal auditing function.  Both theindependent public auditors and the internal auditors have access to the Boardof Directors at any time.

 

Louisville Gas and Electric Company and Subsidiary maintains andinternally communicates a written code of business conduct and a senior financialofficer code of ethics which address, among other items, potential conflicts ofinterest, compliance with laws, including those relating to financialdisclosure, and the confidentiality of proprietary information.

 

S. Bradford Rives

Chief Financial Officer

 

Louisville Gas and Electric Company and Subsidiary

Louisville, Kentucky

 

104

----

 

Louisville Gasand Electric Company and SubsidiaryREPORT OF INDEPENDENT AUDITORS

 

To the Shareholders of Louisville Gas and Electric Company andSubsidiary:

 

In our opinion, the accompanying consolidated balance sheets and therelated consolidated statements of capitalization, income, retained earnings,cash flows and comprehensive income present fairly, in all material respects,the financial position of Louisville Gas and Electric Company and Subsidiary(the “Company”) at December 31, 2003 and 2002, and the results of theiroperations and their cash flows for each of the three years in the period endedDecember 31, 2003 in conformity with accounting principles generallyaccepted in the United States of America. In addition, in our opinion, basedon our audits, the financial statementschedule as of and for the year ended December 31, 2003 listed in theindex appearing under Item 15(a)(2), presents fairly, in all material respects,the information set forth therein when read in conjunction with the relatedconsolidated****financial statements. These financial statements and financial statement schedules arethe responsibility of the Company’s management; our responsibility is toexpress an opinion on these financial statements and financial statementschedules based on our audits.  Weconducted our audits of these statements in accordance with auditing standardsgenerally accepted in the United States of America, which require that we planand perform the audit to obtain reasonable assurance about whether thefinancial statements are free of material misstatement.  An audit includes examining, on a testbasis, evidence supporting the amounts and disclosures in the financialstatements, assessing the accounting principles used and significant estimatesmade by management, and evaluating the overall financial statementpresentation.  We believe that ouraudits provide a reasonable basis for our opinion.

 

As discussed in Note 1 to the consolidatedfinancial statements, effective January 1, 2003,  Louisville Gas and Electric Company and Subsidiary adopted EITFNo. 02-03*,Issues Involved in Accounting for Derivative Contracts Held for TradingPurposes and Contracts Involved in Energy Trading and Risk ManagementActivities*.  As discussed inNote 1 to the consolidated financial statements, effective January 1,2003, Louisville Gas and Electric Company and Subsidiary adopted Statement ofFinancial Accounting Standards No. 143, *Accounting for Asset Retirement Obligations*.  As discussed in Note 1 to the consolidatedfinancial statements, effective July 1, 2003, Louisville Gas and ElectricCompany and Subsidiary adopted Statement of Financial Accounting Standards No.150, *Accounting for Certain FinancialInstruments with Characteristics of Both Liabilities and Equity.*

 
| /s/ PricewaterhouseCoopers LLP |   |
|--------------------------------|--------|
|                           |
| PricewaterhouseCoopers  LLP    |
| Louisville, Kentucky           |
| February 5, 2004          |

 

105

----

 

INDEX OF ABBREVIATIONS

 
| AFUDC               | Allowance for Funds Used During  Construction                |
|---------------------|--------------------------------------------------------------|
| ARO                 | Asset Retirement Obligation                                  |
| Capital Corp.       | LG&E Capital Corp.                                       |
| Clean Air Act       | The Clean Air Act, as amended in 1990                        |
| CCN                 | Certificate of Public Convenience and  Necessity             |
| CT                  | Combustion Turbines                                          |
| CWIP                | Construction Work in Progress                                |
| DSM                 | Demand Side Management                                       |
| ECR                 | Environmental Cost Recovery                                  |
| EEI                 | Electric Energy, Inc.                                        |
| EITF                | Emerging Issues Task Force Issue                             |
| E.ON                | E.ON AG                                                      |
| EPA                 | U.S. Environmental Protection Agency                         |
| ESM                 | Earnings Sharing Mechanism                                   |
| F                   | Fahrenheit                                                   |
| FAC                 | Fuel Adjustment Clause                                       |
| FERC                | Federal Energy Regulatory Commission                         |
| FGD                 | Flue Gas Desulfurization                                     |
| FPA                 | Federal Power Act                                            |
| FT and FT-A         | Firm Transportation                                          |
| GSC                 | Gas Supply Clause                                            |
| IBEW                | International Brotherhood of Electrical  Workers             |
| IMEA                | Illinois Municipal Electric Agency                           |
| IMPA                | Indiana Municipal Power Agency                               |
| Kentucky Commission | Kentucky Public Service Commission                           |
| KIUC                | Kentucky Industrial Utility Consumers, Inc.                  |
| KU                  | Kentucky Utilities Company                                   |
| KU Energy           | KU Energy Corporation                                        |
| KU R                | KU Receivables LLC                                           |
| kV                  | Kilovolts                                                    |
| Kva                 | Kilovolt-ampere                                              |
| KW                  | Kilowatts                                                    |
| Kwh                 | Kilowatt hours                                               |
| LEM                 | LG&E Energy Marketing Inc.                               |
| LG&E            | Louisville Gas and Electric Company                          |
| LG&E Energy     | LG&E Energy LLC (as successor to  LG&E Energy Corp.) |
| LG&E R          | LG&E  Receivables LLC                                    |
| LG&E Services   | LG&E Energy Services Inc.                                |
| Mcf                 | Thousand Cubic Feet                                          |
| MGP                 | Manufactured Gas Plant                                       |
| MISO                | Midwest Independent Transmission System  Operator            |
| Mmbtu               | Million British thermal units                                |
| Moody’s        | Moody’s Investor Services, Inc.                         |
| Mw                  | Megawatts                                                    |
| Mwh                 | Megawatt hours                                               |
| NNS                 | No-Notice Service                                            |
| NOPR                | Notice of Proposed Rulemaking                                |
| NOx                 | Nitrogen Oxide                                               |
| OATT                | Open Access Transmission Tariff                              |
| OMU                 | Owensboro Municipal Utilities                                |
| OVEC                | Ohio Valley Electric Corporation                             |
| PBR                 | Performance-Based Ratemaking                                 |
| PJM                 | Pennsylvania, New Jersey, Maryland Interconnection           |
| Powergen            | Powergen Limited (formerly Powergen plc)                     |
| PUHCA               | Public Utility Holding Company Act of 1935                   |
| ROE                 | Return on Equity                                             |
| RTO                 | Regional Transmission Organization                           |
| S&P             | Standard & Poor’s Rating Services                   |

 

106

----

 
| SCR                 | Selective Catalytic Reduction                |
|---------------------|----------------------------------------------|
| SEC                 | Securities and Exchange Commission           |
| SERP                | Supplemental Employee Retirement Plan        |
| SFAS                | Statement of Financial Accounting Standards  |
| SIP                 | State Implementation Plan                    |
| SMD                 | Standard Market Design                       |
| SO2                 | Sulfur Dioxide                               |
| Tennessee Gas       | Tennessee Gas Pipeline Company               |
| Texas Gas           | Texas Gas Transmission LLC                   |
| TRA                 | Tennessee Regulatory Authority               |
| Trimble County      | LG&E’s  Trimble County Unit 1       |
| USWA                | United Steelworkers of America               |
| Utility Operations  | Operations of LG&E and KU                |
| VDT                 | Value Delivery Team Process                  |
| Virginia Commission | Virginia State Corporation Commission        |
| Virginia Staff      | Virginia State Corporation  Commission Staff |
| WNA                 | Weather Normalization Adjustment             |

 

107

----

 

Kentucky Utilities Company and SubsidiaryConsolidated Statements of Income(Thousands of $)

 
|                                                                                                                             |   | **Years  Ended December 31** |    |
|----------------------------------------------------------------------------------------------------------------------------------|--------|-----------------------------------|---------|
|                                                                                                                             |   | **2003**                          |    | **2002** |   | **2001** |   |
|                                                                                                                             |   |                              |    |   |   |   |   |
| OPERATING REVENUES:                                                                                                              |   |                              |    |   |   |   |   |
| Electric (Notes 1 and 13)                                                                                                        |   | $                                 | 900,312 |   | $ | 846,183 |   | $ | 820,920 |   |
| Provision for rate collections (refunds)  (Note 3)                                                                               |   | (8,534                            | )       | 15,481 |   | (199 | ) |
| Total operating revenues                                                                                                         |   | 891,778                           |    | 861,664 |   | 820,721 |   |
|                                                                                                                             |   |                              |    |   |   |   |   |
| OPERATING EXPENSES:                                                                                                              |   |                              |    |   |   |   |   |
| Fuel for electric generation                                                                                                     |   | 265,935                           |    | 250,117 |   | 236,985 |   |
| Power purchased (Note 13)                                                                                                        |   | 140,063                           |    | 131,400 |   | 118,410 |   |
| Other operation expenses                                                                                                         |   | 145,606                           |    | 144,118 |   | 118,359 |   |
| Non-recurring charge (Note 3)                                                                                                    |   | —                            |    | — |   | 6,867 |   |
| Maintenance                                                                                                                      |   | 60,271                            |    | 62,909 |   | 57,021 |   |
| Depreciation and amortization (Note 1)                                                                                           |   | 101,805                           |    | 95,462 |   | 90,299 |   |
| Federal and state income taxes (Note 7)                                                                                          |   | 54,656                            |    | 54,032 |   | 57,482 |   |
| Property and other taxes                                                                                                         |   | 15,888                            |    | 14,983 |   | 13,928 |   |
| Total operating expenses                                                                                                         |   | 784,224                           |    | 753,021 |   | 699,351 |   |
|                                                                                                                             |   |                              |    |   |   |   |   |
| Net operating income                                                                                                             |   | 107,554                           |    | 108,643 |   | 121,370 |   |
|                                                                                                                             |   |                              |    |   |   |   |   |
| Other income – net (Note 8)                                                                                                 |   | 9,089                             |    | 10,368 |   | 8,636 |   |
| Other income from affiliated company (Note  13)                                                                                  |   | 8                                 |    | 61 |   | 296 |   |
| Interest expense                                                                                                                 |   | 19,309                            |    | 24,612 |   | 33,050 |   |
| Interest expense to affiliated companies  (Note 13)                                                                              |   | 5,940                             |    | 1,076 |   | 974 |   |
|                                                                                                                             |   |                              |    |   |   |   |   |
| Net income before cumulative effect of a  change in accounting principle                                                         |   | 91,402                            |    | 93,384 |   | 96,278 |   |
|                                                                                                                             |   |                              |    |   |   |   |   |
| Cumulative effect of a change in accounting  principle-accounting for derivative instruments and hedging activities, net  of tax |   | —                            |    | — |   | 136 |   |
|                                                                                                                             |   |                              |    |   |   |   |   |
| Net income                                                                                                                       |   | $                                 | 91,402  |   | $ | 93,384 |   | $ | 96,414 |   |

 

 

Consolidated Statements of Retained Earnings(Thousands of $)

 
|                                                                                                                                |   | **Years  Ended December 31** |    |
|-------------------------------------------------------------------------------------------------------------------------------------|--------|-----------------------------------|---------|
|                                                                                                                                |   | **2003**                          |    | **2002** |   | **2001** |   |
|                                                                                                                                |   |                              |    |   |   |   |   |
| Balance January 1                                                                                                              |   | $                                 | 502,024 |   | $ | 410,896 |   | $ | 347,238 |   |
| Add net income                                                                                                                      |   | 91,402                            |    | 93,384 |   | 96,414 |   |
|                                                                                                                                |   | 593,426                           |    | 504,280 |   | 443,652 |   |
| Deduct:                Cash dividends declared on stock: |   |                              |    |   |   |   |   |
| 4.75% cumulative preferred                                                                                                          |   | 950                               |    | 950 |   | 950 |   |
| 6.53% cumulative preferred                                                                                                          |   | 1,306                             |    | 1,306 |   | 1,306 |   |
| Common                                                                                                                              |   | —                            |    | — |   | 30,500 |   |
|                                                                                                                                |   | 2,256                             |    | 2,256 |   | 32,756 |   |
|                                                                                                                                |   |                              |    |   |   |   |   |
| Balance December 31                                                                                                            |   | $                                 | 591,170 |   | $ | 502,024 |   | $ | 410,896 |   |

 

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

 

108

----

 

KentuckyUtilities Company and SubsidiaryConsolidated Statements of ComprehensiveIncome(Thousands of $)

 
|                                                                                                                                                                         |   | **Years  Ended December 31** |   |
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|-----------------------------------|--------|
|                                                                                                                                                                         |   | **2003**                          |   | **2002** |   | **2001** |   |
|                                                                                                                                                                         |   |                              |   |   |   |   |   |
| Net income                                                                                                                                                                   |   | $                                 | 91,402 |   | $ | 93,384 |   | $ | 96,414 |   |
|                                                                                                                                                                         |   |                              |   |   |   |   |   |   |   |   |
| Cumulative effect of change in accounting  principle – Accounting for derivative instruments and hedging activities, net  of tax benefit/(expense) of $(1,059) for 2001 |   | —                            |   | — |   | 1,588 |   |
|                                                                                                                                                                         |   |                              |   |   |   |   |   |
| Losses on derivative instruments and  hedging activities, net of tax benefit/(expense) of $102 and $1,059 for 2003  and 2002, respectively                                   |   | (147                              | )      | (1,588 | ) | — |   |
|                                                                                                                                                                         |   |                              |   |   |   |   |   |
| Additional minimum pension liability  adjustment, net of tax benefit/(expense) of $(3,099) and $7,081 for 2003 and  2002, respectively (Note 6)                              |   | 4,578                             |   | (10,462 | ) | — |   |
|                                                                                                                                                                         |   |                              |   |   |   |   |   |
| Other comprehensive income (loss), net of tax                                                                                                                                |   | 4,431                             |   | (12,050 | ) | 1,588 |   |
|                                                                                                                                                                         |   |                              |   |   |   |   |   |
| Comprehensive income                                                                                                                                                         |   | $                                 | 95,833 |   | $ | 81,334 |   | $ | 98,002 |   |

 

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

 

109

----

 

KentuckyUtilities Company and SubsidiaryConsolidated Balance Sheets(Thousands of $)

 
|                                                                    |   | **December 31** |      |
|-------------------------------------------------------------------------|--------|----------------------|-----------|
|                                                                    |   | **2003**             |      | **2002** |   |
| ASSETS:                                                                 |   |                 |      |   |   |
| Utility plant, at original cost (Note 1)                                |   | $                    | 3,193,145 |   | $ | 3,089,529 |   |
| Less:   reserve for depreciation                                   |   | 1,350,165            |      | 1,288,106 |   |
|                                                                    |   | 1,842,980            |      | 1,801,423 |   |
| Construction work in progress                                           |   | 403,512              |      | 191,233 |   |
|                                                                    |   | 2,246,492            |      | 1,992,656 |   |
|                                                                    |   |                 |      |   |   |
| Other property and investments - less reserve of  $130 in 2003 and 2002 |   | 17,862               |      | 14,358 |   |
|                                                                    |   |                 |      |   |   |
| Current assets:                                                         |   |                 |      |   |   |
| Cash and temporary cash investments (Note 1)                            |   | 4,869                |      | 5,391 |   |
| Accounts receivable-less reserve of $672 in 2003  and $800 in 2002      |   | 49,289               |      | 49,588 |   |
| Materials and supplies - at average cost:                               |   |                 |      |   |   |
| Fuel (predominantly coal) (Note 1)                                      |   | 45,538               |      | 46,090 |   |
| Other (Note 1)                                                          |   | 27,094               |      | 26,408 |   |
| Prepayments and other                                                   |   | 13,100               |      | 6,584 |   |
|                                                                    |   | 139,890              |      | 134,061 |   |
|                                                                    |   |                 |      |   |   |
| Deferred debits and other assets:                                       |   |                 |      |   |   |
| Unamortized debt expense (Note 1)                                       |   | 4,481                |      | 4,991 |   |
| Regulatory assets (Note 3)                                              |   | 69,222               |      | 67,987 |   |
| Long-term derivative asset                                              |   | 12,223               |      | 16,928 |   |
| Other                                                                   |   | 23,449               |      | 20,657 |   |
|                                                                    |   | 109,375              |      | 110,563 |   |
|                                                                    |   | $                    | 2,513,619 |   | $ | 2,251,638 |   |
| CAPITAL AND LIABILITIES:                                                |   |                 |      |   |   |
| Capitalization (see statements of capitalization):                      |   |                 |      |   |   |
| Common equity                                                           |   | $                    | 907,957   |   | $ | 814,380 |   |
| Cumulative preferred stock                                              |   | 39,727               |      | 39,727 |   |
|                                                                    |   | 947,684              |      | 854,107 |   |
|                                                                    |   |                 |      |   |   |
| Long-term debt:                                                         |   |                 |      |   |   |
| Long-term bonds (Note 9)                                                |   | 312,646              |      | 346,562 |   |
| Long-term notes to affiliated company (Note 9)                          |   | 283,000              |      | — |   |
|                                                                    |   | 595,646              |      | 346,562 |   |
|                                                                    |   | 1,543,330            |      | 1,200,669 |   |
|                                                                    |   |                 |      |   |   |
| Current liabilities:                                                    |   |                 |      |   |   |
| Current portion of long-term bonds (Note 9)                             |   | 91,930               |      | 153,930 |   |
| Notes payable to affiliated company (Notes 10 and  13)                  |   | 43,231               |      | 119,490 |   |
| Accounts payable                                                        |   | 69,947               |      | 67,536 |   |
| Accounts payable to affiliated companies (Note 13)                      |   | 26,426               |      | 27,838 |   |
| Accrued taxes                                                           |   | 8,809                |      | 4,955 |   |
| Customer deposits                                                       |   | 13,453               |      | 12,081 |   |
| Other                                                                   |   | 11,654               |      | 9,361 |   |
|                                                                    |   | 265,450              |      | 395,191 |   |
|                                                                    |   |                 |      |   |   |
| Deferred credits and other liabilities:                                 |   |                 |      |   |   |
| Accumulated deferred income taxes (Notes 1 and 7)                       |   | 261,258              |      | 241,184 |   |
| Investment tax credit, in process of amortization                       |   | 5,859                |      | 8,500 |   |
| Accumulated provision for pensions and related  benefits (Note 6)       |   | 103,101              |      | 110,927 |   |
| Asset retirement obligations                                            |   | 19,698               |      | — |   |
| Regulatory liabilities (Note 3)                                         |   |                 |      |   |   |
| Accumulated cost of removal of utility plant                            |   | 266,832              |      | 248,552 |   |
| Other                                                                   |   | 36,464               |      | 33,310 |   |
| Other                                                                   |   | 11,627               |      | 13,305 |   |
|                                                                    |   | 704,839              |      | 655,778 |   |
| Commitments and contingencies (Note 11)                                 |   |                 |      |   |   |
|                                                                    |   | $                    | 2,513,619 |   | $ | 2,251,638 |   |

 

Theaccompanying notes are an integral part of these consolidated financialstatements.

 

110

----

 

KentuckyUtilities Company and SubsidiaryConsolidated Statements of Cash Flows(Thousands of $)

 
|                                                        |   | **Years  Ended December 31** |    |
|-------------------------------------------------------------|--------|-----------------------------------|---------|
|                                                        |   | **2003**                          |    | **2002** |   | **2001** |   |
|                                                        |   |                              |    |   |   |   |   |
| CASH FLOWS FROM OPERATING ACTIVITIES:                       |   |                              |    |   |   |   |   |
| Net income                                                  |   | $                                 | 91,402  |   | $ | 93,384 |   | $ | 96,414 |   |
| Items not requiring cash currently:                         |   |                              |    |   |   |   |   |
| Depreciation and amortization                               |   | 101,805                           |    | 95,462 |   | 90,299 |   |
| Deferred income taxes - net                                 |   | 15,278                            |    | (2,038 | ) | (12,088 | ) |
| Investment tax credit - net                                 |   | (2,641                            | )       | (2,955 | ) | (3,446 | ) |
| LG&E/KU merger amortization                             |   | 2,046                             |    | 4,092 |   | 4,092 |   |
| VDT amortization                                            |   | 12,030                            |    | 11,500 |   | 5,000 |   |
| Mark-to-market financial instruments                        |   | 3,790                             |    | 1,386 |   | (2,651 | ) |
| One utility amortization                                    |   | 873                               |    | 3,492 |   | 3,908 |   |
| Other                                                       |   | 13,047                            |    | 3,814 |   | 4,839 |   |
| Change in certain net current assets:                       |   |                              |    |   |   |   |   |
| Accounts receivable                                         |   | (401                              | )       | (8,497 | ) | 28 |   |
| Materials and supplies                                      |   | (134                              | )       | (2,928 | ) | (31,263 | ) |
| Accounts payable                                            |   | 999                               |    | 10,225 |   | 8,810 |   |
| Accrued taxes                                               |   | 3,854                             |    | (15,565 | ) | 898 |   |
| Prepayments and other                                       |   | (2,851                            | )       | (2,350 | ) | (6,033 | ) |
| Sale of accounts receivable (Note 1)                        |   | 700                               |    | 4,200 |   | 45,100 |   |
| Pension funding                                             |   | (10,231                           | )       | (15,283 | ) | (1 | ) |
| VDT expense                                                 |   | (106                              | )       | (1,064 | ) | (53,811 | ) |
| Pension liability                                           |   | 3,509                             |    | 6,418 |   | 28,249 |   |
| Provision for post-retirement benefits                      |   | 4,248                             |    | 4,760 |   | 19,099 |   |
| Other                                                       |   | (208                              | )  | (12,296 | )  | (9,312 | ) |
| Net cash flows from operating activities                    |   | 237,009                           |    | 175,757 |   | 188,131 |   |
|                                                        |   |                              |    |   |   |   |   |
| CASH FLOWS FROM INVESTING ACTIVITIES:                       |   |                              |    |   |   |   |   |
| Proceeds from sales of securities                           |   | —                            |    | — |   | 3,480 |   |
| Long-term investments                                       |   | (3,504                            | )       | — |   | — |   |
| Construction expenditures                                   |   | (341,869                          | )       | (237,909 | ) | (142,425 | ) |
| Net cash flows from investing activities                    |   | (345,373                          | )       | (237,909 | ) | (138,945 | ) |
|                                                        |   |                              |    |   |   |   |   |
| CASH FLOWS FROM FINANCING ACTIVITIES:                       |   |                              |    |   |   |   |   |
| Long-term borrowings from affiliated  company               |   | 283,000                           |    | — |   | — |   |
| Short-term borrowings from affiliated  company              |   | 655,241                           |    | 518,400 |   | 357,685 |   |
| Repayment of short-term borrowings from  affiliated company |   | (731,500                          | )       | (446,700 | ) | (371,134 | ) |
| Retirement of first mortgage bonds                          |   | (95,000                           | )       | — |   | — |   |
| Issuance of pollution control bonds                         |   | —                            |    | 133,930 |   | — |   |
| Issuance expense on pollution control bonds                 |   | (1,643                            | )       | (5,196 | ) | — |   |
| Retirement of pollution control bonds                       |   | —                            |    | (133,930 | ) | — |   |
| Payment of dividends                                        |   | (2,256                            | )       | (2,256 | ) | (32,756 | ) |
| Net cash flows used for financing  activities               |   | 107,842                           |    | 64,248 |   | (46,205 | ) |
|                                                        |   |                              |    |   |   |   |   |
| Change in cash and temporary cash  investments              |   | (522                              | )       | 2,096 |   | 2,981 |   |
|                                                        |   |                              |    |   |   |   |   |
| Cash and temporary cash investments at  beginning of year   |   | 5,391                             |    | 3,295 |   | 314 |   |
|                                                        |   |                              |    |   |   |   |   |
| Cash and temporary cash investments at end  of year         |   | $                                 | 4,869   |   | $ | 5,391 |   | $ | 3,295 |   |
|                                                        |   |                              |    |   |   |   |   |
| Supplemental disclosures of cash flow  information:         |   |                              |    |   |   |   |   |
| Cash paid during the year for:                              |   |                              |    |   |   |   |   |
| Income taxes                                                |   | $                                 | 37,166  |   | $ | 59,580 |   | $ | 72,432 |   |
| Interest on borrowed money                                  |   | 20,204                            |    | 37,866 |   | 39,829 |   |
| Interest to affiliated companies on  borrowed money         |   | 3,533                             |    | 1,725 |   | 1,473 |   |

 

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

 

111

----

 

KentuckyUtilities Company and SubsidiaryConsolidated Statements of Capitalization(Thousands of $)

 
|                                                         |   | **December 31** |    |
|--------------------------------------------------------------|--------|----------------------|---------|
|                                                         |   | **2003**             |    | **2002** |   |
| COMMON EQUITY:                                               |   |                 |    |   |   |
| Common stock, without par value -                            |   |                 |    |   |   |
| authorized 80,000,000 shares, outstanding  37,817,878 shares |   | $                    | 308,140 |   | $ | 308,140 |   |
| Common stock expense                                         |   | (322                 | )       | (322 | ) |
| Additional paid-in-capital                                   |   | 15,000               |    | 15,000 |   |
| Accumulated other comprehensive income                       |   | (6,031               | )       | (10,462 | ) |
| Retained earnings                                            |   | 591,170              |    | 502,024 |   |
|                                                         |   |                 |    |   |   |
|                                                         |   | 907,957              |    | 814,380 |   |
|                                                              |        |                      |         |  |  |  |  |

 
|                                              |   | **Shares  Outstanding** |   | **Current  Redemption Price** |   |    |      |    |   |
|---------------------------------------------------|--------|-------------------------|--------|-------------------------------|--------|---------|-----------|---------|--------|
|                                              |   |                    |   |                          |   |    |      |    |   |
| CUMULATIVE PREFERRED STOCK:                       |   |                    |   |                          |   |    |      |    |   |
| Without par value, 5,300,000 shares  authorized - |   |                    |   |                          |   |    |      |    |   |
| 4.75% series, $100 stated value                   |   |                    |   |                          |   |    |      |    |   |
| Redeemable on 30 days notice by KU                |   | 200,000                 |   | $                             | 101.00 |    | 20,000    |    | 20,000 |   |
| 6.53% series, $100 stated value                   |   | 200,000                 |   | $                             | 103.27 |    | 20,000    |    | 20,000 |   |
| Preferred stock expense                           |   |                    |   |                          |   | (273    | )         | (273    | )      |
|                                              |   |                    |   |                          |   |    |      |    |   |
|                                              |   |                    |   |                          |   | 39,727  |      | 39,727  |   |
| LONG-TERM DEBT (Note 9):                          |   |                    |   |                          |   |    |      |    |   |
| First mortgage bonds:                             |   |                    |   |                          |   |    |      |    |   |
| Q due June 15, 2003, 6.32%                   |   |                    |   |                          |   | —  |      | 62,000  |   |
| S due January 15, 2006, 5.99%                |   |                    |   |                          |   | 36,000  |      | 36,000  |   |
| P due May 15, 2007, 7.92%                         |   |                    |   |                          |   | 53,000  |      | 53,000  |   |
| R due June 1, 2025, 7.55%                    |   |                    |   |                          |   | 50,000  |      | 50,000  |   |
| P due May 15, 2027, 8.55%                         |   |                    |   |                          |   | —  |      | 33,000  |   |
| Pollution control series:                         |   |                    |   |                          |   |    |      |    |   |
| 9, due December 1, 2023, 5.75%               |   |                    |   |                          |   | 50,000  |      | 50,000  |   |
| 10, due November 1, 2024, variable %         |   |                    |   |                          |   | 54,000  |      | 54,000  |   |
| 11, due May 1, 2023, variable %                   |   |                    |   |                          |   | 12,900  |      | 12,900  |   |
| 12, due February 1, 2032, variable %         |   |                    |   |                          |   | 20,930  |      | 20,930  |   |
| 13, due February 1, 2032, variable %         |   |                    |   |                          |   | 2,400   |      | 2,400   |   |
| 14, due February 1, 2032, variable %         |   |                    |   |                          |   | 7,400   |      | 7,400   |   |
| 15, due February 1, 2032, variable %         |   |                    |   |                          |   | 7,200   |      | 7,200   |   |
| 16, due October 1, 2032, variable %          |   |                    |   |                          |   | 96,000  |      | 96,000  |   |
| Notes payable to Fidelia:                         |   |                    |   |                          |   |    |      |    |   |
| Due April 30, 2013, 4.55%, unsecured         |   |                    |   |                          |   | 100,000 |      | —  |   |
| Due August 15, 2013, 5.31%, secured          |   |                    |   |                          |   | 75,000  |      | —  |   |
| Due November 24, 2010, 4.24%, secured        |   |                    |   |                          |   | 33,000  |      | —  |   |
| Due December 19, 2005, 2.29%, secured        |   |                    |   |                          |   | 75,000  |      | —  |   |
| Long-term debt marked to market (Note 4)          |   |                    |   |                          |   | 14,746  |      | 15,662  |   |
|                                              |   |                    |   |                          |   |    |      |    |   |
| Total long-term debt outstanding                  |   |                    |   |                          |   | 687,576 |      | 500,492 |   |
|                                              |   |                    |   |                          |   |    |      |    |   |
| Less current portion of long-term debt            |   |                    |   |                          |   | 91,930  |      | 153,930 |   |
|                                              |   |                    |   |                          |   |    |      |    |   |
| Long-term debt                                    |   |                    |   |                          |   | 595,646 |      | 346,562 |   |
|                                              |   |                    |   |                          |   |    |      |    |   |
| Total capitalization                              |   |                    |   |                          |   | $       | 1,543,330 |    | $      | 1,200,669 |   |
|                                                   |        |                         |        |                               |        |         |           |         |        |  |  |  |

 

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

 

112

----

 

KentuckyUtilities Company and SubsidiaryNotes to Consolidated Financial Statements

 

**Note 1 - Summary ofSignificant Accounting Policies**

 

KU, a subsidiary of LG&E Energy and an indirect subsidiary of E.ON,is a regulated public utility engaged in the generation, transmission,distribution, and sale of electric energy. LG&E Energy is a registered public utility holding company withwholly owned subsidiaries including LG&E, KU, Capital Corp., LEM, andLG&E Services.  All of KU’s commonstock is held by LG&E Energy.  KUhas one wholly owned consolidated subsidiary, KU R.  The consolidated financial statements include the accounts of KUand KU R with the elimination of intercompany accounts and transactions.

 

On December 11, 2000, LG&E Energy was acquired byPowergen.  On July 1, 2002, E.ON, aGerman company, completed its acquisition of Powergen plc (now PowergenLimited).  E.ON had announced its pre-conditional cash offer of £5.1billion ($7.3 billion) for Powergen on April 9, 2001.  Powergen and E.ON are registered public utilityholding companies under PUHCA.

 

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

 

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

 

Certain reclassification entries have been made to the previous years’financial statements to conform to the 2003 presentation with no impact on thebalance sheet net assets or previously reported income.

 

**RegulatoryAccounting. **Accountingfor the regulated utility business conforms with generally accepted accountingprinciples as applied to regulated public utilities and as prescribed by FERC,the Kentucky Commission and the Virginia Commission.  KU is subject to SFAS No. 71, *Accounting for the Effects of Certain Types ofRegulation*, under which certain costs that would otherwise becharged to expense are deferred as regulatory assets based on expected recoveryfrom customers in future rates. Likewise, certain credits that would otherwise be reflected as incomeare deferred as regulatory liabilities based on expected return to customers infuture rates.  KU’s current or expectedrecovery of deferred costs and expected return of deferred credits is generallybased on specific ratemaking decisions or precedent for each item.  See Note 3 for additional detail regardingregulatory assets and liabilities.

 

**Utility Plant.**  KU’s utility plant is stated at originalcost, which includes payroll-related costs such as taxes, fringe benefits, andadministrative and general costs. Construction work in progress has been included in the rate base fordetermining retail customer rates.  KUhas not recorded a significant allowance for funds used during construction.

 

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

 

**Depreciation andAmortization.** Depreciation is provided on the straight-line method over the estimatedservice lives of depreciable plant.  Theamounts provided were approximately 3.1% in 2003, 3.1% in 2002 and  3.1% in 2001, of average depreciable plant.Of the amount provided for depreciation at December 31, 2003,approximately 0.6% was related to the retirement, removal and disposal costs oflong lived assets.

 

113

----

 

**Cash and TemporaryCash Investments. **KUconsiders all debt instruments purchased with a maturity of three months orless to be cash equivalents.  Temporarycash investments are carried at cost, which approximates fair value.

 

**Fuel Inventory.**  Fuel inventories of $45.5 million and $46.1million at December 31, 2003 and 2002, respectively, are included in Fuelin the balance sheet.  The inventory isaccounted for using the average-cost method.

 

**Other Materials andSupplies.** Non-fuel materials and supplies of $27.1 million and $26.4 million atDecember 31, 2003 and 2002, respectively, are accounted for using theaverage-cost method.

 

**FinancialInstruments.** KU uses over-the-counter interest-rate swap agreements to hedge itsexposure to interest rates.  Gains andlosses on interest-rate swaps used to hedge interest rate risk are reflected ininterest charges monthly.  KU uses salesof market-traded electric forward contracts for periods less than one year tohedge the price volatility of its forecasted peak electric off-systemsales.  Gains and losses resulting fromineffectiveness are shown in other income (expense) and to the extent that thehedging relationship has been effective, gains and losses are reflected inother comprehensive income.  See Note 4– Financial Instruments.

 

**Unamortized DebtExpense.**  Debtexpense is capitalized in deferred debits and amortized over the lives of therelated bond issues, consistent with regulatory practices.

 

**Deferred IncomeTaxes.** Deferred income taxes are recognized at currently enacted tax rates forall material temporary differences between the financial reporting and incometax basis of assets and liabilities.

 

**Investment TaxCredits.** Investment tax credits resulted from provisions of the tax law thatpermitted a reduction of KU’s tax liability based on credits for certainconstruction expenditures.  Deferredinvestment tax credits are being amortized to income over the estimated livesof the related property that gave rise to the credits.

 

**Revenue Recognition.**  Revenues are recorded based on servicerendered to customers through month-end. KU accrues an estimate for unbilled revenues from each meter readingdate to the end of the accounting period based on allocating the daily systemnet deliveries between billed volumes and unbilled volumes.  The allocation is based on a daily ratio ofthe number of meter reading cycles remaining in the month to the total numberof meter reading cycles in each month. Each day’s ratio is then multiplied by each day’s system net deliveriesto determine an estimated billed and unbilled volume for each day of theaccounting period.  The unbilled revenueestimates included in accounts receivable were approximately $38.7 million and$36.4 million at December 31, 2003, and 2002, respectively.

 

**Allowance forDoubtful Accounts.** At December 31, 2003 and 2002, the KU allowance for doubtfulaccounts was $0.7 million and $0.8 million, respectively.  The allowance is based on the ratio of theamounts charged-off during the last twelve months to the retail revenues billedover the same period multiplied by the retail revenues billed over the lastfour months.  Accounts with no paymentactivity are charged-off after four months.

 

**Fuel Costs.**  The cost of fuel for electric generation ischarged to expense as used.

 

**Management’s Use ofEstimates.**  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, arerecorded when they are reasonable and estimable.  Actual results could differ from those estimates.  See Note 11,

 

114

----

 

Commitments and Contingencies, for a further discussion.

 

**New AccountingPronouncements.** The following accounting pronouncements were implemented by KU in 2003:

 

SFAS No. 143, *Accounting for Asset Retirement Obligations*was issued in 2001.  SFAS No. 143establishes accounting and reporting standards for obligations associated withthe retirement of tangible long-lived assets and the associated assetretirement costs.

 

The effective implementation date for SFAS No. 143 was January 1,2003.  Management has calculated theimpact of SFAS No. 143 and FERC Final Order No. 631 issued in Docket No.RM02-7, *Accounting,Financial Reporting, and Rate Filing Requirements for Asset RetirementObligations. *The Companyevaluated the impact of SFAS 143 from both a legal and operations perspective,reviewing applicable laws and regulations affecting the industry, contracts,permits, certificates of need and right of way agreements, to determine iflegal obligations existed.   The fairvalue of future removal obligations was calculated based on the Company’s engineeringestimates, costs expended for similar retirements and third party estimates atcurrent market prices inflated at a rate of 2.31% per year to the expectedretirement date of the asset.  Thefuture removal obligations were then discounted to their net present value atthe original asset in-service date based on a discount rate of 6.61%.  ARO assets equal to the net present valuewere recorded on the Company’s books at implementation.  An amount equal to the net present valueplus the accretion the Company would have accrued had the standard been ineffect at the original in-service date was also recorded on the Company’s booksas an ARO liability at implementation. Additionally, the Company contracted with an independent consultant toquantify the cost of removal included in its accumulated depreciation underregulatory accounting practices.

 

As of January 1, 2003, KU recorded asset retirement obligation(ARO) assets in the amount of $8.6 million and liabilities in the amount of$18.5 million.  KU also recorded acumulative effect adjustment in the amount of $9.9 million to reflect theaccumulated depreciation and accretion of ARO assets at the transition dateless amounts previously accrued under regulatory depreciation.  KU recorded offsetting regulatory assets of$9.9 million, pursuant to regulatory treatment prescribed under SFAS No. 71, *Accountingfor the Effects of Certain Types of Regulation*.  Also pursuant to SFAS No. 71, KU recordedregulatory liabilities in the amount of $0.9 million offsetting removal costspreviously accrued under regulatory accounting in excess of amounts allowedunder SFAS No. 143.

 

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

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

 

As of December 31, 2003, KU recorded ARO assets, net ofaccumulated depreciation, of $8.4 million and liabilities of $19.7million.  KU recorded regulatory assetsof $11.3 million and regulatory liabilities of $1.2 million.

 

For the year ended December 31, 2003, KU recorded ARO accretionexpense of $1.2 million, ARO depreciation expense of $0.2 million and an offsettingregulatory credit in the income statement of $1.4 million in 2003, pursuant toregulatory treatment prescribed under SFAS No. 71.  SFAS No. 143 has no impact on the results of the operation of KU.

 

KU AROs are primarily related to final retirement of assets associatedwith generating units.  For assetsassociated with AROs the removal cost accrued through depreciation underregulatory accounting is established as a regulatory asset or liabilitypursuant to regulatory treatment prescribed under SFAS No. 71.  For the year ended December 31, 2003,KU recorded $0.3 million in depreciation expense related to the cost of removalof ARO related assets.  An offsettingregulatory liability was established pursuant to regulatory treatmentprescribed under SFAS No. 71.

 

KU also continues to include a cost of removal component indepreciation for assets that do not have a legal ARO.  As of December 31, 2003 and 2002, KU has segregated thiscost of removal, included in accumulated depreciation, of $266.8 million and$248.6 million, respectively, in accordance with FERC Order No. 631*.* For reporting purposes in its Consolidated Balance Sheets, KU haspresented this cost of removal as a regulatory liability pursuant to SFAS No.71.

 

KU transmission and distribution lines largely operate under perpetualproperty easement agreements which do 

 

115

----

 

not generally require restoration upon removal of the property.  Therefore, under SFAS No. 143, no materialasset retirement obligations are recorded for transmission and distributionassets.

 

KU adopted EITF No. 98-10, *Accounting for Energy Trading and Risk ManagementActivities,*effective January 1, 1999.  This pronouncement required that energytrading contracts be marked to market on the balance sheet, with the gains andlosses shown net in the income statement. Effective January 1, 2003, KU adopted EITF No. 02-03, *IssuesInvolved in Accounting for Derivative Contracts Held for Trading Purposes andContracts Involved in Energy Trading and Risk Management Activities*.  EITF No. 02-03 established the following:

 

•                  Rescinded EITFNo. 98-10,

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

•                  Revenuesshould be shown in the income statement net of costs associatedwith trading activities, whether or not the trades are physically settled.

 

With the rescission of EITF No. 98-10, energy trading contracts that donot also meet the definition of a derivative under SFAS No. 133 must beaccounted for as executory contracts. Contracts previously recorded at fair value under EITF No. 98-10 thatare not also derivatives under SFAS No. 133, *Accounting for Derivative Instruments**and**HedgingActivities*, must be restated to historical cost through a cumulativeeffect adjustment.  The rescission ofthis standard had no impact on financial position or results of operations ofKU since all forward and option contracts marked to market under EITF No. 98-10were also within the scope of SFAS No. 133.

 

As a result of EITF No. 02-03, KU has nettedthe power purchased expense for trading activities against electric operatingrevenue to reflect this accounting change. KU applied this guidance to all prior periods, which had no impact onpreviously reported net income or common equity.

 
| **(in thousands of $)**                      |   | **2002** |    | **2001** |   |
|----------------------------------------------|--------|----------|---------|----------|--------|
|                                         |   |     |    |     |   |
| Gross electric operating revenues            |   | $        | 888,219 |     | $      | 859,472 |   |
| Less costs reclassified from power purchased |   | 26,555   |    | 38,751   |   |
| Net electric operating revenues reported     |   | $        | 861,664 |     | $      | 820,721 |   |
|                                         |   |     |    |     |   |
| Gross power purchased                        |   | $        | 157,955 |     | $      | 157,161 |   |
| Less costs reclassified to revenues          |   | 26,555   |    | 38,751   |   |
| Net power purchased reported                 |   | $        | 131,400 |     | $      | 118,410 |   |

 

InMay 2003, the Financial Accounting Standards Board issued SFAS No. 150, *Accountingfor Certain Financial Instruments with Characteristics of both Liabilities andEquity*.  SFAS No. 150 waseffective immediately for financial instruments entered into or modified afterMay 31, 2003, and otherwise was effective for interim reporting periodsbeginning after June 15, 2003, except for certain instruments and certainentities which have been deferred by the FASB. Such deferrals do not affect KU. KU has no financial instruments that fall within the scope of SFAS No.150.

 

In January 2003, the Financial Accounting Standards Board issuedFinancial Accounting Standards Board Interpretation No. 46, *Consolidationof Variable Interest Entities*, an Interpretation of ARB No. 51 (FIN46).  FIN 46 requires certain variableinterest entities to be consolidated by the primary beneficiary of the entityif the equity investors in the entity do not have the characteristics of acontrolling financial interest or do not have sufficient equity at risk for theentity to finance its activities without additional subordinated financialsupport 

 

116

----

 

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

 

In December 2003, FIN 46 was revised, delaying the effective datesfor certain entities created before February 1, 2003, and making otheramendments to clarify application of the guidance.  For potential variable interest entities other than an specialpurpose entities, the revised FIN 46 (FIN 46R) is now required to be applied nolater than the end of the first fiscal year or interim reporting period endingafter March 15, 2004.  The originalguidance under FIN 46 was applicable, however, for all special purpose entitiescreated prior to February 1, 2003, at the end of the first interim orannual reporting period ending after December 15, 2003.  FIN 46R may be applied prospectively with acumulative-effect adjustment as of the date it is first applied, or byrestating previously issued financial statements with a cumulative-effectadjustment as of the beginning of the first year restated.  FIN 46R also requires certain disclosures ofan entity’s relationship with variable interest entities.

 

KU has no special purpose entities that fall within the scope of FIN46R. LG&E continues to evaluate the impact that FIN 46R may have on itsfinancial position and results of operations.

 

# **Note2 – Mergers and Acquisitions**

 

OnJuly 1, 2002, E.ON completed its acquisition of Powergen, includingLG&E Energy, for approximately £5.1 billion ($7.3 billion).  As a result of the acquisition, LG&EEnergy became a wholly owned subsidiary (through Powergen) of E.ON and, as aresult, KU also became an indirect subsidiary of E.ON.  KU has continued its separate identity andserves customers in Kentucky, Virginia and Tennessee under its existingnames.  The preferred stock and debtsecurities of KU were not affected by this transaction and the utilitiescontinue to file SEC reports.  Followingthe acquisition, E.ON became, and Powergen remained, a registered holdingcompany under PUHCA.  KU, as asubsidiary of a registered holding company, is subject to additionalregulations under PUHCA.  Ascontemplated in their regulatory filings in connection with the E.ONacquisition, E.ON, Powergen and LG&E Energy completed an administrativereorganization to move the LG&E Energy group from an indirect Powergensubsidiary to an indirect E.ON subsidiary. This reorganization was effective in March 2003. In early 2004,LG&E Energy commenced direct reporting arrangements to E.ON.

 

LG&E Energy and KU Energy merged on May 4, 1998, with LG&EEnergy as the surviving corporation. Management accounted for the merger as apooling of interests and as a tax-free reorganization under the InternalRevenue Code.  Following theseacquisitions, KU has continued to maintain its separate identity and servecustomers under its present name.

 

**Note 3 - Rates andRegulatory Matters**

 

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

 
| **(in  thousands)**                          |   | **2003** |     | **2002** |   |
|----------------------------------------------|--------|----------|----------|----------|--------|
|                                         |   |     |     |     |   |
| VDT costs                                    |   | $        | 26,451   |     | $      | 38,375 |   |
| Unamortized loss on bonds                    |   | 10,511   |     | 9,456    |   |
| ESM provision                                |   | 12,382   |     | 13,500   |   |
| VA FAC                                       |   | 4,298    |     | 4,703    |   |
| LG&E/KU merger costs                     |   | —   |     | 2,046    |   |
| Merger surcredit                             |   | 4,815    |     | —   |   |
| One utility costs                            |   | —   |     | 873      |   |
| ARO                                          |   | 11,322   |     | —   |   |
| DSM                                          |   | (1,563   | )        | (1,628   | )      |
| Post retirement and pension                  |   | 1,006    |     | 662      |   |
| Total regulatory assets                      |   | $        | 69,222   |     | $      | 67,987 |   |
|                                         |   |     |     |     |   |
| Accumulated cost of removal of utility plant |   | $        | (266,832 | )        | $      | (248,552 | ) |
| Deferred income taxes - net                  |   | (24,058  | )        | (28,854  | )      |
| ARO                                          |   | (1,162   | )        | —   |   |
| Spare parts                                  |   | (1,055   | )        | (1,022   | )      |
| ESM                                          |   | —   |     | (472     | )      |
| ECR                                          |   | (9,189   | )        | (2,962   | )      |
| FAC                                          |   | (1,000   | )        | —   |   |
| Total regulatory liabilities                 |   | $        | (303,296 | )        | $      | (281,862 | ) |

 

117

----

 

KU currently earns a return on all regulatory assets except for ESM,DSM and FAC, all of which are separate recovery mechanisms with recovery withintwelve months.  Additionally, no currentreturn is earned on the ARO regulatory asset. This regulatory asset will be offset against the associated regulatoryliability, ARO asset, and ARO liability at the time the underlying asset isretired.

 

**Kentucky CommissionSettlement Order - VDT Costs.**During the first quarterof 2001, KU recorded a $64 million charge for a workforce reductionprogram.  Primary components of thecharge were separation benefits, enhanced early retirement benefits, andhealthcare benefits.  The result of thisworkforce reduction was the elimination of approximately 300 positions,accomplished primarily through a voluntary enhanced severance program.

 

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

 

KU reached a settlement in the VDT case as well as other casesinvolving the depreciation rates and ESM with all intervening parties.  The settlement agreement was approved by theKentucky Commission in December 2001. The order allowed KU to set up a regulatory asset of $54 million for theworkforce reduction costs and begin amortizing these costs over a five-yearperiod starting in April 2001. The first quarter 2001 charge of $64million represented all employees who had accepted a voluntary enhancedseverance program.  Some employees rescindedtheir participation in the voluntary enhanced severance program and, along withthe non-recurring charge of $6.9 million for FERC and Virginia jurisdictions,thereby decreasing the original charge to the regulatory asset from $64 millionto $54 million. The settlement reduces revenues approximately $11 millionthrough a surcredit on bills to ratepayers over the same five-year period.  The surcredit represents net savingsstipulated by KU.  The agreement alsoestablished KU’s new depreciation rates in effect December 2001,retroactive to January 2001.  Thenew depreciation rates decreased depreciation expense by $6.0 million in 2001.

 

**PUHCA.**  Following thepurchases of LG&E Energy by Powergen and Powergen by E.ON, Powergen andE.ON became registered holding companies under PUHCA.  As a result, E.ON, its utility subsidiaries, including KU, andcertain of its non-utility subsidiaries are subject to extensive regulation bythe SEC under PUHCA with respect to issuances and sales of securities,acquisitions and sales of certain utility properties, and intra-system sales ofcertain goods and services.  Inaddition, PUHCA generally limits the ability of registered holding companies toacquire additional public utility systems and to acquire and retain businesses unrelatedto the utility operations of the holding company.  KU believes that it has adequate authority (including financingauthority) under existing SEC orders and regulations to conduct itsbusiness.  KU will seek additionalauthorization when necessary.

 

118

----

 

**ECR.**  In August 2002, KU filed an applicationwith the Kentucky Commission to amend its compliance plan to allow recovery ofthe cost of a new and additional environmental compliance facility.  The estimated capital cost of the additionalfacilities is $17.3 million.  A finalorder was issued in February 2003. The final order approved recovery ofthe new environmental compliance facility totaling $17.3 million.  Cost recovery through the environmentalsurcharge of the approved project commenced with bills rendered inApril 2003.

 

In March 2003, the Kentucky Commissioninitiated a series of six-month and two-year reviews of the operation of KU’sEnvironmental Surcharge.  A final orderwas issued on October 17, 2003 resolving all outstanding issues related toover-recovery from customers and under-recovery of allowed O&Mexpense.  The Commission found that KUhad over-collected a net $6.0 million from customers and ordered the refund tooccur through adjustments to the calculation of the monthly surcharge billingfactor over the subsequent 12 month period. The Commission further ordered KU to roll $17.9 million of environmentalassets into base rates and make corresponding adjustment in the monthly environmentalsurcharge filings to reflect that portion of environmental rate base nowincluded in base rates going forward. The rates of return for KU’s 1994 and post-1994 plans were reset to1.24% and 12.60%, respectively.

 

**ESM.**KU’s electric rates are subject to an ESM. The ESM, initially in place for three years beginning in 2000, sets anupper and lower point for rate of return on equity, whereby if KU’s rate ofreturn for the calendar year falls within the range of 10.5% to 12.5%, noaction is necessary.  If earnings areabove the upper limit, the excess earnings are shared 40% with ratepayers and60% with shareholders; if earnings are below the lower limit, the earningsdeficiency is recovered 40% from ratepayers and 60% from shareholders.  By order of the Kentucky Commission, ratechanges prompted by the ESM filing go into effect in April of each yearsubject to a balancing adjustment in successive periods.

 

In November 2002, KU filed a revised ESM tariff which proposedcontinuance of the existing ESM through December 2005.  In addition, the Kentucky Commission initiateda focused management audit to review the ESM plan and reassess itsreasonableness, and recently concluded discovery in the case.  KU and interested parties had theopportunity to provide recommendations for modification and continuance of theESM or other forms of alternative or incentive regulation.  Continuance of the ESM is still beingdeliberated by the Kentucky Commission and a final order is not expected untilthe second quarter.  The ESM tariffremains in effect pending the resolution of the case.

 

KU made its third ESM filing in February 2003 for the calendaryear 2002 reporting period.  KU is inthe process of recovering $11.6 million from ratepayers for the 2002 reportingperiod.  KU estimated that the rate ofreturn will fall below the lower limit, subject to Kentucky Commissionapproval, for the year ended December 31, 2003.  The 2003 financial statements include an accrual to reflect theearnings deficiency of $9.3 million to be recovered from customers commencingin April 2004.

 

# **DSM.** In May 2001, the Kentucky Commission approveda plan that would expand LG&E’scurrent DSM programsinto the service territory served by KU. The plan included a rate mechanism that provided for concurrent recoveryof DSM costs, provided an incentive for implementing DSM programs, andrecovered revenues from lost sales associated with the DSM programs based onprogram plan engineering estimates and post-implementation evaluation.

# ** **

**FAC. **KU employs an FAC mechanism, which allows underKentucky law, KU to recover from customers’ fuel costs associated with retailelectric sales.  InJuly 1999, the Kentucky Commission issued a series of orders requiring KUto refund approximately $10.1 million resulting from reviews of the FAC fromNovember 1994 to October 1998. In August 1999, after a rehearing request by KU, the KentuckyCommission issued a final order that reduced the refund obligation to $6.7million ($5.8 million on a Kentucky jurisdictional basis) from the 

 

119

----

 

original order amount of $10.1 million.  KU implemented the refund from October 1999 throughSeptember 2000.  Both KU and theKIUC appealed the order.  Pending a decision on this appeal, a comprehensivesettlement was reached by all parties and approved by the Kentucky Commissionin May 2002.  Thereunder, KU agreed tocredit its fuel clause in the amount of $1.0 million (refund made inJune and July 2002), and the parties agreed on a prospectiveinterpretation of the state’s FAC regulation to ensure consistent and mutuallyacceptable application going forward.

 

In January2003, the Kentucky Commission reviewed KU’s FAC for the six month period endedOctober 31, 2002. The Kentucky Commission ordered KU to reduce its fuel costsfor purposes of calculating its FAC by $0.7 million. At issue was the purchaseof approximately 102,000 tons of coal from Western Kentucky Energy Corporation,a non-regulated affiliate, for use at KU’s Ghent facility. The KentuckyCommission further ordered that an independent audit be conducted to examineoperational and management aspects of both KU’s and LG&E’s fuel procurementfunctions.  A final report was issued inFebruary 2004.  The report’srecommendations related to documentation and process improvements will beaddressed with the Kentucky Commission staff as Management Audit Plans aredeveloped in the second quarter of 2004.

 

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. KU also employs a FAC mechanism for Virginia customers that uses anaverage fuel cost factor based primarily on projected fuel costs.  The fuel cost factor may be adjustedannually for over or under collections of fuel costs from the previousyear.  No other significant issues havebeen identified as a result of these reviews.

 

**Electric Rate Case.**  In December 2003, KU filed anapplication with the Kentucky Commission requesting an adjustment in KU’selectric rates.  KU asked for a generaladjustment in electric rates based on a twelve month test year endedSeptember 30, 2003.  The revenueincrease requested was $58.3 million.  TheKentucky Commission has suspended the effective date of the proposed newtariffs for five months, so that the rates may go into effect subject to refundby July 1, 2004.  The KentuckyCommission established a procedural schedule for the case pertaining todiscovery and a hearing.  The hearingwill be held in May 2004.  KU expectsthe Kentucky Commission to issue an order in the case before new rates go intoeffect July 1, 2004.

 

**Kentucky CommissionAdministrative Case for Affiliate Transactions. **In December 1997, the KentuckyCommission opened Administrative Case No. 369 to consider Kentucky Commissionpolicy regarding cost allocations, affiliate transactions and codes of conductgoverning the relationship between utilities and their non-utility operationsand affiliates.  The Kentucky Commissionintended to address two major areas in the proceedings: the tools andconditions needed to prevent cost shifting and cross-subsidization betweenregulated and non-utility operations; and whether a code of conduct should beestablished to assure that non-utility segments of the holding company are notengaged in practices that could result in unfair competition caused by costshifting from the non-utility affiliate to the utility.  In early 2000, the Kentucky General Assemblyenacted legislation, House Bill 897, which authorized the Kentucky Commissionto require utilities that provide nonregulated activities to keep separateaccounts and allocate costs in accordance with procedures established by theKentucky Commission. In the same bill, the General Assembly set forthprovisions to govern a utility’s activities related to the sharing ofinformation, databases, and resources between its employees or an affiliateinvolved in the marketing or the provision of nonregulated activities and itsemployees or an affiliate involved in the provision of regulated services. Thelegislation became law in July 2000 and KU has been operating pursuantthereto since that time.  In February 2001,the Kentucky Commission published notice of their intent to promulgate newadministrative regulations under the auspices of this new law.  This effort is still on-going.

 

**KentuckyCommission Administrative Case for System Adequacy. **In June 2001, Kentucky’s Governor 

 

120

----

 

issued Executive Order 2001-771, which directed the Kentucky Commissionto review and study issues relating to the need for and development of newelectric generating capacity in Kentucky. In response to that Executive Order, the Kentucky Commission openedAdministrative Case No. 387 to review the adequacy of Kentucky’s generationcapacity and transmission system. Specifically, the items reviewed were the appropriate level of reliance onpurchased 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, theKentucky Commission issued an order in which it noted that KU is responsiblyaddressing the long-term supply needs of native load customers and that currentreserve margins are appropriate. However, due to the rapid pace of change in the industry, the order alsorequires KU to provide an annual assessment of supply resources, future demand,reserve margin, and the need for new resources.

 

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

 

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

 

**FERC SMD NOPR. **In July 2002,the FERC issued a NOPR in Docket No. RM01-12-000 which would substantiallyalter the regulations governing the nation’s wholesale electricity markets byestablishing a common set of rules, SMD. The SMD NOPR would require each publicutility that owns, operates, or controls interstate transmission facilities tobecome an Independent Transmission Provider (ITP), belong to a RTO that is anITP, or contract with an ITP for operation of its transmission assets. It wouldalso establish a standardized congestion management system, real-time andday-ahead energy markets, and a single transmission service for network andpoint-to-point transmission customers. Review of the proposed rulemaking isunderway and no timeframe has been established by the FERC for adoption of afinal rule.  While it is expected thatthe SMD final rule will affect KU revenues and expenses, the specific impact ofthe rulemaking is not known at this time.

 

**MISO. **KU and LG&E arefounding members of the MISO.  Membershipwas obtained in 1998 in response to and consistent with federal policyinitiatives.  In February 2002, KUand LG&E turned over operational control of their high voltage transmissionfacilities (100kV and above) to the MISO. The MISO currently controls over 100,000 miles of transmission over 1.1million square miles located in the northern Midwest between Manitoba, Canadaand Kentucky.  In September 2002,FERC granted a 12.88% ROE on transmission facilities for KU, LG&E, and therest of the MISO owners.

 

In October 2001, the FERC issued an order requiring that thebundled retail load and grandfathered wholesale load of each membertransmission owner be included in the current calculation of the MISO’s“cost-adder,” the Schedule 10 charges designed to recover the MISO’s costsof operation, including start-up capital (debt) costs.  KU and LG&E, along with several other transmissionowners, opposed the FERC’s ruling on this matter. The opposition was rejectedby the FERC in 2002.  Later that year,the MISO’s transmission owners, appealed the FERC’s decision to the UnitedStates Court of Appeals for the District of Columbia Circuit.  In response in November 2002, the FERCrequested that the Court issue a partial remand of its challenged orders toallow the FERC to revisit certain issues, and requested that the case be heldin abeyance pending the agency’s resolution of such issues.  The Court granted the FERC’s petition inDecember 2002.  InFebruary 2003, FERC issued an order reaffirming its position concerningthe calculation of the Schedule 10 charges and in July 2003 denied arehearing.  KU and LG&E, along withseveral other transmission owners, have again petitioned the District Court ofColumbia Circuit for review.  This caseis currently pending.

 

121

----

 

As a separate matter, MISO, its transmission owners and other interestedindustry segments reached a settlement in mid-2002 regarding the level**ofcost responsibility properly borne by bundled and grandfathered load underthese FERC rulings (such settlement expressly not prejudicing the transmissionowners’ and KU’s right to challenge the FERC’s ruling imposing costresponsibility on bundled loads in the first instance).  In February 2003, FERC accepted apartial settlement between MISO and the transmission owners.  FERC did not accept the only contestedsection of the settlement, which would have allowed the transmissionowners to immediately treat unrecoverable Schedule 10 charges asregulatory assets.  FERC will considerallowing regulatory asset treatment of unrecoverable Schedule 10 chargeson a case-by-case basis.

 

The MISO plans to implement a congestion management system inDecember 2004, in compliance with FERC Order 2000.  This system will be similar to theLocational Marginal Pricing (LMP) system currently used by the PJM RTO andcontemplated in FERC’s SMD NOPR, currently being discussed.  The MISO filed with FERC a mechanism forrecovery of costs for the congestion management system.  They proposed the addition of two newSchedules, 16 and 17.  Schedule 16is the MISO’s cost recovery mechanism for the Financial Transmission RightsAdministrative Service it will provide. Schedule 17 is the MISO’s mechanism for recovering costs it willincur for providing Energy Marketing Support Administrative Service.  The MISO transmission owners, including KUand LG&E, have objected to the allocation of costs among marketparticipants and retail native load.  Ahearing at FERC has been completed, but a ruling has not been issued.

 

The Kentucky Commission opened an investigation into KU’s andLG&E’s membership in MISO in July 2003.  The Kentucky Commission directed KU and LG&E to filetestimony addressing the costs and benefits of MISO membership both currentlyand over the next five years and other legal issues surrounding continuedmembership.  LG&E and KU engaged anindependent third-party to conduct a cost benefit analysis on this issue.  The information was filed with the KentuckyCommission in September 2003.  Theanalysis and testimony supported the exit from MISO, under certainconditions.  The MISO filed its owntestimony and cost benefit analysis in December 2003.  A final Kentucky Commission order isexpected in the second quarter of 2004.

 

**ARO.**  In 2003, KU recorded approximately $11.3million in regulatory assets and approximately $1.2 million in regulatoryliabilities related to SFAS No. 143, *Accounting for Asset Retirement Obligations*.

 

**Accumulated Cost ofRemoval.**  As ofDecember 31, 2003 and 2002, KU has segregated the cost of removal,embedded in accumulated depreciation, of $266.8 million and $248.6 million,respectively, in accordance with FERC Order No. 631*.*  For reportingpurposes in the Consolidated Balance Sheet, KU has presented this cost ofremoval as a regulatory liability pursuant to SFAS No. 71.

 

**Merger Surcredit**.  As part of the LG&E Energy merger withKU Energy, KU estimated non-fuel savings over a ten-year period following themerger.  Costs to achieve these savingsfor KU of $42.3 million were recorded in the second quarter of 1998, $20.5million of which was deferred and amortized over a five-year period pursuant toregulatory orders.  Primary componentsof the merger costs were separation benefits, relocation costs, and transactionfees, the majority of which were paid by December 31, 1998.  KU expensed the remaining costs associatedwith the merger ($21.8 million) in the second quarter of 1998.

 

In approving the merger, the Kentucky Commission adopted KU’s proposalto reduce its retail customers’ bills based on one-half of the estimatedmerger-related savings, net of deferred and amortized amounts, over a five-yearperiod.  The surcredit mechanismprovides that 50% of the net non-fuel cost savings estimated to be LG&E andKU, over a five-year period.  Thesurcredit was allocated 53% to KU and 47% to LG&E.  In that same order, the Commission requiredLG&E and KU, after the end of the five-year period, to present a plan for 

 

122

----

 

sharing with ratepayers the then-projected non-fuel savings associatedwith 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 Kentucky Commission issued an order approvinga settlement agreement reached with the parties in the case.  KU’s merger surcredit will remain in placefor another five-year term beginning July 1, 2003 and the merger savingswill continue to be shared 50% with ratepayers and 50%/with shareholders.

 

Any fuel cost savings are passed to Kentucky customers through the fueladjustment clauses.  See FAC above.

 

**Note 4 - FinancialInstruments**

 

The cost and estimated fair values of KU’s non-trading financialinstruments as of December 31, 2003, and 2002 follow:

 
|                                       |   | **2003** |    | **2002**        |   |
|--------------------------------------------|--------|----------|---------|-----------------|--------|
| **(in thousands)**                         |   | **Cost** |    | **Fair  Value** |   | **Cost** |   | **Fair  Value** |   |
|                                       |   |     |    |            |   |   |   |   |   |
| Long-term debt (including current portion) |   | $        | 389,830 |            | $      | 405,439 |   | $ | 484,830 |   | $ | 503,194 |   |
|                                       |   |     |    |            |   |   |   |   |   |
| Long-term debt from associates             |   | 283,000  |    | 288,292         |   | — |   | — |   |
| Interest-rate swaps                        |   | —   |    | 12,223          |   | — |   | 16,928 |   |
|                                            |        |          |         |                 |        |  |  |  |  |  |  |  |  |

 

All of the above valuations reflect prices quoted by exchanges exceptfor the swaps and the intercompany loans. The fair values of the swaps and intercompany loans reflect price quotesfrom dealers or amounts calculated using accepted pricing models.

 

**InterestRate Swaps.**  KUuses interest rate swaps to hedge exposure to market fluctuations in certain ofits debt instruments.  Pursuant topolicy, use of these financial instruments is intended to mitigate risk andearnings volatility and is not speculative in nature.  Management has designated all of the interest rate swaps as hedgeinstruments.  Financial instrumentsdesignated as fair value hedges are periodically marked to market with theresulting gains and losses recorded directly into net income to correspond withincome or expense recognized from changes in market value of the items beinghedged.

 

As of December 31, 2003 and 2002, KU was party to various interestrate swap agreements with aggregate notional amounts of $153 million in 2003and 2002.  Under these swap agreements,KU paid variable rates based on either LIBOR or the Bond Market Association’smunicipal swap index averaging 1.85% and 2.36%, and received fixed ratesaveraging 7.13% and 7.13% at December 31, 2003 and 2002, respectively. Theswap agreements in effect at December 31, 2003 have been designated asfair value hedges and mature on dates ranging from 2007 to 2025.  For 2003, the effect of marking thesefinancial instruments and the underlying debt to market resulted in immaterialpretax gains recorded in interest expense. Upon expiration of these hedges, any resulting gain or loss will beamortized over the remaining term of the related debt.

 

Interest rate swaps hedge interest rate risk on the underlying debtunder SFAS No. 133, in addition to swaps being marked to market, the item beinghedged must also be marked to market, consequently at December 31, 2003,KU’s debt reflects a $14.7 million mark to market adjustment.

 

123

----

 

# **In February 2004, KUterminated the swap it had in place at December 31, 2003 related to theSeries 9 pollution control bonds.  Thenotional amount of the terminated swap was $50 million and KU received apayment of $2.0 million as part of the termination.  The swap was terminated because it was no longer an effectivehedge of the underlying bond.**

# ** **

# **EnergyTrading & Risk Management Activities. **KU conducts energy trading and risk management activities to maximizethe value of power sales from physical assets it owns, in addition to thewholesale sale of excess asset capacity. Certain energy trading activities are accounted for on a mark-to-marketbasis in accordance with SFAS No. 133*, Accounting for Derivative Instruments and HedgingActivities,* and SFAS No. 138*, Accounting for Certain Derivative Instruments andCertain Hedging Activities*. Wholesale sales of excess asset capacity and wholesale purchases aretreated as normal sales and purchases under SFAS No. 133 and SFAS No. 138 andare not marked-to-market.

# ** **

The rescission of EITF 98-10,effective for fiscal years after December 15, 2002, will have no impact onKU’s energy trading and risk management reporting as all forward and optioncontracts marked to market under EITF 98-10 are also within the scope of SFAS No. 133.

 

The table belowsummarizes KU’s energy trading and risk management activities for 2003 and2002.

 
| **(in thousands)**                                             |   | **2003** |   | **2002** |   |
|----------------------------------------------------------------|--------|----------|--------|----------|--------|
| Fair value of contracts at beginning of period, net  liability |   | $        | (156   | )        | $      | (186 | ) |
| Fair value of contracts when entered into during  the period   |   | 2,654    |   | (65      | )      |
| Contracts realized or otherwise settled during the  period     |   | (569     | )      | 448      |   |
| Changes in fair values due to changes in assumptions           |   | (1,357   | )      | (353     | )      |
| Fair value of contracts at end of period, net  liability       |   | $        | 572    |     | $      | (156 | ) |

 

No changes to valuationtechniques for energy trading and risk management activities occurred during2003.  Changes in market pricing,interest rate and volatility assumptions were made during both years.  All contracts outstanding at December 31,2003, have a maturity of less than one year and are valued using pricesactively quoted for proposed or executed transactions or quoted by brokers.

 

KU maintains policies intended to minimize credit risk and revaluescredit exposures daily to monitor compliance with those policies.  At December 31, 2003, 100% of thetrading and risk management commitments were with counterparties ratedBBB-/Baa3 equivalent or better.

 

KU hedges the price volatility of its forecasted peak electricoff-system sales with the sales of market-traded electric forward contracts forperiods less than one year.  Theseelectric forward sales have been designated as cashflow hedges and are notspeculative in nature.  Gains or losseson these instruments, to the extent that the hedging relationship has beeneffective, are deferred in other comprehensive income.  Gains and losses resulting fromineffectiveness are shown in KU’s Consolidated Statements of Income in otherincome (expense) – net.  Upon expirationof these instruments, the amount recorded in other comprehensive income isrecorded in earnings.  In 2003, KUrecognized a pre-tax loss of approximately $18,000, and a loss, net of tax,deferred in other comprehensive income of approximately $147,000.

 

**Accounts Receivable Securitization. **On February 6,2001, KU implemented an accounts receivable securitization program.  The purpose of this program was to enable KUto accelerate the receipt of cash from the collection of retail accountsreceivable, thereby reducing dependence upon more costly sources of workingcapital. The securitization program allowed for a percentage of eligiblereceivables to be sold.  Eligiblereceivables were generally all receivables associated with retail sales thathave standard terms and are not past due. KU was able to terminate this program at any time without penalty.

 

124

----

 

KU terminated the accounts receivable securitization program inJanuary 2004 and replaced it with long-term loans from an E.ONaffiliate.  The accounts receivableprogram required KU R to maintain minimum levels of net worth.  The program also contained a cross-defaultprovision if KU defaulted on debt obligations in excess of $25 million.  If there was a significant deterioration inthe payment record of the receivables by the retail customers or if KU failedto meet certain covenants regarding the program, the program could terminate atthe election of the financial institutions. In this case, payments from retail customers would first be used torepay the financial institutions participating in the program, and would thenbe available for use by KU.  KU did notviolate any covenants with regard to the accounts receivable securitization program.

 

As part of the program, KU sold retail accounts receivables to a whollyowned subsidiary, KU R.  Simultaneously,KU R entered into two separate three-year accounts receivable securitizationfacilities with two financial institutions and their affiliates whereby KU Rcould sell, on a revolving basis, an undivided interest in certain of itsreceivables and receive up to $50 million from an unrelated third-partypurchaser.  The effective cost of thereceivables program was comparable to KU’s lowest cost source of capital, andwas based on prime rated commercial paper. KU retained servicing rights of thesold receivables through two separate servicing agreements with the third-partypurchaser.  KU obtained an opinion fromindependent legal counsel indicating these transactions qualified as a truesale of receivables.  As ofDecember 31, 2003, the outstanding program balance was $50.0 million.

 

To determine KU’s retained interest, the proceeds on the sale ofreceivables to the financial institutions was netted against the amount ofeligible receivables sold by KU to KU R. Interest expense, program fees, and facility fees paid to the financialinstitutions and an allowance for doubtful accounts were deducted to arrive atthe future value of retained interest. The future value was discounted using the prime rate plus 25 basispoints, assuming a 45-day receivable life. Pre-tax gains and losses from the sale of the receivables in 2003, 2002and 2001 were a gain of $41,057, and losses of $317 and $155,734, respectively.  KU’s net cash flows from KU R were $(0.1)million, $3.3 million and $43.5 million for 2003, 2002 and 2001, respectively.

 

The allowance for doubtful accounts associated with the eligiblesecuritized receivables at December 31 was $0.5 million in 2003, 2002 and2001.  This allowance was based onhistorical experience of KU. Each securitization facility contained a fullyfunded reserve for uncollectible receivables.

 

**Note 5 -Concentrations of Credit and Other Risk**

 

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

 

KU’s customer receivables and revenues arise from deliveries ofelectricity to approximately 482,000 customers in over 600 communities and adjacentsuburban and rural areas in 77 counties in central, southeastern and westernKentucky, to approximately 30,000 customers in five counties in southwesternVirginia and less than ten customers in Tennessee.  For the year ended December 31, 2003, 100% of total utilityrevenue was derived from electric operations.

 

In August 2003, KU and itsemployees represented by IBEW Local 2100 entered into a three-year collectivebargaining agreement. KU and its employees represented by USWA Local 9447-01entered into a three-year

 

125

----

collective bargaining agreement effectiveAugust 2002 and expiring August 2005.  The employees represented by these two bargaining units compriseapproximately 16% of KU’sworkforce.

 

**Note 6 - PensionPlans and Other Postretirement Benefit Plans**

 

KU has both funded and unfunded noncontributory defined benefit pensionplans and other postretirement benefit plans that together cover substantiallyall of its employees.  The healthcareplans are contributory with participants’ contributions adjusted annually.

 

KU uses December 31 as the measurement date for its plans.

 

**Obligations & Funded Status. **The following tableprovides a reconciliation of the changes in the plan’s benefit obligations andfair value of assets over the three-year period ending December 31, 2003,and a statement of the funded status as of December 31, 2003, for KU’ssponsored defined benefit plan:

 
| **(in thousands)**                                        |   | **2003** |     | **2002** |   | **2001** |   |
|-----------------------------------------------------------|--------|----------|----------|----------|--------|----------|--------|
| Pension Plans:                                            |   |     |     |     |   |     |   |
| Change in benefit obligation                              |   |     |     |     |   |     |   |
| Benefit obligation at beginning of year                   |   | $        | 247,727  |     | $      | 244,472  |   | $ | 233,034 |   |
| Service cost                                              |   | 2,962    |     | 2,637    |   | 2,761    |   |
| Interest cost                                             |   | 15,924   |     | 16,598   |   | 17,534   |   |
| Plan amendment                                            |   | 40       |     | 28       |   | 4        |   |
| Change due to transfers                                   |   | (269     | )        | —   |   | (16,827  | )      |
| Curtailment loss                                          |   | —   |     | —   |   | 1,400    |   |
| Special termination benefits                              |   | —   |     | —   |   | 24,274   |   |
| Benefits and lump sums paid                               |   | (22,594  | )        | (23,291  | )      | (29,166  | )      |
| Actuarial (gain) or loss and other                        |   | 13,915   |     | 7,283    |   | 11,458   |   |
| Benefit obligation at end of year                         |   | $        | 257,705  |     | $      | 247,727  |   | $ | 244,472 |   |
|                                                      |   |     |     |     |   |     |   |
| Change in plan assets                                     |   |     |     |     |   |     |   |
| Fair value of plan assets at beginning of  year           |   | $        | 178,534  |     | $      | 216,947  |   | $ | 244,677 |   |
| Actual return on plan assets                              |   | 36,528   |     | (13,767  | )      | 18,155   |   |
| Employer contributions                                    |   | 10,231   |     | 15,283   |   | 1        |   |
| Changes due to transfers                                  |   | (206     | )        | (15,382  | )      | (15,301  | )      |
| Benefits and lump sums paid                               |   | (22,594  | )        | (23,291  | )      | (29,166  | )      |
| Administrative expenses                                   |   | (1,400   | )        | (1,256   | )      | (1,419   | )      |
| Fair value of plan assets at end of year                  |   | $        | 201,093  |     | $      | 178,534  |   | $ | 216,947 |   |
|                                                      |   |     |     |     |   |     |   |
| Reconciliation of funded status                           |   |     |     |     |   |     |   |
| Funded status                                             |   | $        | (56,611  | )        | $      | (69,193  | )      | $ | (27,525 | ) |
| Unrecognized actuarial (gain) or loss                     |   | 27,917   |     | 36,233   |   | (20,581  | )      |
| Unrecognized transition (asset) or  obligation            |   | (399     | )        | (532     | )      | (664     | )      |
| Unrecognized prior service cost                           |   | 9,184    |     | 10,106   |   | 11,027   |   |
| Net amount recognized at end of year                      |   | $        | (19,909  | )        | $      | (23,386  | )      | $ | (37,743 | ) |
|                                                      |   |     |     |     |   |     |   |
| Other Benefits:                                           |   |     |     |     |   |     |   |
| Change in benefit obligation                              |   |     |     |     |   |     |   |
| Benefit obligation at beginning of year                   |   | $        | 104,602  |     | $      | 83,223   |   | $ | 64,213 |   |
| Service cost                                              |   | 805      |     | 610      |   | 495      |   |
| Interest cost                                             |   | 6,313    |     | 6,379    |   | 5,433    |   |
| Curtailment loss                                          |   | —   |     | —   |   | 6,381    |   |
| Special termination benefits                              |   | —   |     | —   |   | 3,824    |   |
| Benefits and lump sums paid net of retiree  contributions |   | (7,329   | )        | (4,640   | )      | (5,446   | )      |
| Actuarial (gain) or loss                                  |   | 1,372    |     | 19,030   |   | 8,323    |   |
| Benefit obligation at end of year                         |   | $        | 105,763  |     | $      | 104,602  |   | $ | 83,223 |   |
|                                                      |   |     |     |     |   |     |   |
| Change in plan assets                                     |   |     |     |     |   |     |   |
| Fair value of plan assets at beginning of  year           |   | $        | 7,943    |     | $      | 14,330   |   | $ | 23,762 |   |
| Actual return on plan assets                              |   | (775     | )        | (2,698   | )      | (4,404   | )      |
| Employer contributions                                    |   | 5,506    |     | 1,648    |   | 1,071    |   |
| Changes due to transfers                                  |   | —   |     | —   |   | (598     | )      |
| Benefits and lump sums paid net of retiree  contributions |   | (7,295   | )        | (5,337   | )      | (5,501   | )      |
| Fair value of plan assets at end of year                  |   | $        | 5,379    |     | $      | 7,943    |   | $ | 14,330 |   |
|                                                      |   |     |     |     |   |     |   |
| Reconciliation of funded status                           |   |     |     |     |   |     |   |
| Funded status                                             |   | $        | (100,383 | )        | $      | (96,659  | )      | $ | (68,893 | ) |
| Unrecognized actuarial (gain) or loss                     |   | 24,013   |     | 22,667   |   | (437     | )      |
| Unrecognized transition (asset) or  obligation            |   | 10,088   |     | 11,209   |   | 12,290   |   |
| Unrecognized prior service cost                           |   | 2,142    |     | 2,891    |   | 3,548    |   |
| Net amount recognized at end of year                      |   | $        | (64,140  | )        | $      | (59,892  | )      | $ | (53,492 | ) |

 

126

----

 

## **Amounts Recognized in Statement of Financial Position. **The following tables provide the amounts recognized inthe balance sheet and information for plans with benefit obligations in excessof plan assets as of December 31, 2003, 2002, and 2001:

##  

| **(in thousands)**                                                                                        |   | **2003** |    | **2002** |   | **2001** |   |
|-----------------------------------------------------------------------------------------------------------|--------|----------|---------|----------|--------|----------|--------|
| Pension Plans:                                                                                            |   |     |    |     |   |     |   |
| Amounts recognized in the balance sheet  consisted of:                                                    |   |     |    |     |   |     |   |
| Accrued benefit liability                                                                                 |   | $        | (38,960 | )        | $      | (51,035  | )      | $ | (37,743 | ) |
| Intangible asset                                                                                          |   | 9,184    |    | 10,106   |   | —   |   |
| Accumulated other comprehensive income                                                                    |   | 9,867    |    | 17,543   |   | —   |   |
| Net amount recognized at year-end                                                                         |   | $        | (19,909 | )        | $      | (23,386  | )      | $ | (37,743 | ) |
|                                                                                                      |   |     |    |     |   |     |   |
| Additional year-end information for plans  with accumulated benefit obligations in excess of plan assets: |   |     |    |     |   |     |   |
| Projected benefit obligation                                                                              |   | $        | 257,705 |     | $      | 247,727  |   | $ | 244,472 |   |
| Accumulated benefit obligation                                                                            |   | 240,054  |    | 229,569  |   | 224,261  |   |
| Fair value of plan assets                                                                                 |   | 201,093  |    | 178,534  |   | 216,947  |   |
|                                                                                                      |   |     |    |     |   |     |   |
| Other Benefits:                                                                                           |   |     |    |     |   |     |   |
| Amounts recognized in the balance sheet consisted of:                                                     |   |     |    |     |   |     |   |
| Accrued benefit liability                                                                                 |   | $        | (64,140 | )        | $      | (59,892  | )      | $ | (53,492 | ) |
|                                                                                                      |   |     |    |     |   |     |   |
| Additional year-end information for plans  with benefit obligations in excess of plan assets:             |   |     |    |     |   |     |   |
| Projected benefit obligation                                                                              |   | $        | 105,763 |     | $      | 104,602  |   | $ | 83,223 |   |
| Fair value of plan assets                                                                                 |   | 5,379    |    | 7,943    |   | 14,330   |   |
|                                                                                                      |   |     |    |     |   |     |   |
| Increase (decrease) in minimum liability  included in other comprehensive income                          |   | $        | (7,676  | )        | $      | 17,543   |   | $ | 0 |   |

 

**Components of Net Periodic Benefit Cost. **The following tableprovides the components of net periodic benefit cost for the plans for 2003,2002 and 2001:

 

127

----

 
| **(in thousands)**                                |   | **2003** |   | **2002** |   | **2001** |   |
|---------------------------------------------------|--------|----------|--------|----------|--------|----------|--------|
| Pension Plans:                                    |   |     |   |     |   |     |   |
| Components of net periodic benefit cost           |   |     |   |     |   |     |   |
| Service cost                                      |   | $        | 2,962  |     | $      | 2,637    |   | $ | 2,761 |   |
| Interest cost                                     |   | 15,925   |   | 16,598   |   | 17,534   |   |
| Expected return on plan assets                    |   | (14,888  | )      | (18,406  | )      | (19,829  | )      |
| Amortization of prior service cost                |   | 957      |   | 956      |   | 962      |   |
| Amortization of transition (asset) or  obligation |   | (133     | )      | (133     | )      | (136     | )      |
| Recognized actuarial (gain) or loss               |   | 1,211    |   | 1        |   | (120     | )      |
| Net periodic benefit cost                         |   | $        | 6,034  |     | $      | 1,653    |   | $ | 1,172 |   |
|                                              |   |     |   |     |   |     |   |
| Special charges                                   |   |     |   |     |   |     |   |
| Prior service cost recognized                     |   | $        | — |     | $      | —   |   | $ | 1,238 |   |
| Special termination benefits                      |   | —   |   | —   |   | 24,274   |   |
| Total charges                                     |   | $        | — |     | $      | —   |   | $ | 25,512 |   |
|                                              |   |     |   |     |   |     |   |
| Other Benefits:                                   |   |     |   |     |   |     |   |
| Components of net periodic benefit cost           |   |     |   |     |   |     |   |
| Service cost                                      |   | $        | 806    |     | $      | 610      |   | $ | 495 |   |
| Interest cost                                     |   | 6,313    |   | 6,379    |   | 5,433    |   |
| Expected return on plan assets                    |   | (337     | )      | (1,022   | )      | (1,313   | )      |
| Amortization of prior service cost                |   | 714      |   | 691      |   | 740      |   |
| Amortization of transition (asset) or  obligation |   | 1,121    |   | 1,081    |   | 1,193    |   |
| Recognized actuarial (gain) or loss               |   | 1,137    |   | 343      |   | (40      | )      |
| Net periodic benefit cost                         |   | $        | 9,754  |     | $      | 8,082    |   | $ | 6,508 |   |
|                                              |   |     |   |     |   |     |   |
| Special charges                                   |   |     |   |     |   |     |   |
| Transition obligation recognized                  |   | $        | — |     | $      | —   |   | $ | 7,638 |   |
| Prior service cost recognized                     |   | —   |   | —   |   | 1,613    |   |
| Special termination benefits                      |   | —   |   | —   |   | 3,824    |   |
| Total charges                                     |   | $        | — |     | $      | —   |   | $ | 13,075 |   |

 

The assumptions used in the measurement of KU’s pension benefitobligation are shown in the following table:

 
|                                                  |   | **2003** |   | **2002** |   | **2001** |   |
|-------------------------------------------------------|--------|----------|--------|----------|--------|----------|--------|
|                                                  |   |     |   |     |   |     |   |
| Weighted-average assumptions as of  December 31: |   |     |   |     |   |     |   |
| Discount rate                                         |   | 6.25     | %      | 6.75     | %      | 7.25     | %      |
| Rate of compensation increase                         |   | 3.00     | %      | 3.75     | %      | 4.25     | %      |

 

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

 
|                                     |   | **2003** |   | **2002** |   | **2001** |   |
|------------------------------------------|--------|----------|--------|----------|--------|----------|--------|
|                                     |   |     |   |     |   |     |   |
| Discount rate                            |   | 6.75     | %      | 7.25     | %      | 7.75     | %      |
| Expected long-term return on plan assets |   | 9.00     | %      | 9.50     | %      | 9.50     | %      |
| Rate of compensation increase            |   | 3.75     | %      | 4.25     | %      | 4.75     | %      |

 

To develop the expected long-term rate of return on assets assumption,KU considered the current level of expected returns on risk free investments(primarily government bonds), 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 return for each asset class wasthen weighted based on the target asset allocation to develop the expectedlong-term rate of return on assets assumption for the portfolio.

 

## **Assumed Healthcare Cost Trend Rates. **For measurement purposes, a 12.0% annual increase inthe per capita cost of covered healthcare benefits was assumed for 2004.  The rate was assumed to decrease graduallyto 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:

 
| **(in thousands)**                                                |   | **1%  Decrease** |   | **1%  Increase** |   |
|-------------------------------------------------------------------|--------|------------------|--------|------------------|--------|
| Effect on total of service and interest  cost components for 2003 |   | $                | (463   | )                | $      | 527 |   |
| Effect on year-end 2003 postretirement  benefit obligations       |   | $                | (7,041 | )                | $      | 8,000 |   |

 

128

----

 

## **Plan Assets. **The following table shows KU’sweighted-average asset allocation by asset category at December 31:

##  

|              |   | **2003** |   | **2002** |   | **2001** |   |
|-------------------|--------|----------|--------|----------|--------|----------|--------|
|              |   |     |   |     |   |     |   |
| Pension Plans:    |   |     |   |     |   |     |   |
| Equity securities |   | 66       | %      | 64       | %      | 70       | %      |
| Debt securities   |   | 33       | %      | 34       | %      | 28       | %      |
| Other             |   | 1        | %      | 2        | %      | 2        | %      |
| Totals            |   | 100      | %      | 100      | %      | 100      | %      |
|              |   |     |   |     |   |     |   |
| Other Benefits:   |   |     |   |     |   |     |   |
| Equity securities |   | 0        | %      | 0        | %      | 97       | %      |
| Debt securities   |   | 100      | %      | 100      | %      | 3        | %      |
| Totals            |   | 100      | %      | 100      | %      | 100      | %      |

 

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

 

The fund focuses on a long-term investmenttime horizon of at least three to five years or a complete market cycle.  The assets of the pension plans are broadlydiversified within different asset classes (equities, fixed income securitiesand cash equivalents).

 

To minimize the risk of large losses in asingle asset class, no more than 5% of the portfolio will be invested in thesecurities of any one issuer with the exclusion of the U.S. government and itsagencies.  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 are not limited to growth, value,small capitalization and international.

 

In addition, the overall fixed incomeportfolio holdings have a maximum average weighted maturity of no more thanfifteen (15) years, with the weighted average duration of the portfolio beingno more than eight (8) years.  Allsecurities must be rated “investment grade” or better and foreign bonds in theaggregate shall not exceed 10% of the total fund.  The cash investments should be in securities that 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 or to reduce transaction costs and must be used inconjunction with underlying physical assets in the portfolio. Derivativesecurities that involve speculation, leverage, interest rate anticipation, orany undue risk whatsoever are not deemed appropriate investments.

 

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

 

### **Contributions. **KU made a discretionarycontribution to the pension plan of $43.4 million in January 2004.  No further discretionary contributions areplanned and no contributions are required for 2004.

###  

**Thrift SavingsPlans. **KU hasa thrift savings plan under section 401(k) of the Internal RevenueCode.  Under the

 

129

----

 

plan, eligible employees may defer and contribute to the plan a portionof current compensation in order to provide future retirement benefits. KUmakes contributions to the plan by matching a portion of the employeecontributions. The costs of this matching were approximately $1.9 million for2003, $1.5 million for 2002 and $1.4 million for 2001.

 

**Note 7 - Income Taxes**

 

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

 
| **(in thousands)**                    |                 | **2003** |   | **2002** |   | **2001** |    |
|---------------------------------------|----------------------|----------|--------|----------|--------|----------|---------|
| Included in operating expenses:       |                 |     |   |     |   |     |    |
| Current                               | - federal            |     | $      | 31,079   |   | $        | 38,524  |   | $ | 58,337 |   |
|                                  | - state              |     | 11,456 |     | 10,494 |     | 13,465  |   |
| Deferred                              | - federal – net |     | 11,198 |     | 3,467  |     | (12,980 | ) |
|                                  | - state – net   |     | 923    |     | 1,547  |     | (1,340  | ) |
| Total                                 |                 |     | 54,656 |     | 54,032 |     | 57,482  |   |
|                                  |                 |     |   |     |   |     |    |   |
| Included in other income - net:       |                 |     |   |     |   |     |    |
| Current                               | - federal            |     | (1,961 | )        | (685   | )        | (948    | ) |
|                                  | - state              |     | (134   | )        | (195   | )        | (268    | ) |
| Deferred                              | - federal – net |     | 180    |     | 15     |     | 863     |   |
|                                  | - state – net   |     | (19    | )        | (88    | )        | 222     |   |
| Amortization of investment tax credit |                 | (2,641   | )      | (2,955   | )      | (3,446   | )       |
| Total                                 |                 | (4,575   | )      | (3,908   | )      | (3,577   | )       |
|                                  |                 |     |   |     |   |     |    |
| Total income tax expense              |                 | $        | 50,081 |     | $      | 50,124   |    | $ | 53,905 |   |

 

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

 
| **(in thousands)**                                      |   | **2003** |    | **2002** |   |
|---------------------------------------------------------|--------|----------|---------|----------|--------|
| Deferred tax liabilities:                               |   |     |    |     |   |
| Depreciation and other plant-related items              |   | $        | 282,376 |     | $      | 271,792 |   |
| Other liabilities                                       |   | 27,499   |    | 30,378   |   |
|                                                    |   | 309,875  |    | 302,170  |   |
|                                                    |   |     |    |     |   |
| Deferred tax assets:                                    |   |     |    |     |   |
| Investment tax credit                                   |   | 2,365    |    | 3,431    |   |
| Income taxes due to customers                           |   | 9,710    |    | 11,609   |   |
| Pensions                                                |   | (4,702   | )       | 15,861   |   |
| Accrued liabilities not currently  deductible and other |   | 41,244   |    | 30,085   |   |
|                                                    |   | 48,617   |    | 60,986   |   |
| Net deferred income tax liability                       |   | $        | 261,258 |     | $      | 241,184 |   |

 

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

 
|                                       |   | **2003** |   | **2002** |   | **2001** |   |
|--------------------------------------------|--------|----------|--------|----------|--------|----------|--------|
|                                       |   |     |   |     |   |     |   |
| Statutory federal income tax rate          |   | 35.0     | %      | 35.0     | %      | 35.0     | %      |
| State income taxes, net of federal benefit |   | 5.8      |   | 5.5      |   | 5.4      |   |
| Amortization of investment tax credit      |   | (1.9     | )      | (2.4     | )      | (2.3     | )      |
| Other differences – net               |   | (3.5     | )      | (3.2     | )      | (2.2     | )      |
| Effective income tax rate                  |   | 35.4     | %      | 34.9     | %      | 35.9     | %      |

 

130

----

 

Other differences include tax benefits related to prior year auditsettlements (1.0%), excess deferred taxes (1.8%), and various other permanentdifferences (0.7%).

 

**Note 8 - Other Income- Net**

 

Other income – net consisted of the following at December 31:

 
| **(in thousands)**                      |   | **2003** |   | **2002** |   | **2001** |   |
|-----------------------------------------|--------|----------|--------|----------|--------|----------|--------|
|                                    |   |     |   |     |   |     |   |
| Equity in earnings - subsidiary company |   | $        | 3,644  |     | $      | 6,967    |   | $ | 1,803 |   |
| Interest and dividend income            |   | 682      |   | 580      |   | 1,072    |   |
| Investment tax credit                   |   | 2,641    |   | 2,955    |   | 3,446    |   |
| Income and other taxes                  |   | 1,907    |   | 943      |   | 121      |   |
| Other                                   |   | 215      |   | (1,077   | )      | 2,194    |   |
|                                    |   | $        | 9,089  |     | $      | 10,368   |   | $ | 8,636 |   |

 

**Note 9 - Long-TermDebt**

 

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

 

Long-term debt and the current portion of long-term debt consistsprimarily of first mortgage bonds, pollution control bonds, and long-term loansfrom affiliated companies as summarized below (in thousands of $).  Interest rates and maturities in the tablebelow are for the amounts outstanding at December 31, 2003 and reflectsthe impact of interest rate swaps.

 
|               |   | **Stated  Interest Rates** |   | **Weighted  Average  Interest  Rate** | ** ** | **Maturities** | ** ** | **Principal  Amounts** | ** ** |
|--------------------|--------|----------------------------|--------|---------------------------------------|------------|----------------|------------|------------------------|------------|
|               |   |                       |   |                                  |       |           |       |                   |       |
| Noncurrent portion |   | Variable – 7.92       | %      | 3.10                                  | %          | 2006-2032      |       | $                      | 595,646    |   |
| Current portion    |   | Variable                   |   | 1.34                                  | %          | 2024-2032      |       | $                      | 91,930     |   |

 

Under the provisions for KU’s variable-rate pollution control bondsSeries 10, 12, 13, 14, and 15, the bonds are subject to tender for purchase atthe option of the holder and to mandatory tender for purchase upon theoccurrence of certain events, causing the bonds to be classified as currentportion of long-term debt in the Consolidated Balance Sheets.  The average annualized interest rate forthese bonds during 2003 was 1.07%.

 

Interest rate swaps are used to hedge KU’s underlying debtobligations.  These swaps hedge specificdebt issuances and, consistent with management’s designation, are accordedhedge accounting treatment.  As ofDecember 31, 2003, KU has swaps with a combined notional value of $153million.  The swaps effectively convertfixed rate obligations on KU’s first mortgage bonds Series P and R andpollution control bonds Series 9 to variable-rate obligations.  See Note 4.

 

In September 2002, KU issued $96 million variable-rate pollutioncontrol bonds Series 16 due October 1, 2032, and exercised its call optionon $96 million, 7.45% pollution control bonds Series 8 due September 15,2016.

 

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

 

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

 

131

----

 

In November 2003, KU called its first mortgage bond, Series P8.55% of $33 million, due in 2007, and replaced it with a loan from anaffiliated company.

 

Substantially all of KU’s utility plant is pledged as security for itsfirst mortgage bonds.

 

During 2003, KU entered into four long-term loans from an affiliatedcompany totaling $283 million (see Note 1). Of this total, $100 million is unsecured with an interest rate of 4.55%and matures in April 2013.  Theremaining $183 million (which is made up of $75 million at 5.31% dueAugust 2013, $33 million at 4.24% due November 2010 and $75 millionat 2.29% due December 2005) is secured by a lien subordinated to the firstmortgage bond lien.  The second lienapplies to substantially all utility assets of KU.

 

The following table reflects the long-term debt maturities:

 
| **(in thousands)**              |   | **2004** |   | **2005** |   | **2006** |   | **2007** |   | **2008** |   | **Thereafter** |   | **Total** |   |
|---------------------------------|--------|----------|--------|----------|--------|----------|--------|----------|--------|----------|--------|----------------|--------|-----------|--------|
|                            |   |     |   |     |   |     |   |     |   |     |   |           |   |      |   |
| First mortgage bonds            |   | $        | — |     | $      | —   |   | $        | 36,000 |     | $      | 53,000         |   | $         | — |   | $ | 50,000 |   | $ | 139,000 |   |
| Pollution control bonds         |   | 91,930   | (1)    | —   |   | —   |   | —   |   | —   |   | 158,900        |   | 250,830   |   |
| Notes payable to Fidelia        |   | —   |   | 75,000   |   | —   |   | —   |   | —   |   | 208,000        |   | 283,000   |   |
| Long-term debt marked to market |   | —   |   | —   |   | —   |   | 8,162    |   | —   |   | 6,584          |   | 14,746    |   |
|                            |   | $        | 91,930 |     | $      | 75,000   |   | $        | 36,000 |     | $      | 61,162         |   | $         | — |   | $ | 423,484 |   | $ | 687,576 |   |

 

(1)   Includes $91,930 of bonds with put provisionsthat allow the holders to sell bonds back to KU at a specific price beforematurity.

 

In January 2004, KU entered into one additional unsecuredlong-term loan from an affiliated company totaling $50 million with an interestrate of 4.39% that matures in January 2012.  The proceeds were used to repay amounts due under the accountsreceivable securitization program.

 

InFebruary 2004, KU terminated the swap it had in place at December 31,2003 related to the Series 9 pollution control bonds.  The notional amount of the terminated swap was $50 million and KUreceived a payment of $2.0 million as part of the termination. The swap wasterminated because it was no longer an effective hedge of the underlying bond.

 

**Note 10 - NotesPayable and Other Short-Term Obligations**

 

KU participates in an intercompany money pool agreement whereinLG&E Energy and LG&E make funds available to KU at market-based rates(based on an index of highly rated commercial paper issues as of the priormonth end) up to $400 million. Likewise, LG&E Energy and KU make funds available to LG&E atmarket-based rates upto $400 million. The balance of the money pool loan from LG&E Energy (shown as “Notespayable to affiliated company”) was $43.2 million at an average rate of 1.00%and $119.5 million at an average rate of 1.61% at December 31, 2003 and2002, respectively.  The amountavailable to KU under the money pool agreement at December 31, 2003 was$356.8 million. LG&E Energy maintains a revolving credit facility totaling$150 million with an affiliate to ensure funding availability for the moneypool.  The outstanding balance underLG&E Energy’s facility as of December 31, 2003 was $111.1 million, andavailability of $38.9 million remained.

 

# **Note11 - Commitments and Contingencies**

# ** **

The following is provided to summarize KU’s contractual cashobligations for periods after December 31, 2003:

 

132

----

 
|                                             |   | **Payments  Due by Period** |       |
|--------------------------------------------------|--------|-----------------------------|------------|
| **(in thousands)  Contractual Cash Obligations** |   | **2004**                    | ** ** | **2005-  2006** | ** ** | **2007-  2008** | ** ** | **After  2008** | ** ** | **Total** | ** ** |
| Short-term debt (a)                              |   | $                           | 43,231     |   | $ | — |   | $ | — |   | $ | — |   | $ | 43,231 |   |
| Long-term debt (b)                               |   | 91,930                      |       | 111,000 |   | 53,000 |   | 431,646 |   | 687,576 |   |
| Unconditional purchase obligations (c)           |   | 37,433                      |       | 76,419 |   | 79,733 |   | 686,420 |   | 880,005 |   |
| Other long-term obligations (d)                  |   | 82,100                      |       | — |   | — |   | — |   | 82,100 |   |
| Total contractual cash obligations (e)           |   | $                           | 254,694    |   | $ | 187,419 |   | $ | 132,733 |   | $ | 1,118,066 |   | $ | 1,692,912 |   |

 

(a)   Represents borrowings from affiliated company due within one year.

(b)   Includes long-term debt of $91.9 millionclassified as a current liability because the 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 the bonds range from 2024 to 2032.

(c)   Represents future minimum payments underpurchased power agreements through 2023.

(d)   Represents construction commitments.

(e)   KU does not expect to pay the $91.9 million oflong-term debt classified as a current liability in the Consolidated BalanceSheets in 2004 as explained in (b) above. KU anticipates cash from operations and external financing will besufficient to fund future obligations. KU anticipates refinancing a portion of its short-term debt with long-termdebt in 2004.

 

**Operating Leases.**  KU leases office space, office equipment,and vehicles.  KU accounts for theseleases as operating leases.  Inaddition, 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 expense for 2003, 2002, and2001, was $2.2 million, $3.1 million, and $3.5 million, respectively.

 

KU is aparticipant in a sale and leaseback transaction involving its 62% interest intwo jointly-owned CTs at KU’s E.W. Brown generating station (Units 6 and7).  Commencing in December 1999,LG&E and KU entered into a tax-efficient, 18-year lease of the CTs.LG&E and KU have provided funds to fully defease the lease, and have executedan irrevocable notice to exercise an early purchase option contained in thelease after 15.5 years. The financial statement treatment of this transactionis no different than if KU had retained its ownership.  The transaction produced a pre-tax gain ofapproximately $1.9 million which was recorded in other income on the incomestatement in 2000, pursuant to a Kentucky Commission order.  The leasing transaction was entered intofollowing receipt of required state and federal regulatory approvals.

 

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

 

AtDecember 31, 2003, the maximum aggregate amount of default fees oramounts, which decrease over the term of the lease, was $8.9 million, of whichKU would be responsible for 62%.  KU hasmade arrangements with LG&E Energy, via guarantee and regulatorycommitment, for LG&E Energy to pay its full portion of any default fees oramounts.  KU paid LG&E Energy aone-time fee of $186,000 to provide the guarantee.

 

**Purchased Power.**  KU has purchase power arrangements with OMU,EEI, and OVEC.  Under the OMU agreement,which expires on January 1, 2020, KU purchases all of the output of a400-Mw (approximate) coal-fired generating station not required by OMU.  The amount of purchased power available toKU during 2004-2008, which is expected to be approximately 8% of KU’s total kWhnative load energy requirements, is dependent upon a number of factors includingthe OMU units’ availability, maintenance schedules, fuel costs and OMUrequirements.  Payments are based on thetotal costs of the station allocated per terms of the OMU

 

133

----

 

agreement.  Included in thetotal costs is KU’s proportionate share of debt service requirements on $210.9million of OMU bonds outstanding at December 31, 2003.  The debt service is allocated to KU based onits annual allocated share of capacity, which averaged approximately 47% in2003.  KU does not guarantee the OMUbonds, 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.  KU’sentitlement is 20% of the available capacity of a 1,000 Mw station.  Payments are based on the total costs of thestation allocated per terms of an agreement among the owners, which generallyfollow delivered kWh.

 

KU has an investment of 2.5% ownership in OVEC’s common stock, which isaccounted for under the cost method of accounting.  KU’s entitlement is 2.5% of OVEC’s generation capacity orapproximately 55 Mw.

 

The estimated future minimum annual demand payments under purchasedpower agreements for the five years subsequent to December 31, 2003, areas follows:

 
| **(in thousands)** |   |    |    |   |
|--------------------|--------|---------|---------|--------|
| 2004               |   | $       | 37,433  |   |
| 2005               |   | 37,481  |    |
| 2006               |   | 38,938  |    |
| 2007               |   | 38,882  |    |
| 2008               |   | 40,851  |    |
| Thereafter         |   | 686,420 |    |
| Total              |   | $       | 880,005 |   |

 

**Construction Program.**  KU had approximately $11.5 million ofcommitments in connection with its construction program at December 31,2003.  Construction expenditures for theyears 2004 and 2005 are estimated to total approximately $312.0 million;although all of this is not currently committed, including the construction offour jointly owned CTs, $23.2 million, and construction of NOx equipment, $58.9million.

 

**EnvironmentalMatters. **KU issubject to SO2 and NOx emission limits on its electric generatingunits pursuant to the Clean Air Act.  KUmet its Phase I SO2 requirements primarily through installation ofFGD equipment on Ghent Unit 1.  KU’sstrategy for Phase II SO2 reductions, which commencedJanuary 1, 2000, is to use accumulated emissions allowances to delayadditional capital expenditures and will include fuel switching or theinstallation of additional FGDs as necessary. KU met the NOx emission requirements of the Act through installation oflow-NOx burner systems.  KU’s complianceplans are subject to many factors including developments in the emissionallowance and fuel markets, future regulatory and legislative initiatives, andadvances in clean air control technology. KU will continue to monitor these developments to ensure that itsenvironmental obligations are met in the most efficient and cost-effectivemanner.

 

In September 1998, the EPA announced its final “NOx SIP Call” rulerequiring states to impose significant additional reductions in NOx emissionsby May 2003, in order to mitigate alleged ozone transport impacts on theNortheast region.  The Commonwealth ofKentucky SIP, which was approved by EPA June 24, 2003, requires reductionsin NOx emissions from coal-fired generating units to the 0.15 lb./Mmbtu levelon a system-wide basis.  In relatedproceedings in response to petitions filed by various Northeast states, inDecember 1999, EPA issued a final rule pursuant to Section 126 of theClean Air Act directing similar NOx reductions from a number of specificallytargeted generating units including all KU units in the eastern half ofKentucky.  Additional petitionscurrently pending before EPA may potentially result in rules encompassing KU’sremaining generating units.  As a resultof appeals to both rules, the compliance date was extended to May 2004.  All KU generating units are subject to theMay 2004 compliance date under these NOx emissions reduction rules.

 

KU is currently implementing a plan for adding significant additionalNOx controls to its generating units.

 

134

----

 

Installation of additional NOx controls will proceed on a phased basis,with installation of controls commencing in late 2000 and continuing throughthe final compliance date.  KU estimatesthat it will incur total capital costs of approximately $230 million to reduceits NOx emissions to the 0.15 lb./Mmbtu level on a company-wide basis.  As of December 31, 2003, KU has incurred$172 million of these capital costs related to the reduction of its NOxemissions.  In addition, KU will incuradditional operation and maintenance costs in operating new NOx controls.  KU believes its costs in this regard to becomparable to those of similarly situated utilities with like generationassets.  KU had anticipated that suchcapital 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 April 2001, the Kentucky Commissiongranted recovery of these costs for KU.

 

KU is also monitoring several other air quality issues which may potentiallyimpact coal-fired power plants, including EPA’s revised air quality standardsfor ozone and particulate matter, measures to implement EPA’s regional hazerule and EPA’s December 2003 proposals to regulate mercury emissions fromsteam electric generating units and to further reduce emissions of sulfurdioxide and nitrogen oxides under the Interstate Air Quality Rule.

 

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

 

In October 1999, approximately 38,000 gallons of diesel fuelleaked from a cracked valve in an underground pipeline at KU’s E.W. BrownStation.  KU commenced immediate spillcontainment and recovery measures which continued under the oversight of EPAand state officials and prevented the spill from reaching the KentuckyRiver.  KU ultimately recoveredapproximately 34,000 gallons of diesel fuel. In November 1999, the Kentucky Division of Water issued a notice ofviolation for the incident.  KU hassettled all outstanding issues for this incident with the Commonwealth ofKentucky.  KU incurred costs of approximately$1.8 million and received insurance reimbursement of $1.2 million.  In December 2002, the Department ofJustice (DOJ) sent correspondence to KU regarding a potential per-day fine forfailure to timely submit a facility response plan and a per-gallon fine for theamount of oil discharged.  KU and theDOJ have commenced settlement discussions using existing DOJ settlementguidelines on this matter.

 

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

 

# **Note12 – Jointly Owned Electric Utility Plant**

# ** **

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

 

135

----

 
| **($ in thousands)**  |   |           |   | **LG&E** |   | **KU** |   | **Total** |   |
|-----------------------|--------|----------------|--------|--------------|--------|--------|--------|-----------|--------|
|                  |   |           |   |         |   |   |   |      |   |
| Paddy’s Run 13   |   | Ownership%     |   | 53           | %      | 47     | %      | 100       | %      |
|                  |   | Mw capacity    |   | 84           |   | 74     |   | 158       |   |
|                  |   | Cost           |   | $            | 33,919 |   | $      | 29,973    |   | $ | 63,892 |   |
|                  |   | Depreciation   |   | 2,875        |   | 2,527  |   | 5,402     |   |
|                  |   | Net book value |   | $            | 31,044 |   | $      | 27,446    |   | $ | 58,490 |   |
|                  |   |           |   |         |   |   |   |      |   |
| E.W. Brown 5          |   | Ownership%     |   | 53           | %      | 47     | %      | 100       | %      |
|                  |   | Mw capacity    |   | 62           |   | 55     |   | 117       |   |
|                  |   | Cost           |   | $            | 24,111 |   | $      | 20,296    |   | $ | 44,407 |   |
|                  |   | Depreciation   |   | 2,033        |   | 1,700  |   | 3,733     |   |
|                  |   | Net book value |   | $            | 22,078 |   | $      | 18,596    |   | $ | 40,674 |   |
|                  |   |           |   |         |   |   |   |      |   |
| E.W. Brown 6          |   | Ownership%     |   | 38           | %      | 62     | %      | 100       | %      |
|                  |   | Mw capacity    |   | 59           |   | 95     |   | 154       |   |
|                  |   | Cost           |   | $            | 23,975 |   | $      | 36,701    |   | $ | 60,676 |   |
|                  |   | Depreciation   |   | 2,629        |   | 5,447  |   | 8,076     |   |
|                  |   | Net book value |   | $            | 21,346 |   | $      | 31,254    |   | $ | 52,600 |   |
|                  |   |           |   |         |   |   |   |      |   |
| E.W. Brown 7          |   | Ownership%     |   | 38           | %      | 62     | %      | 100       | %      |
|                  |   | Mw capacity    |   | 59           |   | 95     |   | 154       |   |
|                  |   | Cost           |   | $            | 23,824 |   | $      | 38,256    |   | $ | 62,080 |   |
|                  |   | Depreciation   |   | 3,571        |   | 4,039  |   | 7,610     |   |
|                  |   | Net book value |   | $            | 20,253 |   | $      | 34,217    |   | $ | 54,470 |   |
|                  |   |           |   |         |   |   |   |      |   |
| Trimble 5             |   | Ownership%     |   | 29           | %      | 71     | %      | 100       | %      |
|                  |   | Mw capacity    |   | 46           |   | 114    |   | 160       |   |
|                  |   | Cost           |   | $            | 15,970 |   | $      | 39,045    |   | $ | 55,015 |   |
|                  |   | Depreciation   |   | 799          |   | 1,953  |   | 2,752     |   |
|                  |   | Net book value |   | $            | 15,171 |   | $      | 37,092    |   | $ | 52,263 |   |
|                  |   |           |   |         |   |   |   |      |   |
| Trimble 6             |   | Ownership%     |   | 29           | %      | 71     | %      | 100       | %      |
|                  |   | Mw capacity    |   | 46           |   | 114    |   | 160       |   |
|                  |   | Cost           |   | $            | 15,961 |   | $      | 39,025    |   | $ | 54,986 |   |
|                  |   | Depreciation   |   | 798          |   | 1,952  |   | 2,750     |   |
|                  |   | Net book value |   | $            | 15,163 |   | $      | 37,073    |   | $ | 52,236 |   |
|                  |   |           |   |         |   |   |   |      |   |
| Trimble 7             |   | Ownership%     |   | 37           | %      | 63     | %      | 100       | %      |
|                  |   | Mw capacity    |   | 56           |   | 96     |   | 152       |   |
|                  |   | Current CWIP   |   | $            | 17,342 |   | $      | 29,634    |   | $ | 46,976 |   |
|                  |   |           |   |         |   |   |   |      |   |
| Trimble 8             |   | Ownership%     |   | 37           | %      | 63     | %      | 100       | %      |
|                  |   | Mw capacity    |   | 56           |   | 96     |   | 152       |   |
|                  |   | Current CWIP   |   | $            | 17,307 |   | $      | 29,601    |   | $ | 46,908 |   |
|                  |   |           |   |         |   |   |   |      |   |
| Trimble 9             |   | Ownership%     |   | 37           | %      | 63     | %      | 100       | %      |
|                  |   | Mw capacity    |   | 56           |   | 96     |   | 152       |   |
|                  |   | Current CWIP   |   | $            | 17,300 |   | $      | 29,599    |   | $ | 46,899 |   |
|                  |   |           |   |         |   |   |   |      |   |
| Trimble 10            |   | Ownership%     |   | 37           | %      | 63     | %      | 100       | %      |
|                  |   | Mw capacity    |   | 56           |   | 96     |   | 152       |   |
|                  |   | Current CWIP   |   | $            | 17,300 |   | $      | 29,597    |   | $ | 46,897 |   |
|                  |   |           |   |         |   |   |   |      |   |
| Trimble CT Pipeline   |   | Ownership%     |   | 29           | %      | 71     | %      | 100       | %      |
|                  |   | Cost           |   | $            | 1,835  |   | $      | 4,475     |   | $ | 6,310 |   |
|                  |   | Depreciation   |   | 102          |   | 249    |   | 351       |   |
|                  |   | Net book value |   | $            | 1,733  |   | $      | 4,226     |   | $ | 5,959 |   |
|                  |   |           |   |         |   |   |   |      |   |
| Trimble CT Substation |   | Ownership%     |   | 29           | %      | 71     | %      | 100       | %      |
|                  |   | Cost           |   | $            | 1,474  |   | $      | 3,598     |   | $ | 5,072 |   |
|                  |   | Depreciation   |   | 45           |   | 116    |   | 161       |   |
|                  |   | Net book value |   | $            | 1,429  |   | $      | 3,482     |   | $ | 4,911 |   |

 

See also Note 11, Construction Program, for KU’s planned expendituresfor construction of four jointly owned CTs in 2004.

 

136

----

 

**Note 13 - RelatedParty Transactions**

 

KU, subsidiaries of LG&E Energy and other subsidiaries of E.ONengage in related party transactions. Transactions between KU and its subsidiary KU R are eliminated uponconsolidation with KU.  Transactionsbetween KU and LG&E Energy subsidiaries are eliminated upon consolidationof LG&E Energy. Transactions between KU and E.ON subsidiaries areeliminated upon consolidation of E.ON. These transactions are generallyperformed at cost and are in accordance with the SEC regulations under thePUHCA and the applicable Kentucky Commission and Virginia Commissionregulations.  Amounts payable to andreceivable from related parties are netted and presented as accounts payable toaffiliated companies on the balance sheet of KU, as allowed due to the right ofoffset. Obligations related to intercompany debt arrangements with LG&EEnergy and Fidelia, an E.ON subsidiary, are presented as separate line items onthe balance sheet, as appropriate. The significant related party transactionsare disclosed below.

 

Electric Purchases

 

KU and LG&E purchase energy from each other in order to effectivelymanage the load of their retail and off-system customers.  In addition, KU and LG&E EnergyMarketing Inc. (“LEM”), a subsidiary of LG&E Energy, purchase energy fromeach other. These sales and purchases are included in the ConsolidatedStatements of Income as Electric Operating Revenues and Purchased PowerOperating Expense.  KU intercompanyelectric revenues and purchased power expense for the years ended December 31,2003, 2002, and 2001 were as follows:

 
| **(in thousands)**                        |   | **2003** |   | **2002** |   | **2001** |   |
|-------------------------------------------|--------|----------|--------|----------|--------|----------|--------|
| Electric operating revenues from LG&E |   | $        | 46,690 |     | $      | 33,249   |   | $ | 31,133 |   |
| Electric operating revenues from LEM      |   | 2,408    |   | 3,581    |   | 5,444    |   |
| Purchased power from LG&E             |   | 53,747   |   | 41,480   |   | 28,521   |   |
| Purchased power from LEM                  |   | —   |   | 913      |   | —   |   |
|                                           |        |          |        |          |        |          |        |  |  |  |

 

Interest Charges

 

KU participates in an intercompany money pool agreement whereinLG&E Energy and LG&E make funds available to KU at market-based rates(based on an index of highly rated commercial paper issues as of the priormonth end) up to $400 million. Likewise, LG&E Energy and KU make funds available to LG&E atmarket-based rates up to $400 million. The balance of the money pool loan from LG&E Energy (shown as “Notespayable to parent”) was $43.2 million at an average rate of 1.00% and $119.5million at an average rate of 1.61% at December 31, 2003 and 2002,respectively.  The amount available toKU under the money pool agreement at December 31, 2003 was $356.8 million.LG&E Energy maintains a revolving credit facility totaling $150 millionwith an affiliate to ensure funding availability for the money pool.  The outstanding balance under LG&EEnergy’s facility as of December 31, 2003 was $111.1 million, andavailability of $38.9 million remained.

 

In addition, in 2003 KU began borrowing long-term funds from FideliaCorporation, an affiliate of E.ON (see Note 9).  Fidelia Corporation has a second lien on the property subject tothe first mortgage bond lien.  Thesecond lien secures $183 million of the loans provided by Fidelia.

 

Intercompany agreements do not require interest payments forreceivables related to services provided when settled within 30 days.  The only interest income or expense recordedby the utilities relates to LG&E’s receipt and payment of KU’s portion ofoff-system sales and purchases.

 

KU intercompany interest income and expense for the years endedDecember 31, 2003, 2002, and 2001 were as follows:

 

137

----

 
| **(in thousands)**                     |   | **2003** |   | **2002** |   | **2001** |   |
|----------------------------------------|--------|----------|--------|----------|--------|----------|--------|
| Interest on money pool loans           |   | $        | 1,204  |     | $      | 1,071    |   | $ | 974 |   |
| Interest on Fidelia loans              |   | 4,729    |   | —   |   | —   |   |
| Interest expense paid to LG&E      |   | 7        |   | 5        |   | —   |   |
| Interest income received from LG&E |   | 8        |   | 61       |   | 296      |   |
|                                        |        |          |        |          |        |          |        |  |  |  |

 

Other Intercompany Billings

 

LG&E Services provides KU with a variety of centralized administrative,management, and support services in accordance with agreements approved by theSEC under PUHCA. These charges include taxes paid by LG&E Energy on behalfof KU, labor and burdens of LG&E Services employees performing services forKU, and vouchers paid by LG&E Services on behalf of KU.  The cost of these services are directlycharged to KU, 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.  Thesecosts are charged on an actual cost basis.

 

In addition, KU and LG&E provide certain services to each other andto LG&E Services, in accordance with exceptions granted under PUHCA.Billings between LG&E and KU relate to labor and overheads associated withunion employees performing work for the other utility, charges related tojointly-owned combustion turbines, and other miscellaneous charges.  Billings from KU to LG&E Servicesrelated to information technology-related services provided by KU employees,cash received by LG&E Services on behalf of KU, and services provided by KUto other non-regulated businesses which are paid through LG&E Services.

 

Intercompany billings to and from KU for the years endedDecember 31, 2003, 2002, and 2001 were as follows:

 
| **(in thousands)**               |   | **2003** |    | **2002** |   | **2001** |   |
|----------------------------------|--------|----------|---------|----------|--------|----------|--------|
| LG&E Services billings to KU |   | $        | 187,320 |     | $      | 176,254  |   | $ | 201,513 |   |
| KU billings to LG&E          |   | 31,850   |    | 36,404   |   | 87,992   |   |
| LG&E billings to KU          |   | 23,436   |    | 29,659   |   | 31,314   |   |
| KU billings to LG&E Services |   | 14,199   |    | 18,573   |   | 11,726   |   |
|                                  |        |          |         |          |        |          |        |  |  |  |

 

**Note 14 - SelectedQuarterly Data (Unaudited)**

 

Selected financial data for the four quarters of 2003 and 2002 areshown below.  Because of seasonalfluctuations in temperature and other factors, results for quarters mayfluctuate throughout the year.

 
|                 |   | **Quarters  Ended** |       |
|----------------------|--------|---------------------|------------|
| **(in thousands)**   |   | **March**           | ** ** | **June** | ** ** | **September** | ** ** | **December** | ** ** |
| 2003                 |   |                |       |   |   |   |   |   |   |
| Operating revenues   |   | $                   | 224,983    |   | $ | 197,174 |   | $ | 235,426 |   | $ | 234,195 |   |
| Net operating income |   | 14,660              |       | 19,155 |   | 32,776 |   | 40,963 |   |
| Net income           |   | 11,861              |       | 14,159 |   | 30,310 |   | 35,072 |   |
|                 |   |                |       |   |   |   |   |   |   |
| 2002                 |   |                |       |   |   |   |   |   |   |
| Operating revenues   |   | $                   | 209,023    |   | $ | 196,020 |   | $ | 235,059 |   | $ | 221,562 |   |
| Net operating income |   | 28,200              |       | 20,047 |   | 31,028 |   | 29,368 |   |
| Net income           |   | 24,357              |       | 12,752 |   | 31,085 |   | 25,190 |   |

 

As the result of EITF No. 02-03, KU has netted the power purchasedexpense for trading activities against electric operating revenue.  KU applied this guidance to all priorperiods beginning with the June 2003 10-Q filing, which had no impact onpreviously reported net income or common equity (see Note 1).

 

138

----

 
| **(in thousands)**                            |   | **Quarter  Ended  March** | ** ** |
|-----------------------------------------------|--------|---------------------------|------------|
| 2003                                          |   |                      |       |
| Gross operating revenues                      |   | $                         | 234,147    |   |
| Less costs reclassified from power  purchased |   | 9,164                     |       |
| Net operating revenues reported               |   | $                         | 224,983    |   |
|                                          |   |                      |       |
| 2002                                          |   |                      |       |
| Gross operating revenues                      |   | $                         | 215,168    |   |
| Less costs reclassified from power  purchased |   | 6,145                     |       |
| Net operating revenues reported               |   | $                         | 209,023    |   |

 

# **Note15 – Subsequent Events**

# ** **

KU made a contribution to the pension plan of $43.4 million inJanuary 2004 (see Note 6).

 

KU terminated the accounts receivable securitization program inJanuary 2004 (see Note 4).

 

InJanuary 2004, KU entered into an unsecured long-term loan with anaffiliated company totaling $50 million with an interest rate of 4.39% thatmatures in January 2012.  Theproceeds were used to repay amounts due under the accounts receivable securitizationprogram (see Note 9).

 

InFebruary 2004, KU terminated the swap it had in place at December 31,2003 related to the Series 9 pollution control bonds.  The notional amount of the terminated swap was $50 million and KUreceived a payment of $2.0 million as part of the termination. The swap was terminatedbecause it was no longer an effective hedge of the underlying bond (see Notes 4and 9).

 

139

----

 

Kentucky Utilities Company and Subsidiary

REPORT OF MANAGEMENT

 

The management of Kentucky Utilities Company and Subsidiary isresponsible for the preparation and integrity of the financial statements andrelated information included in this Annual Report.  These statements have been prepared in accordance with accountingprinciples generally accepted in the United States applied on a consistentbasis and, necessarily, include amounts that reflect the best estimates andjudgment of management.

 

KU’s 2003, 2002 and 2001 financial statements have been audited byPricewaterhouseCoopers LLP, independent auditors.  Management made available to PricewaterhouseCoopers LLP all KU’sfinancial records and related data as well as the minutes of shareholders’ anddirectors’ meetings.

 

Management has established and maintains a system of internal controlsthat provide reasonable assurance that transactions are completed in accordancewith management’s authorization, that assets are safeguarded and that financialstatements are prepared in conformity with generally accepted accountingprinciples.  Management believes that anadequate system of internal controls is maintained through the selection andtraining of personnel, appropriate division of responsibility, establishmentand communication of policies and procedures and by regular reviews of internalaccounting controls by KU’s internal auditors. Management reviews and modifies its system of internal controls in lightof changes in conditions and operations, as well as in response torecommendations from the internal and external auditors.  These recommendations for the year endedDecember 31, 2003, did not identify any material weaknesses in the designand operation of KU’s internal control structure.

 

In carrying out its oversight role for the financial reporting andinternal controls of KU, the Board of Directors meets regularly with KU’sindependent auditors, internal auditors and management.  The Board of Directors reviews the resultsof the independent auditors’ audit of the financial statements and their auditprocedures, and discusses the adequacy of internal accounting controls.  The Board of Directors also approves theannual internal auditing program, and reviews the activities and results of theinternal auditing function.  Both the independentpublic auditors and the internal auditors have access to the Board of Directorsat any time.

 

Kentucky Utilities Company and Subsidiary maintains and internallycommunicates a written code of business conduct and a senior financial officercode of ethics which address, among other items, potential conflicts ofinterest, compliance with laws, including those relating to financialdisclosure, and the confidentiality of proprietary information.

 

S. Bradford Rives

Chief Financial Officer

 

 

Kentucky Utilities Company and Subsidiary

Louisville, Kentucky

 

140

----

 

Kentucky Utilities Company and Subsidiary

REPORT OFINDEPENDENT AUDITORS

 

To the Shareholders of Kentucky Utilities Company and Subsidiary:

 

In our opinion, the accompanying consolidated balance sheets and therelated consolidated statements of capitalization, income, retained earnings,cash flows and comprehensive income present fairly, in all material respects,the financial position of Kentucky Utilities Company and Subsidiary (the“Company”) at December 31, 2003 and 2002, and the results of theiroperations and their cash flows for each of the three years in the period endedDecember 31, 2003 in conformity with accounting principles generallyaccepted in the United States of America. In addition, in our opinion, basedon our audits, the financial statementschedule as of and for the year ended December 31, 2003 listed in theindex appearing under Item 15(a)(2), presents fairly, in all material respects,the information set forth therein when read in conjunction with the relatedconsolidated****financial statements. These financial statements and financial statement schedules arethe responsibility of the Company’s management; our responsibility is toexpress an opinion on these financial statements and financial statementschedules based on our audits.  Weconducted our audits of these statements in accordance with auditing standardsgenerally accepted in the United States of America, which require that we planand perform the audit to obtain reasonable assurance about whether the financialstatements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting theamounts and disclosures in the financial statements, assessing the accountingprinciples used and significant estimates made by management, and evaluatingthe overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

As discussed in Note 1 to the consolidated financial statements,effective January 1, 2003,  KentuckyUtilities Company and Subsidiary adopted EITF No. 02-03, *Issues Involved in Accounting for DerivativeContracts Held for Trading Purposes and Contracts Involved in Energy Tradingand Risk Management Activities*. As discussed in Note 1 to the consolidated financial statements,effective January 1, 2003, Kentucky Utilities Company and Subsidiary adoptedStatement of Financial Accounting Standards No. 143, *Accounting for Asset Retirement Obligations*.

 
| /s/ PricewaterhouseCoopers LLP |   |
|--------------------------------|--------|
|                           |
| PricewaterhouseCoopers  LLP    |
| Louisville, Kentucky           |
| February 5, 2004          |

 

141

----

 

# **ITEM 9**.  Changes in and Disagreements withAccountants on Accounting and Financial Disclosure.

# ** **

Not applicable.

 

# **ITEM9A**.  Controls and Procedures

# ** **

Disclosure Controls

 

LG&E and KU maintain a system ofdisclosure controls and procedures designed to ensure that information requiredto be disclosed by the companies in reports they file or submit under theSecurities Exchange Act of 1934 is recorded, processed, summarized andreported, within the time periods specified in the Securities and ExchangeCommission rules and forms.  LG&Eand KU conducted an evaluation of such controls and procedures under thesupervision and with the participation of the companies’ Management, includingthe Chairman, President and Chief Executive Officer (“CEO”) and the ChiefFinancial Officer (“CFO”). Based upon that evaluation, the CEO and CFO are ofthe conclusion that the companies’ disclosure controls and procedures areeffective as of the end of the period covered by this report.  There has been no change in LG&E’s andKU’s internal controls over financial reporting that occurred during the fiscalquarter ended December 31, 2003 that has materially affected, or isreasonably likely to materially affect, LG&E’s and KU’s internal controlover financial reporting.

 

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 regardingexecutive officers of LG&E and KU has been included in Part I of thisForm 10-K.

 

Audit Committee Independence and Financial Expert

 

As wholly-owned subsidiaries of a common parent, LG&E and KU eachhave a three-person board of directors. Due to the small size of this board,the board as a whole performs the functions associated with auditcommittees.  The Boards of Directors ofLG&E and KU have determined that each of Victor A. Staffieri and S.Bradford Rives is an audit committee financial expert as defined by Item 401(h)of Regulation S-K.  All of the membersof the boards of LG&E and KU are officers or employees of the companies, ortheir ultimate parent, E.ON AG, and therefore are not independent within themeaning of Item 7(d)(3)(iv) of Schedule 14A of the Exchange Act.  Nevertheless, LG&E and KU believe thestructure and composition of their boards of directors and the qualificationsand attributes of their members to be fully able and competent to perform theirduties in the areas associated with audit committees.

 

Code of Ethics

 

LG&E and KU have adopted a code of ethics for senior financialofficers (including principal executive officer, principal financial officerprincipal accounting officer and controller or other employees performingsimilar functions). The Senior Financial Officer Code of Ethics is available ontheir corporate website at http://www.lgeenergy.com.  LG&E and KU intend to satisfy the disclosure requirement underItem 10 of Form 8-K regarding an amendment to, or waiver from, a provision ofthe Code of Ethics by posting such information on our website at the locationspecified above.

 

142

----

 

Section 16(a) Beneficial Ownership Reporting Compliance

 

Information regarding Section 16(a) beneficial ownership reportingcompliance is included in Exhibit 99.02 filed herewith, which information isincorporated herein by reference.

 

# **ITEM11**. 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.

 

# **ITEM12**. Security Ownership of Certain Beneficial Owners and Management.

# ** **

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, including non-stockholderapproved plans, is set forth in Exhibit 99.02 filed herewith, which informationis incorporated herein by reference.

 

# **ITEM13**. Certain Relationships and Related Transactions.

# ** **

Information regarding certain relationships and related transactions,if applicable, is set forth in Exhibit 99.02 filed herewith, which informationis incorporated herein by reference.

 

# **ITEM14**. Principal Accountant Fees and Services.

# ** **

Information regarding principal accountant fees and services is setforth in Exhibit 99.02 filed herewith, information is incorporated herein byreference.

 

PART IV

 

ITEM 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.

 

(a)                   1.      Financial Statements (included in Item 8):

 
| LG&E:                                                                                          |   |
|----------------------------------------------------------------------------------------------------|--------|
| Consolidated Statements of Income for the three years ended December 31,  2003.               |   |
| Consolidated Statements of Retained  Earnings for the three years ended December 31, 2003.    |   |
| Consolidated Statements of Comprehensive  Income for the three years ended December 31, 2003. |   |
| Consolidated Balance  Sheets-December 31, 2003, and 2002.                                     |   |
| Consolidated Statements of Cash Flows for the three years ended  December 31, 2003.           |   |
| Consolidated Statements of Capitalization-December 31, 2003, and  2002.                       |   |
| Notes to Consolidated Financial Statements.                                                        |   |
| Report of Management.                                                                              |   |
| Report of Independent Auditors.                                                                    |   |
|                                                                                               |   |
| KU:                                                                                                |   |
| Consolidated Statements of Income for the three years ended  December 31, 2003.               |   |

 

143

----

 
| Consolidated Statements of Retained  Earnings for the three years ended December 31, 2003.    |   |
|----------------------------------------------------------------------------------------------------|--------|
| Consolidated Statements of Comprehensive  Income for the three years ended December 31, 2003. |   |
| Consolidated Balance Sheets-December 31, 2003, and 2002.                                      |   |
| Consolidated Statements of Cash Flows for  the three years ended December 31, 2003.           |   |
| Consolidated Statements of  Capitalization-December 31, 2003, and 2002.                       |   |
| Notes to Consolidated Financial Statements.                                                        |   |
| Report of Management.                                                                              |   |
| Reports of Independent Auditors.                                                                   |   |

 

2.             FinancialStatement Schedules (included in Part IV):

 
| Schedule II | Valuation  and Qualifying Accounts for the three years ended December 31, 2003, for  LG&E, and KU. |   |
|------------------|------------------------------------------------------------------------------------------------------------------|--------|

 

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:

 
| **Exhibit  No.** |         | **Applicable to  Form  10-K of** |   |   |
|------------------|--------------|----------------------------------|--------|--------|
|             | **LG&E** |                             | **KU** |   | **Description** |
|             |         |                             |   |   |   |   |
| 2.01             |         | X                                |   | X      |   | Copy of Agreement and Plan of Merger, dated as of February 27,  2000, by and among Powergen plc, LG&E Energy Corp., US Subholdco2 and  Merger Sub, including certain exhibits thereto.  [Filed as Exhibit 1 to  LG&E’s and KU’s Current Report on Form 8-K filed February 29, 2000  and incorporated by reference herein] |
|             |         |                             |   |   |   |   |
| 2.02             |         | X                                |   | X      |   | Amendment No. 1 to Agreement and Plan of Merger, dated as of  December 8, 2000, among LG&E Energy Corp., Powergen plc, Powergen US  Investments Corp. and Powergen Acquisition Corp. [Filed as Exhibit 2.01 to LG&E’s  and KU’s Current Report on Form 8-K filed December 11, 2000 and  incorporated by reference herein] |
|             |         |                             |   |   |   |   |
| 2.03             |         | X                                |   | X      |   | Copy of Agreement and Plan of Merger, dated as of May 20, 1997, by  and between LG&E Energy and KU Energy, including certain exhibits  thereto.  [Filed as Exhibit 2 to LG&E’s and KU’s Current Report on  Form 8-K filed May 30, 1997 and incorporated by reference herein] |
|             |         |                             |   |   |   |   |
| 3.01             |         | X                                |   |   |   | Copy of Restated Articles of Incorporation of LG&E, dated  November 6, 1996. [Filed as Exhibit 3.06 to LG&E Quarterly Report on  Form 10-Q for the quarter ended September 30, 1996, and incorporated by  reference herein] |
|             |         |                             |   |   |   |   |
| 3.02             |         | X                                |   |   |   | Copy of Amendment to Articles of Incorporation of LG&E, dated  February 6, 2004. |

 

144

----

 
| **Exhibit  No.** |         | **Applicable to  Form  10-K of** |   |   |
|------------------|--------------|----------------------------------|--------|--------|
|             | **LG&E** |                             | **KU** |   | **Description** |
|             |         |                             |   |   |   |   |
| 3.03             |         | X                                |   |   |   | Copy of By-Laws of LG&E, as amended through December 16,  2003. |
|             |         |                             |   |   |   |   |
| 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. |
|             |         |                             |   |   |   |   |
| 3.06             |         |                             |   | X      |   | Copy of By-Laws of KU, as amended through December 16, 2003. |
|             |         |                             |   |   |   |   |
| 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 15, 1993, which is a  supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.34  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 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] |
|             |         |                             |   |   |   |   |
| 4.06             |         | X                                |   |   |   | Copy of Supplemental Indenture dated October 15, 1993, which is  a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit  4.36 to LG&E’s Annual Report on Form 10-K for the year ended  December 31, 1993, and incorporated by reference herein] |
|             |         |                             |   |   |   |   |
| 4.07             |         | 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] |

 

145

----

 
| **Exhibit  No.** |         | **Applicable to  Form  10-K of** |   |   |
|------------------|--------------|----------------------------------|--------|--------|
|             | **LG&E** |                             | **KU** |   | **Description** |
|             |         |                             |   |   |   |   |
| 4.08             |         | 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] |
|             |         |                             |   |   |   |   |
| 4.09             |         | 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.) |
|             |         |                             |   |   |   |   |
| 4.10             |         | X                                |   |   |   | Copy of Supplemental Indenture dated March 15, 2002, which is a  supplemental instrument to Exhibit 4.01 hereto.  (Filed as Exhibit 4.40 to LG&E’s Annual Report on Form 10-K  for the year ended December 31, 2002, and incorporated by reference herein.) |
|             |         |                             |   |   |   |   |
| 4.11             |         | 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.) |
|             |         |                             |   |   |   |   |
| 4.12             |         |                             |   | 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 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 |

 

146

----

 
| **Exhibit  No.** |         | **Applicable to  Form  10-K of** |   |   |
|------------------|--------------|----------------------------------|--------|--------|
|             | **LG&E** |                             | **KU** |   | **Description** |
|             |         |                             |   |   |   |   |
|             |         |                             |   |   |   | (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 4.12 hereto. [Filed as Exhibit 4.42 to  KU’s Annual Report on Form 10-K for the year ended December 31, 2001,  and incorporated by reference herein] |
|             |         |                             |   |   |   |   |
| 4.16             |         |                             |   | X      |   | Receivables Purchase Agreement dated as of February 6, 2001  among KU Receivables LLC, Kentucky Utilities Company as Servicer, the Various  Purchaser Groups From Time to Time Party Hereto and PNC Bank, National  Association, as Administrator. [Filed as Exhibit 4.43 to KU’s Annual Report  on Form 10-K for the year ended December 31, 2001, and incorporated by  reference herein] |
|             |         |                             |   |   |   |   |
| 4.17             |         |                             |   | X      |   | Purchase and Sale Agreement dated as of February 6, 2001 between  KU Receivables LLC and Kentucky Utilities Company. [Filed as Exhibit 4.44 to  KU’s Annual Report on Form 10-K for the year ended December 31, 2001,  and incorporated by reference herein] |
|             |         |                             |   |   |   |   |
| 4.18             |         | X                                |   |   |   | Receivables Purchase Agreement dated as of February 6, 2001  among LG&E Receivables LLC, Louisville Gas and Electric Company as  Servicer, the Various Purchaser Groups From Time to Time Party Hereto and PNC  Bank, National Association, as Administrator. [Filed as Exhibit 4.45 to KU’s  Annual Report on Form 10-K for the year ended December 31, 2001, and  incorporated by reference herein] |

 

147

----

 
| **Exhibit  No.** |         | **Applicable to  Form  10-K of** |   |   |
|------------------|--------------|----------------------------------|--------|--------|
|             | **LG&E** |                             | **KU** |   | **Description** |
|             |         |                             |   |   |   |   |
| 4.19             |         |                             |   | X      |   | Purchase and Sale Agreement dated as of February 6, 2001 between  LG&E Receivables LLC and Louisville Gas and Electric Company. [Filed as  Exhibit 4.46 to KU’s Annual Report on Form 10-K for the year ended  December 31, 2001, and incorporated by reference herein] |
|             |         |                             |   |   |   |   |
| 4.20             |         |                             |   | 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.) |
|             |         |                             |   |   |   |   |
| 4.21             |         |                             |   | 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.) |
|             |         |                             |   |   |   |   |
| 4.22             |         | X                                |   |   |   | Copy of Supplemental Indenture dated October 1, 2003, which is a  supplemental instrument to Exhibit 4.01 hereto. |
|             |         |                             |   |   |   |   |
| 4.23             |         |                             |   | X      |   | Copy of Loan Agreement between KU and Fidelia Corporation, dated  April 30, 2003. |
|             |         |                             |   |   |   |   |
| 4.24             |         | X                                |   |   |   | Copy of Loan Agreement between LG&E and Fidelia Corporation,  dated April 30, 2003. |
|             |         |                             |   |   |   |   |
| 4.25             |         |                             |   | X      |   | Copy of Loan Agreement between KU and Fidelia Corporation, dated  January 15, 2004. |
|             |         |                             |   |   |   |   |
| 4.26             |         |                             |   | X      |   | Copy of Loan and Security Agreement between KU and Fidelia  Corporation, dated as of August 15, 2003. |
|             |         |                             |   |   |   |   |
| 4.27             |         | X                                |   |   |   | Copy of Loan and Security Agreement between LG&E and Fidelia  Corporation, dated as of August 15, 2003. |
|             |         |                             |   |   |   |   |
| 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] |

 

148

----

 
| **Exhibit  No.** |         | **Applicable to  Form  10-K of** |   |   |
|------------------|--------------|----------------------------------|--------|--------|
|             | **LG&E** |                             | **KU** |   | **Description** |
|             |         |                             |   |   |   |   |
| 10.02            |         | X                                |   | X      |   | Copy of Modification No. 1 and No. 2 dated June 3, 1966 and  January 7, 1967, respectively, to Inter-Company Power Agreement dated  July 10, 1953.  [Filed as Exhibits 4(a)(8) and 4(a)(10) to  LG&E’s Registration Statement 2-26063 and incorporated by reference  herein] |
|             |         |                             |   |   |   |   |
| 10.03            |         | X                                |   | X      |   | Copies of Amendments to Agreements (iii) and (iv) referred to under  10.06 above as follows:  (i) Amendment to Inter-Company Bond Agreement  and (ii) Amendment to Inter-Company Bank Credit Agreement.  [Filed as  Exhibit 5.02h to LG&E’s Registration Statement 2-61607 and incorporated  by reference herein] |
|             |         |                             |   |   |   |   |
| 10.04            |         | X                                |   | X      |   | Copy of Modification No. 1, dated August 20, 1958, to First  Supplementary Transmission Agreement, dated July 10, 1953, among Ohio  Valley Electric Corporation and the Sponsoring Companies.  [Filed as  Exhibit 5.02i to LG&E’s Registration Statement 2-61607 and incorporated  by reference herein] |
|             |         |                             |   |   |   |   |
| 10.05            |         | X                                |   | X      |   | Copy of Modification No. 2, dated April 1, 1965, to the First  Supplementary Transmission Agreement, dated July 10, 1953, among Ohio  Valley Electric Corporation and the Sponsoring Companies.  [Filed as  Exhibit 5.02j to LG&E’s Registration Statement 2-61607 and incorporated  by reference herein] |
|             |         |                             |   |   |   |   |
| 10.06            |         | X                                |   | X      |   | Copy of Modification No. 3, dated January 20, 1967, to First  Supplementary Transmission Agreement, dated July 10, 1953, among Ohio  Valley Electric Corporation and the Sponsoring Companies.  [Filed as  Exhibit 4(a)(7) to LG&E’s Registration Statement 2-26063 and incorporated  by reference herein] |
|             |         |                             |   |   |   |   |
| 10.07            |         | X                                |   | X      |   | Copy of Modification No. 3 dated November 15, 1967, to the  Inter-Company Power Agreement dated July 10, 1953.  [Filed as  Exhibit 4.02m to LG&E’s Registration Statement 2-37368 and incorporated  by reference herein] |
|             |         |                             |   |   |   |   |
| 10.08            |         | X                                |   | X      |   | Copy of Modification No. 4 dated November 5, 1975, to the  Inter-Company Power Agreement dated July 10, 1953.  [Filed as  Exhibit 5.02o to LG&E’s Registration Statement 2-56357 and  incorporated by reference herein] |
|             |         |                             |   |   |   |   |
| 10.09            |         | X                                |   | X      |   | Copy of Modification No. 4 dated April 30, 1976, to First  Supplementary Transmission Agreement, dated July 10, 1953, among Ohio  Valley Electric Corporation and the Sponsoring Companies.  [Filed as  Exhibit 5.02p to LG&E’s Registration Statement 2-61607 and  incorporated by reference herein] |

 

149

----

 
| **Exhibit  No.** |         | **Applicable to  Form  10-K of** |   |   |
|------------------|--------------|----------------------------------|--------|--------|
|             | **LG&E** |                             | **KU** |   | **Description** |
|             |         |                             |   |   |   |   |
| 10.10            |         | X                                |   | X      |   | Copy of Modification No. 5 dated September 1, 1979, to  Inter-Company Power Agreement dated July 5, 1953, among Ohio Valley  Electric Corporation and Sponsoring Companies.  [Filed as Exhibit 4 to  LG&E’s Annual Report on Form 10-K for the year ended December 31,  1979, and incorporated by reference herein] |
|             |         |                             |   |   |   |   |
| 10.11            |         | X                                |   | X      |   | Copy of Modification No. 6 dated August 1, 1981, to  Inter-Company Power Agreement dated July 5, 1953, among Ohio Valley  Electric Corporation and Sponsoring Companies.  [Filed as Exhibit 10.26  to LG&E’s Annual Report on Form 10-K for the year ended December 31,  1981, and incorporated by reference herein] |
|             |         |                             |   |   |   |   |
| 10.12            |         | X                                |   |   |   | Copy of Non-Qualified Savings Plan covering officers of the Company,  effective January 1, 1992.  [Filed as Exhibit 10.43 to the  Company’s Annual Report on Form 10-K for the year ended December 31,  1992, and incorporated by reference herein] |
|             |         |                             |   |   |   |   |
| 10.13            |         | X                                |   | X      |   | Copy of Modification No. 7 dated January 15, 1992, to  Inter-Company Power Agreement dated July 10, 1953, among Ohio Valley  Electric Corporation and Sponsoring Companies.  [Filed as Exhibit 10.44  to LG&E’s Annual Report on Form 10-K for the year ended December 31,  1993, and incorporated by reference herein] |
|             |         |                             |   |   |   |   |
| 10.14            |         | X                                |   |   |   | Copies of Firm No-Notice Transportation Agreements each effective  November 1, 1993, between Texas Gas Transmission Corporation and  LG&E (expiring October 31, 2000, 2001 and 2003)  covering the  transmission of natural gas.  [All filed as Exhibit 10.47 to LG&E’s  Annual Report on Form 10-K for the year ended December 31, 1993, and  incorporated by reference herein] |
|             |         |                             |   |   |   |   |
| 10.15            |         | X                                |   | X      |   | Copy of Modification No. 8 dated January 19, 1994, to  Inter-Company Power Agreement, dated July 10, 1953, among Ohio Valley  Electric Corporation and the Sponsoring Companies.  [Filed as Exhibit  10.43 to LG&E’s Annual Report on Form 10-K for the year ended December 31,  1995, and incorporated by reference herein] |
|             |         |                             |   |   |   |   |
| 10.16            |         | X                                |   |   |   | Copy of Amendment dated March 1, 1995, to Firm No-Notice  Transportation Agreements dated November 1, 1993 (2-Year, 5-Year and  8-Year), between Texas Gas Transmission Corporation and LG&E covering the  transmission of natural gas.  [Filed as Exhibit 10.44 to LG&E’s  Annual Report on Form 10-K for the year ended December 31, 1995, and  incorporated by reference herein] |

 

150

----

 
| **Exhibit  No.** |         | **Applicable to  Form  10-K of** |   |   |
|------------------|--------------|----------------------------------|--------|--------|
|             | **LG&E** |                             | **KU** |   | **Description** |
|             |         |                             |   |   |   |   |
| 10.17            |         | 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] |
|             |         |                             |   |   |   |   |
| 10.18            |         | X                                |   |   |   | Copies of Firm Transportation Agreements, each dated March 1,  1995, between Texas Gas Transmission Corporation and LG&E (expiring  October 31, 2001 and 2003) covering the transportation of natural  gas.  [Both filed as Exhibit 10.45 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                                |   |   |   | Copy of Firm Transportation Agreement, dated March 1, 1995,  between Texas Gas Transmission Corporation and LG&E (expires  October 31, 2000) covering the transportation of natural gas. [Filed as  Exhibit 10.41 to LG&E’s Annual Report on Form 10-K for the year ended December 31,  1996, and incorporated by reference herein] |
|             |         |                             |   |   |   |   |
| 10.20            |         | 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] |
|             |         |                             |   |   |   |   |
| 10.21            |         | 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] |
|             |         |                             |   |   |   |   |
| 10.22            |         | 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] |
|             |         |                             |   |   |   |   |
| 10.23            |         | 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] |
|             |         |                             |   |   |   |   |
| 10.24            |         | X                                |   |   |   | Copy of Coal Supply Agreement between LG&E and Kindill Mining,  Inc., dated July 1, 1997.  [Filed as Exhibit 10.76 to LG&E  Energy’s Annual Report on Form 10-K for the year ended December 31,  1997, and incorporated by reference herein] |

 

151

----

 
| **Exhibit  No.** |         | **Applicable to  Form  10-K of** |   |   |
|------------------|--------------|----------------------------------|--------|--------|
|             | **LG&E** |                             | **KU** |   | **Description** |
|             |         |                             |   |   |   |   |
| 10.25            |         | X                                |   |   |   | Copies of Amendments dated September 23, 1997, to Firm No-Notice  Transportation Agreements dated November 1, 1993, between Texas Gas  Transmission Corporation and LG&E, as amended.  [Filed as Exhibit  10.81 to LG&E Energy’s Annual Report on Form 10-K for the year ended  December 31, 1997, and incorporated by reference herein] |
|             |         |                             |   |   |   |   |
| 10.26            |         | X                                |   |   |   | Copies of Amendments dated September 23, 1997, to Firm  Transportation Agreements dated March 1, 1995, between Texas Gas  Transmission Corporation and LG&E, as amended.  [Filed as Exhibit  10.82 to LG&E Energy’s Annual Report on Form 10-K for the year ended  December 31, 1997, and incorporated by reference herein] |
|             |         |                             |   |   |   |   |
| 10.27            |         | X                                |   | X      |   | Copy of Coal Supply Agreement between LG&E and KU and Black  Beauty Coal Company, dated as of January 1, 2002, covering the purchase  of coal.  [Filed as Exhibit 10.51 to LG&E’s and KU’s Annual Report  on Form 10-K for the year ended December 31, 2001, and incorporated by  reference herein] |
|             |         |                             |   |   |   |   |
| 10.28            |         | X                                |   | X      |   | Copy of Coal Supply Agreement between LG&E and KU and McElroy  Coal Company, Consolidation Coal Company, Consol Pennsylvania Coal Company,  Greenon Coal Company, Nineveh Coal Company, Eighty Four Mining Company and  Island Creek Coal Company, dated as of January 1, 2000, and Amendment  No. 1 dated as of January 1, 2002, for the purchase of coal. [Filed as  Exhibit 10.52 to LG&E’s and KU’s Annual Report on Form 10-K for the year  ended December 31, 2001, and incorporated by reference herein] |
|             |         |                             |   |   |   |   |
| 10.29            |         |                             |   | X      |   | Copy of Coal Supply Agreement between KU and Arch Coal Sales Company,  Inc., as agent for the independent operating subsidiaries of Arch Coal, Inc.,  dated as of July 22, 2001, for the purchase of coal. [Filed as Exhibit  10.53 to KU’s Annual Report on Form 10-K for the year ended December 31,  2001, and incorporated by reference herein] |
|             |         |                             |   |   |   |   |
| 10.30            |         | X                                |   |   |   | Copy of Coal Supply Agreement between LG&E and Hopkins County  Coal, LLC and Alliance Coal Sales, a division of Alliance Coal, LLC, dated as  of January 1, 2002, for the purchase of coal. [Filed as Exhibit 10.54 to  LG&E’s Annual Report on Form 10-K for the year ended December 31,  2001, and incorporated by reference herein] |
|             |         |                             |   |   |   |   |
| 10.31            |         | X                                |   |   |   | Copy of Amendment dated November 6, 2000, to Firm Transportation  Agreement between LG&E and Texas Gas Transmission Corporation covering  the transmission of natural gas (expires October 31, 2006). [Filed as  Exhibit 10.57 to LG&E’s Annual Report on Form 10-K for the year ended  December 31, 2001, and incorporated by reference herein] |

 

152

----

 
| **Exhibit  No.** |         | **Applicable to  Form  10-K of** |   |   |
|------------------|--------------|----------------------------------|--------|--------|
|             | **LG&E** |                             | **KU** |   | **Description** |
|             |         |                             |   |   |   |   |
| 10.32            |         | X                                |   |   |   | Copy of Amendment dated November 6, 2000, to Firm Transportation  Agreement between LG&E and Texas Gas Transmission Corporation covering  the transmission of natural gas (expires October 31, 2008). [Filed as  Exhibit 10.58 to LG&E’s Annual Report on Form 10-K for the year ended  December 31, 2001, and incorporated by reference herein] |
|             |         |                             |   |   |   |   |
| 10.33            |         | X                                |   |   |   | Copy of Amendment dated November 6, 2000, to Firm No-Notice  Transportation Agreement between LG&E and Texas Gas Transmission  Corporation covering the transmission of natural gas (expires  October 31, 2006). [Filed as Exhibit 10.59 to LG&E’s Annual Report  on Form 10-K for the year ended December 31, 2001, and incorporated by  reference herein] |
|             |         |                             |   |   |   |   |
| 10.34            |         | X                                |   |   |   | Copy of Amendment dated September 15, 1999, to Firm  Transportation Agreement between LG&E and Texas Gas Transmission  Corporation covering the transmission of natural gas (expires  October 31, 2005). [Filed as Exhibit 10.60 to LG&E’s Annual Report  on Form 10-K for the year ended December 31, 2001, and incorporated by  reference herein] |
|             |         |                             |   |   |   |   |
| 10.35            |         | 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] |
|             |         |                             |   |   |   |   |
| 10.36            |         | 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.) |
|             |         |                             |   |   |   |   |
| 10.37            |         | X                                |   | X      |   | * Copy of Amendment, effective October 1, 1999, to LG&E  Energy’s Non-Qualified Savings Plan. [Filed as Exhibit 10.96 to LG&E’s  and KU’s Annual Report on Form 10-K for the year ended December 31,  1999, and incorporated by reference herein] |
|             |         |                             |   |   |   |   |
| 10.38            |         | 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] |
|             |         |                             |   |   |   |   |
| 10.39            |         | 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] |

 

153

----

 
| **Exhibit  No.** |         | **Applicable to  Form  10-K of** |   |   |
|------------------|--------------|----------------------------------|--------|--------|
|             | **LG&E** |                             | **KU** |   | **Description** |
|             |         |                             |   |   |   |   |
| 10.40            |         | 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] |
|             |         |                             |   |   |   |   |
| 10.41            |         | X                                |   |   |   | Copy of Letter Amendment, dated September 15, 1999, to Firm  No-Notice Transportation Agreement, dated November 1, 1993, between  LG&E and Texas Gas Transmission Corporation. [Filed as Exhibit 10.106 to  LG&E’s Annual Report on Form 10-K for the year ended December 31,  1999, and incorporated by reference herein] |
|             |         |                             |   |   |   |   |
| 10.42            |         | 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] |
|             |         |                             |   |   |   |   |
| 10.43            |         | 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] |
|             |         |                             |   |   |   |   |
| 10.44            |         | 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] |
|             |         |                             |   |   |   |   |
| 10.45            |         | 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] |
|             |         |                             |   |   |   |   |
| 10.46            |         | X                                |   |   |   | Copy of Amendment dated June 5, 2002, to Firm No-Notice  Transportation Agreement dated November 1, 1993, between LG&E and  Texas Gas Transmission Corporation covering the transmission of natural gas  (expires October 31, 2008). [Filed as Exhibit 10.64 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] |

 

154

----

 
| **Exhibit  No.** |         | **Applicable to  Form  10-K of** |   |   |
|------------------|--------------|----------------------------------|--------|--------|
|             | **LG&E** |                             | **KU** |   | **Description** |
|             |         |                             |   |   |   |   |
| 10.47            |         | X                                |   |   |   | Copy of Firm Transportation Service Agreement dated November 1,  2002, between LG&E and Tennessee Gas Pipeline Company covering the transmission  of natural gas (expires October 31, 2012).  [Filed as Exhibit 10.65 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] |
|             |         |                             |   |   |   |   |
| 10.48            |         | X                                |   |   |   | Copy of Amendment No. 1 dated January 1, 2001, to Coal Supply  Agreement dated July 1, 1997, between LG&E and Kindill Mining,  Inc.  [Filed as Exhibit 10.66 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] |
|             |         |                             |   |   |   |   |
| 10.49            |         | X                                |   |   |   | Copy of Amendment No. 2 dated January 1, 2002, to Coal Supply  Agreement dated July 1, 1997, between LG&E and Kindill Mining,  Inc.  [Filed as Exhibit 10.67 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] |
|             |         |                             |   |   |   |   |
| 10.50            |         | X                                |   | X      |   | Copy of Amendment No. 2 dated January 1, 2003, to Coal Supply  Agreement dated January 1, 2000, between LG&E and KU and McElroy  Coal Company, Consolidation Coal Company, Consol Pennsylvania Coal Company,  Greenon Coal Company, Nineveh Coal Company, Eighty Four Mining Company and  Island Creek Coal Company.  [Filed as  Exhibit 10.68 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] |
|             |         |                             |   |   |   |   |
| 10.51            |         | X                                |   |   |   | Copy of Coal Supply Agreement dated January 1, 2003, between  LG&E and Peabody Coalsales Company.   [Filed as Exhibit 10.69 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] |
|             |         |                             |   |   |   |   |
| 10.52            |         | X                                |   |   |   | Copy of Coal Supply Agreement dated January 1, 2002, between  LG&E and Peabody Coalsales Company.   [Filed as Exhibit 10.70 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] |
|             |         |                             |   |   |   |   |
| 10.53            |         | X                                |   |   |   | Copy of Amendment No. 1 dated June 1, 2002, to Coal Supply  Agreement dated January 1, 2002, between LG&E and Peabody Coalsales  Company. [Filed as Exhibit 10.71 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] |
|             |         |                             |   |   |   |   |
| 10.54            |         | X                                |   |   |   | Copy of  Amendment No. 2 dated January 1, 2003, to Coal  Supply Agreement dated January 1, 2002, between LG&E and Peabody  Coalsales Company.  [Filed as Exhibit  10.72 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] |

 

155

----

 
| **Exhibit  No.** |         | **Applicable to  Form  10-K of** |   |   |
|------------------|--------------|----------------------------------|--------|--------|
|             | **LG&E** |                             | **KU** |   | **Description** |
|             |         |                             |   |   |   |   |
| 10.55            |         |                             |   | X      |   | Copy of Coal Supply Agreement dated January 1, 2002, between KU  and Massey Coal Sales Company, Inc.   [Filed as Exhibit 10.73 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] |
|             |         |                             |   |   |   |   |
| 10.56            |         | X                                |   | X      |   | *Copy of Third Amendment, dated July 1, 2002, to Employment and  Severance Agreement dated as of February 25, 2000 by and among E.ON AG,  LG&E Energy, Powergen and Victor A. Staffieri.  [Filed as Exhibit 10.74 to LG&E’s and KU’s Annual Report on  Form 10-K for the year ended December 31, 2002, and incorporated by  reference herein] |
|             |         |                             |   |   |   |   |
| 10.57            |         | 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] |
|             |         |                             |   |   |   |   |
| 10.58            |         | 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] |
|             |         |                             |   |   |   |   |
| 10.59            |         | X                                |   | X      |   | *Copy of Terms and Conditions for Stock Options Issued as part of  E.ON Group’s Stock Option Programs, applicable to certain executive officers  of the Companies.  [Filed as Exhibit  10.79 to LG&E’s and KU’s Annual Report on Form 10-K for the year ended  December 31, 2002, and incorporated by reference herein] |
|             |         |                             |   |   |   |   |
| 10.60            |         | X                                |   | X      |   | Copy of Amendment No. 1 dated as of January 1, 2004, to Coal  Supply Agreement dated as of January 1, 2002, between LG&E, KU and  Black Beauty Coal Company |
|             |         |                             |   |   |   |   |
| 10.61            |         |                             |   | X      |   | Copy of Amendment No. 1 dated as of July 1, 2003, to Coal Supply  Agreement dated as of January 1, 2002, between KU and Arch Coal Sales  Company, Inc. |
|             |         |                             |   |   |   |   |
| 10.62            |         | X                                |   |   |   | Copy of Amendment No. 1 dated as of January 1, 2000, to Amended  and Restated Coal Supply Agreement dated as of April 1, 1998, between  LG&E and Hopkins County Coal, LLC and Webster County Coal, LLC as  successor to Webster County Coal Corporation. |

 

156

----

 
| **Exhibit  No.** |         | **Applicable to  Form  10-K of** |   |   |
|------------------|--------------|----------------------------------|--------|--------|
|             | **LG&E** |                             | **KU** |   | **Description** |
|             |         |                             |   |   |   |   |
| 10.63            |         | X                                |   |   |   | Copy of Amendment No. 2 dated as of September 15, 2000, to  Amended and Restated Coal Supply Agreement dated as of April 1, 1998, as  amended by Amendment No. 1 dated January 1, 2000 between LG&E and  Hopkins County Coal, LLC and Webster County Coal, LLC, as successor to  Webster County Coal Corporation. |
|             |         |                             |   |   |   |   |
| 10.64            |         | X                                |   |   |   | Copy of Amendment No. 3 dated as of September 15, 2003,  to Coal Supply Agreement dated as of  January 1, 2002, as amended by Amendment No. 1 dated effective  June 1, 2002, and Amendment No. 2 dated effective January 1, 2003,  between LG&E and Peabody Coalsales Company. |
|             |         |                             |   |   |   |   |
| 10.65            |         | X                                |   | X      |   | *Copy of LG&E Energy Corp. Long-Term Performance Unit Plan,  adopted April 25, 2003, effective January 1, 2003. |
|             |         |                             |   |   |   |   |
| 10.66            |         |                             |   |   |   | [NOT USED] |
|             |         |                             |   |   |   |   |
| 10.67            |         |                             |   |   |   | [NOT USED] |
|             |         |                             |   |   |   |   |
| 10.68            |         |                             |   |   |   | [NOT USED] |
|             |         |                             |   |   |   |   |
| 10.69            |         | 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. |
|             |         |                             |   |   |   |   |
| 10.70            |         | 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. |
|             |         |                             |   |   |   |   |
| 10.71            |         | 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. |
|             |         |                             |   |   |   |   |
| 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. |

 

157

----

 
| **Exhibit  No.** |         | **Applicable to  Form  10-K of** |   |   |
|------------------|--------------|----------------------------------|--------|--------|
|             | **LG&E** |                             | **KU** |   | **Description** |
| 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. |

 

(b)   Reports on Form 8-K:

 

On November 13, 2003, LG&E and KU filed a Current Report onForm 8-K to present reclassified financial statements and other financialinformation in accordance with the requirements of Emerging Issues Task ForceIssue No. 02-03.

 

On November 25, 2003 and December 30, 2003, LG&E and KUfiled Current Reports describing their intention and submission, respectively,of requests to the Kentucky Public Service Commission for increases in electricand gas base rates, as applicable.

 

(c)   Executive Compensation Plans and Arrangements:

 

Exhibits preceded by an asterisk (“*”) above are management contracts,compensation plans or arrangements required to be filed as an exhibit pursuantto Item 15(c) of Form 10-K.

 

(d)   The following instruments defining the rights ofholders of certain long- term debt of KU have not been filed with theSecurities and Exchange Commission but will be furnished to the Commission uponrequest.

 

1.     Loan Agreement dated as of May 1, 1990, between KUand the County of Mercer, Kentucky, in connection with $12,900,000 County ofMercer, Kentucky, Collateralized Solid Waste Disposal Facility Revenue Bonds(KU Project) 1990 Series A, due May 1, 2010 and May 1, 2020.

 

2.     Loan Agreement dated as of May 1, 1991, between KUand the County of Carroll, Kentucky, in connection with $96,000,000 County ofCarroll, Kentucky, Collateralized Pollution Control Revenue Bonds (KU Project)1992 Series A, due September 15, 2016.

 

3.     Loan Agreement dated as of August 1, 1992,between KU and the County of Carroll, Kentucky, in 

 

158

----

 

connection with $2,400,000 County of Carroll, Kentucky, CollateralizedPollution Control Revenue Bonds (KU Project) 1992 Series C, dueFebruary 1, 2018.

 

4.     Loan Agreement dated as of August 1, 1992,between KU and the County of Muhlenberg, Kentucky, in connection with$7,200,000 County of Muhlenberg, Kentucky, Collateralized Pollution Control RevenueBonds (KU Project) 1992 Series A, due February 1, 2018.

 

5.     Loan Agreement dated as of August 1, 1992,between KU and the County of Mercer, Kentucky, in connection with $7,400,000County of Mercer, Kentucky, Collateralized Pollution Control Revenue Bonds (KUProject) 1992 Series A, due February 1, 2018.

 

6.     Loan Agreement dated as of August 1, 1992,between KU and the County of Carroll, Kentucky, in connection with $20,930,000County of Carroll, Kentucky, Collateralized Pollution Control Revenue Bonds (KUProject) 1992 Series B, due February 1, 2018.

 

7.     Loan Agreement dated as of December 1, 1993,between KU and the County of Carroll, Kentucky, in connection with $50,000,000County of Carroll, Kentucky, Collateralized Solid Waste Disposal FacilitiesRevenue Bonds (KU Project) 1993 Series A, due December 1, 2023.

 

8.     Loan Agreement dated as of November 1, 1994,between KU and the County of Carroll, Kentucky, in connection with $54,000,000County of Carroll, Kentucky, Collateralized Solid Waste Disposal FacilitiesRevenue Bonds (KU Project) 1994 Series A, due November 1,  2024.

 

159

----

 

Schedule II

 

Louisville Gas and Electric Company

Schedule II - Valuation and QualifyingAccounts

For the Three Years Ended December 31,2003

(Thousands of $)

 
|                                                   |   | **Other  Property  and  Investments** |   | **Accounts  Receivable  (Uncollectible  Accounts)** |   |
|--------------------------------------------------------|--------|---------------------------------------|--------|-----------------------------------------------------|--------|
|                                                   |   |                                  |   |                                                |   |
| Balance December 31, 2000                         |   | $                                     | 63     |                                                | $      | 1,286 |   |
|                                                   |   |                                  |   |                                                |   |
| Additions:                                             |   |                                  |   |                                                |   |
| Charged to costs and expenses                          |   | —                                |   | 4,953                                               |   |
|                                                   |   |                                  |   |                                                |   |
| Deductions:                                            |   |                                  |   |                                                |   |
| Net charges of nature for which reserves  were created |   | —                                |   | 4,664                                               |   |
|                                                   |   |                                  |   |                                                |   |
| Balance December 31, 2001                         |   | 63                                    |   | 1,575                                               |   |
|                                                   |   |                                  |   |                                                |   |
| Additions:                                             |   |                                  |   |                                                |   |
| Charged to costs and expenses                          |   | —                                |   | 4,459                                               |   |
|                                                   |   |                                  |   |                                                |   |
| Deductions:                                            |   |                                  |   |                                                |   |
| Net charges of nature for which reserves  were created |   | —                                |   | 3,909                                               |   |
|                                                   |   |                                  |   |                                                |   |
| Balance December 31, 2002                         |   | 63                                    |   | 2,125                                               |   |
|                                                   |   |                                  |   |                                                |   |
| Additions:                                             |   |                                  |   |                                                |   |
| Charged to costs and expenses                          |   | —                                |   | 5,477                                               |   |
|                                                   |   |                                  |   |                                                |   |
| Deductions:                                            |   |                                  |   |                                                |   |
| Net charges of nature for which reserves  were created |   | —                                |   | 4,087                                               |   |
|                                                   |   |                                  |   |                                                |   |
| Balance December 31, 2003                         |   | $                                     | 63     |                                                | $      | 3,515 |   |

 

160

----

 

Schedule II

 

Kentucky Utilities Company

Schedule II - Valuation and QualifyingAccounts

For the Three Years Ended December 31,2003

(Thousands of $)

 
|                                                   |   | **Other  Property  and  Investments** |   | **Accounts  Receivable  (Uncollectible  Accounts)** |   |
|--------------------------------------------------------|--------|---------------------------------------|--------|-----------------------------------------------------|--------|
|                                                   |   |                                  |   |                                                |   |
| Balance December 31, 2000                         |   | $                                     | 751    |                                                | $      | 800 |   |
|                                                   |   |                                  |   |                                                |   |
| Additions:                                             |   |                                  |   |                                                |   |
| Charged to costs and expenses                          |   | 9                                     |   | 1,528                                               |   |
| Deductions:                                            |   |                                  |   |                                                |   |
| Net charges of nature for which reserves  were created |   | 630                                   |   | 1,528                                               |   |
|                                                   |   |                                  |   |                                                |   |
| Balance December 31, 2001                         |   | 130                                   |   | 800                                                 |   |
|                                                   |   |                                  |   |                                                |   |
| Additions:                                             |   |                                  |   |                                                |   |
| Charged to costs and expenses                          |   | —                                |   | 1,314                                               |   |
|                                                   |   |                                  |   |                                                |   |
| Deductions:                                            |   |                                  |   |                                                |   |
| Net charges of nature for which reserves  were created |   | —                                |   | 1,314                                               |   |
|                                                   |   |                                  |   |                                                |   |
| Balance December 31, 2002                         |   | 130                                   |   | 800                                                 |   |
|                                                   |   |                                  |   |                                                |   |
| Additions:                                             |   |                                  |   |                                                |   |
| Charged to costs and expenses                          |   | —                                |   | 1,492                                               |   |
|                                                   |   |                                  |   |                                                |   |
| Deductions:                                            |   |                                  |   |                                                |   |
| Net charges of nature for which reserves  were created |   | —                                |   | 1,620                                               |   |
|                                                   |   |                                  |   |                                                |   |
| Balance December 31, 2003                         |   | $                                     | 130    |                                                | $      | 672 |   |

 

161

----

 

SIGNATURES – LOUISVILLE GAS AND ELECTRIC COMPANY

 

Pursuant to the requirements of Section 13 or 15(d) of theSecurities Exchange Act of 1934, the registrant has duly caused this report tobe signed on its behalf by the undersigned, thereunto duly authorized.

 
|                | LOUISVILLE GAS AND ELECTRIC COMPANY |
|---------------------|-------------------------------------|
|                | Registrant                          |
|                |                                |
| March 29, 2004 | /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                         |   |     |

 

 
| By     | /s/ S. Bradford Rives |   | March 29, 2004 |
|--------|-----------------------|--------|---------------------|
|   | (Attorney-In-Fact)    |   |

 

162

----

 

SIGNATURES – KENTUCKY UTILITIES COMPANY

 

Pursuant to the requirements of Section 13 or 15(d) of theSecurities Exchange Act of 1934, the registrant has duly caused this report tobe signed on its behalf by the undersigned, thereunto duly authorized.

 
|                | KENTUCKY UTILITIES COMPANY |
|---------------------|----------------------------|
|                | Registrant                 |
|                |                       |
| March 29, 2004 | /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                         |   |     |

 

 
| By     | /s/ S. Bradford Rives |   | March 29, 2004 |
|--------|-----------------------|--------|---------------------|
|   | (Attorney-In-Fact)    |   |

 

163

----