**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, 2002** |
|                                             |
| **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 |
|-----------------------------|--------|----------------------------------------------------------------------------------------|--------|--------------------------------------|
|                        |   |                                                                                   |   |                                 |
| **2-26720**                 |   | **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 Securities ExchangeAct of 1934 during the preceding 12 months (or for such shorter period that theregistrants were required to file such reports), and (2) have been subject tosuch filing requirements for the past 90 days. Yes  ý  No  o

 

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

 

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

 

As of June 28, 2002, the aggregate market value of the common stock ofeach of Louisville Gas and Electric Company and Kentucky Utilities Company heldby non-affiliates was $0.  As of February28, 2003, Louisville Gas and Electric Company had 21,294,223 shares of commonstock outstanding, all held by LG&E Energy Corp.  Kentucky Utilities Company had 37,817,878 shares of common stockoutstanding, all held by LG&E Energy Corp.

 

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 BYREFERENCE

 

Not applicable.

 

 

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TABLE OF CONTENTS

 
| PART I     |
|------------|
|       |
| Item 1.    | Business |
|       | Louisville Gas and  Electric Company |
|       | General |
|       | Electric  Operations |
|       | Gas Operations |
|       | Rates  and Regulation |
|       | Construction Program  and Financing |
|       | Coal Supply |
|       | Gas Supply |
|       | Environmental  Matters |
|       | Competition |
|       | Kentucky Utilities Company |
|       | General |
|       | Electric  Operations |
|       | Rates  and Regulation |
|       | Construction Program  and Financing |
|       | Coal Supply |
|       | Environmental  Matters |
|       | Competition |
|       | Employees and Labor  Relations |
|       | 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 Disclosures About Market Risk |
| Item  8.   | Financial  Statements and Supplementary Data: |
|       | Louisville  Gas and Electric Company |
|       | Kentucky  Utilities Company |
| Item  9.   | Changes  in and Disagreements with Accountants on Accounting and Financial Disclosure |
|       |   |
| PART III   |
|       |
| Item  10.  | Directors  and Executive Officers of the Registrant (a) |
| Item 11.   | Executive  Compensation (a) |
| Item 12.   | Security  Ownership of Certain Beneficial Owners and Management (a) |
| Item 13.   | Certain  Relationships and Related Transactions (a) |
|       |   |
| PART IV    |
|       |
| Item 14.   | Controls and  Procedures |
| Item  15.  | Exhibits,  Financial Statement Schedules, and Reports on Form 8-K |
| Signatures |

 

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| (a) Incorporated by reference. |
|--------------------------------|

 

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INDEX OF ABBREVIATIONS

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

 

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

 

 

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PART I.

 

Item 1.  Business.

 

LG&E and KU are each subsidiaries of LG&E Energy.  On December 11, 2000, LG&E Energywas acquired by Powergen plc, now known as Powergen Limited, for cash of approximately$3.2 billion or $24.85 per share and the assumption of all of LG&E Energy’sdebt.  As a result of the acquisition,among other things, LG&E Energy became a wholly owned subsidiary ofPowergen and, as a result, LG&E and KU became indirect subsidiaries ofPowergen.  The utility operations(LG&E and KU) of LG&E Energy have continued their separate identitiesand continue to serve customers in Kentucky, Virginia and Tennessee under theirexisting names.  The preferred stock anddebt securities of the utility operations were not affected by this transactionresulting in the utility operations’ obligations to continue to file SECreports.  Following the acquisition,Powergen became a registered holding company under PUHCA, and LG&E and KU,as subsidiaries of a registered holding company, became subject to additionalregulation 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&EServices provides certain services to affiliated entities, including LG&Eand KU, at cost as required under PUHCA. On January 1, 2001, approximately 1,000 employees, mainly from LG&EEnergy, LG&E and KU, were moved to LG&E Services.

 

On July 1, 2002, E.ON, a German company, completed its acquisition ofPowergen following receipt of all necessary regulatory approvals.  E.ONhad announced its pre-conditional cash offer of £5.1 billion ($7.3 billion) forPowergen on April 9, 2001.

 

LOUISVILLE GAS AND ELECTRIC COMPANY

 

General

 

Incorporated in 1913 in Kentucky, LG&E is a regulated publicutility that supplies natural gas to approximately 310,000 customers andelectricity to approximately 382,000 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 consolidatedsubsidiary, LG&E R. LG&E R is a special purpose entity formed inSeptember 2000 to enter into accounts receivable securitization transactionswith LG&E.  LG&E R startedoperations in 2001.  LG&E isconsidering unwinding its accounts receivable securitization arrangementsinvolving LG&E R during 2003.

 

6

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For the year ended December 31, 2002, 74% oftotal operating revenues were derived from electric operations and 26% from gasoperations.  Electric and gasoperating revenues and the percentages by class of service on a combined basisfor this period were as follows:

 
|                           |   | **(Thousands  of $)** |    |    |   |         |   |
|--------------------------------|--------|-----------------------|---------|---------|--------|--------------|--------|
|                           |   | **Electric**          |    | **Gas** |   | **Combined** |   | **% Combined** |   |
| Residential                    |   | $                     | 232,285 |    | $      | 160,733      |   | $ | 393,018 |   | 47 | % |
| Commercial                     |   | 185,112               |    | 61,036  |   | 246,148      |   | 30 | % |
| Industrial                     |   | 111,871               |    | 10,232  |   | 122,103      |   | 15 | % |
| Public authorities             |   | 57,703                |    | 11,197  |   | 68,900       |   | 8 | % |
| Total retail                   |   | 586,971               |    | 243,198 |   | 830,169      |   | 100 | % |
| Wholesale sales                |   | 143,002               |    | 16,384  |   | 159,386      |   |   |   |
| Gas transported – net     |   | —                |    | 6,232   |   | 6,232        |   |   |   |
| Provision for rate collections |   | 12,267                |    | —  |   | 12,267       |   |   |   |
| Miscellaneous                  |   | 16,251                |    | 1,879   |   | 18,130       |   |   |   |
| Total                          |   | $                     | 758,491 |    | $      | 267,693      |   | $ | 1,026,184 |   |   |   |
|                                |        |                       |         |         |        |              |        |  |  |  |  |  |  |

 

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, 2002.

 

ElectricOperations

 

The sources of LG&E’s electric operating revenues and the volumesof sales for the three years ended December 31, 2002, were as follows:

 
|                                     |   | **2002** |    | **2001** |   | **2000** |   |
|------------------------------------------|--------|----------|---------|----------|--------|----------|--------|
| ELECTRIC OPERATING REVENUES              |   |     |    |     |   |     |   |
| (Thousands of $)                         |   |     |    |     |   |     |   |
| Residential                              |   | $        | 232,285 |     | $      | 205,926  |   | $ | 205,105 |   |
| Commercial                               |   | 185,112  |    | 171,540  |   | 171,414  |   |
| Industrial                               |   | 111,871  |    | 104,438  |   | 104,738  |   |
| Public authorities                       |   | 57,703   |    | 53,725   |   | 54,270   |   |
| Total retail                             |   | 586,971  |    | 535,629  |   | 535,527  |   |
| Wholesale sales                          |   | 143,002  |    | 159,406  |   | 165,080  |   |
| Provision for rate collections (refunds) |   | 12,267   |    | (720     | )      | (2,500   | )      |
| Miscellaneous                            |   | 16,251   |    | 11,610   |   | 12,851   |   |
| Total                                    |   | $        | 758,491 |     | $      | 705,925  |   | $ | 710,958 |   |
|                                     |   |     |    |     |   |     |   |
| ELECTRIC SALES (Thousands of Mwh):       |   |     |    |     |   |     |   |
| Residential                              |   | 4,036    |    | 3,782    |   | 3,722    |   |
| Commercial                               |   | 3,493    |    | 3,395    |   | 3,350    |   |
| Industrial                               |   | 3,028    |    | 2,976    |   | 3,043    |   |
| Public authorities                       |   | 1,253    |    | 1,224    |   | 1,214    |   |
| Total retail                             |   | 11,810   |    | 11,377   |   | 11,329   |   |
| Wholesale sales                          |   | 7,262    |    | 6,957    |   | 6,834    |   |
| Total                                    |   | 19,072   |    | 18,334   |   | 18,163   |   |

 

LG&E uses efficient coal-fired boilers, fullyequipped with sulfur dioxide removal systems, to generate most of its 

 

7

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electricity. LG&E’s weighted-average system-wide emission rate for sulfur dioxidein 2002 was approximately 0.55 lbs./Mmbtu of heat input, with every generatingunit below its emission limit established by the Kentucky Division for AirQuality.

 

LG&E set a record local peak load of 2,623 Mwon Monday, August 5, 2002, when the peak daily temperature was 100 degrees F.

 

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

 

LG&E currently maintains a 13 – 15% reservemargin range.  At December 31, 2002,LG&E owned steam and combustion turbine generating facilities with a netsummer capability of 2,882 Mw and an 80 Mw nameplate rated hydroelectricfacility on the Ohio River with a summer capability rate of 48 Mw.  At December 31, 2002, LG&E’s system netsummer capability, including purchases from others and excluding thehydroelectric facility, was 3,037 Mw. See Item 2, Properties.

 

LG&E and 11 other electric utilities are participating owners ofOVEC located in Piketon, Ohio.  OVECowns and operates two power plants that burn coal to generate electricity,Kyger Creek Station in Ohio and Clifty Creek Station in Indiana. LG&E’sshare is 7%, representing approximately 155 Mw’s of generation capacity. LG&E also has agreements with a number ofentities throughout the United States for the purchase and/or sale of capacityand energy and for the utilization of their bulk transmission system.

 

On February 1, 2002, LG&E (along with KU) turned over operationalcontrol of its high voltage transmission facilities (100kV and above) toMISO.  LG&E (along with KU) is afounding member of MISO.  Such membershipwas obtained in 1998 in response to and consistent with federal policyinitiatives.  MISO operates a singleOATT over the facilities under its control. Currently MISO controls over 100,000 miles of transmission over 1.1million square miles located in the northern Midwest between Manitoba, Canadaand Kentucky.  On September 18, 2002, FERCgranted a 12.88% ROE on transmission facilities for LG&E, KU and the restof the MISO owners.  This ROE includes a50 basis point increase because of operational independence.

 

MISO plans to implement a Congestion Management System in December2003, in compliance with FERC Order 2000. This system will be similar to the Locational Marginal Pricing (LMP)system currently used by the PJM RTO and contemplated in FERC’s SMD NOPR,currently being discussed.  MISO filedwith FERC a mechanism for recovery of costs for the Congestion ManagementSystem, designated Schedule 16 and Schedule 17.  The MISO transmission owners, including LG&E and KU, andothers have objected to the allocation of costs between market participants andretail native load.  This case is currentlyin a hearing at FERC.

 

In October 2001, the FERC issued an order requiring that the bundledretail load and grandfathered wholesale load of each member transmission owner(including LG&E) be included in the current calculation of MISO’s“cost-adder,” a charge designed to recover MISO’s costs of operation, includingstart-up capital (debt) costs. LG&E, along with several other transmission owners, opposed theFERC’s ruling in this regard, which opposition the FERC rejected in an order onrehearing issued in 2002.   Later thatyear, MISO’s transmission owners, including LG&E, appealed the FERC’sdecision to the United States Court of Appeals for the District of ColumbiaCircuit.  In response, by petition filedNovember 25, 2002, the FERC requested that the Court issue a partial remand ofits challenged orders to allow the FERC to revisit certain issues raisedtherein, and further requested that the case be held in abeyance pending theagency’s resolution of such issues.  TheCourt granted the FERC’s petition by order dated December 6, 2002.   On February 24, 2003, FERC issued an order 

 

8

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reaffirming its position concerning the calculation of the“cost-adder”.

 

As a separate matter, MISO, its transmission owners and otherinterested industry segments reached a settlement in mid-2002 regarding thelevel**ofcost responsibility properly borne by bundled and grandfathered load underthese FERC rulings (such settlement expressly not prejudicing the transmissionowners’ and LG&E’s right to challenge the FERC’s ruling imposing costresponsibility on bundled loads in the first instance).  On February 24, 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 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.

 

Gas Operations

 

The sources of LG&E’s gas operating revenues and the volumes ofsales for the three years ended December 31, 2002, were as follows:

 
|                             |   | **2002** |    | **2001** |   | **2000** |   |
|----------------------------------|--------|----------|---------|----------|--------|----------|--------|
| GAS OPERATING REVENUES           |   |     |    |     |   |     |   |
| (Thousands of $)                 |   |     |    |     |   |     |   |
| Residential                      |   | $        | 160,733 |     | $      | 177,387  |   | $ | 159,670 |   |
| Commercial                       |   | 61,036   |    | 70,296   |   | 61,888   |   |
| Industrial                       |   | 10,232   |    | 15,750   |   | 15,898   |   |
| Public authorities               |   | 11,197   |    | 13,223   |   | 9,193    |   |
| Total retail                     |   | 243,198  |    | 276,656  |   | 246,649  |   |
| Wholesale sales                  |   | 16,384   |    | 5,702    |   | 17,344   |   |
| Gas transported – net       |   | 6,232    |    | 6,042    |   | 6,922    |   |
| Miscellaneous                    |   | 1,879    |    | 2,375    |   | 1,574    |   |
| Total                            |   | $        | 267,693 |     | $      | 290,775  |   | $ | 272,489 |   |
|                             |   |     |    |     |   |     |   |
| GAS SALES (Millions of cu. ft.): |   |     |    |     |   |     |   |
| Residential                      |   | 22,124   |    | 20,429   |   | 24,274   |   |
| Commercial                       |   | 9,074    |    | 8,587    |   | 10,132   |   |
| Industrial                       |   | 1,783    |    | 2,160    |   | 3,089    |   |
| Public authorities               |   | 1,747    |    | 1,681    |   | 1,576    |   |
| Total retail                     |   | 34,728   |    | 32,857   |   | 39,071   |   |
| Wholesale sales                  |   | 5,345    |    | 1,882    |   | 5,115    |   |
| Gas transported                  |   | 13,939   |    | 13,108   |   | 14,729   |   |
| Total                            |   | 54,012   |    | 47,847   |   | 58,915   |   |

 

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

 

LG&E has five underground natural gas storagefields that help provide economical and reliable gas service to ultimateconsumers.  By using gas storagefacilities, LG&E avoids the costs associated with typically more expensivepipeline transportation 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 tobuy additional gas and pipeline transportation services when customer demandincreases, likely to be when the price for those items are typically at theirhighest.  Currently, LG&E buyscompetitively 

 

9

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priced 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, 2002, LG&E had aninventory balance of gas stored underground of 12.6 million Mcf valued at $50.3million.

 

A number of industrial customers purchase theirnatural gas requirements directly from alternate suppliers for delivery throughLG&E’s distribution system.  Theselarge industrial customers account for about one-fourth of LG&E’s annualthroughput.

 

The all-time maximum day gas sendout of 545,000Mcf occurred on Sunday, January 20, 1985, when the average temperature for theday was -11 degrees F.  During 2002,maximum day gas sendout was approximately 418,000 Mcf, occurring on February27, 2002, when the average temperature for the day was 21 degrees F.  Supply on that day consisted ofapproximately 130,000 Mcf from purchases, approximately 221,000 Mcf deliveredfrom underground storage, and approximately 67,000 Mcf transported forindustrial customers.  For a furtherdiscussion, see Gas Supply under Item 1.

 

Rates andRegulation

 

Following the purchase ofPowergen by E.ON, E.ON became a registered holding company under PUHCA.  As a result, E.ON, its utility subsidiaries,including LG&E, and certain of its non-utility subsidiaries are subject toextensive regulation by the SEC under PUHCA with respect to issuances and salesof securities, acquisitions and sales of certain utility properties, andintra-system sales of certain goods and services.  In addition, PUHCA generally limits the ability of registeredholding companies to acquire additional public utility systems and to acquireand retain businesses unrelated to the utility operations of the holdingcompany.  LG&E believes that it hasadequate authority (including financing authority) under existing SEC ordersand regulations to conduct its business. LG&E will seek additional authorization when necessary.

 

No costs associated with the E.ON purchase ofPowergen or the Powergen purchase of LG&E Energy nor any effects ofpurchase accounting have been reflected in the financial statements ofLG&E.

 

The Kentucky Commission has regulatoryjurisdiction over the rates and service of LG&E and over the issuance ofcertain of its securities.  The KentuckyCommission has the ability to examine the rates LG&E charges its retailcustomers at any time.  LG&E is a“public utility” as defined in the FPA, and is subject to the jurisdiction ofthe Department of Energy and FERC with respect to the matters covered in theFPA, including the sale of electric energy at wholesale in interstate commerce.

 

For a discussion of current regulatory matters,see Rates and Regulation for LG&E under Item 7 and Note 3 of LG&E’sNotes to Financial Statements under Item 8.

 

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

 

LG&E’s retail electric rates are subject toan ESM.  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 

 

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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 year subjectto a balancing adjustment in successive periods.  LG&E made its second ESM filing on March 1, 2002, forthe calendar year 2001 reporting period. LG&E is in the process of refunding $441,000 to customers for the2001 reporting period.  LG&E estimated that the rate of return willfall below the lower limit, subject to Kentucky Commission approval, for theyear ended December 31, 2002.  The 2002financial statements include an accrual to reflect the earnings deficiency of$12.5 million to be recovered from customers commencing in April 2003.

 

On November 27, 2002, LG&E filed a revised ESM tariff whichproposed continuance of the existing ESM through 2005.  The Kentucky Commission issued an Ordersuspending the ESM tariff one day making the effective date January 2,2003.  In addition, the KentuckyCommission is conducting a management audit to review the ESM plan and reassessits reasonableness in 2003.  LG&E andinterested parties will have the opportunity to provide recommendations formodification and continuance of the ESM or other forms of alternative orincentive regulation.

 

LG&E’s retail rates contain an ECR surchargewhich recovers certain costs incurred by LG&E that are required to complywith the Clean Air Act and other environmental regulations.  See Note 3 of LG&E’s Notes toFinancial Statements under Item 8.

 

LG&E’s gas rates contain a GSC, wherebyincreases or decreases in the cost of gas supply are reflected in LG&E’srates, subject to approval by the Kentucky Commission.  The GSC procedure prescribed by order of theKentucky Commission provides for quarterly rate adjustments to reflect theexpected cost of gas supply in that quarter. In addition, the GSC contains a mechanism whereby any over- orunder-recoveries of gas supply cost from prior quarters will be refunded to orrecovered from customers through the adjustment factor determined forsubsequent 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 on October 1, 2002.

 

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.

 

Construction Program and Financing

 

LG&E’s construction program is designed toensure that there will be adequate capacity and reliability to meet theelectric and gas needs of its service area. These needs are continually being reassessed and appropriate revisionsare made, when necessary, 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 rates, economic conditions, construction costs, and new environmental orother governmental laws and regulations.

 

During the five years ended December 31, 2002,gross property additions amounted to approximately $950 million. Internallygenerated funds and external financings for the five-year period were utilizedto provide for these gross additions. The gross additions during this period amounted to approximately 26% oftotal utility plant at 

 

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December 31, 2002, and consisted of $798 millionfor electric properties and $152 million for gas properties.  Gross retirements during the same periodwere $106 million, consisting of $74 million for electric properties and $32million for gas properties.

 

Coal Supply

 

Coal-fired generating units provided over 97% ofLG&E’s net kilowatt-hour generation for 2002.  The remaining net generation was provided by a natural gas andoil fueled combustion turbine peaking units and a hydroelectric plant.  Coal will be the predominant fuel used byLG&E in the foreseeable future, with natural gas and oil being used forpeaking 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 has entered into coal supplyagreements with various suppliers for coal deliveries for 2003 and beyond.  LG&E normally augments its coal supplyagreements with spot market purchases. LG&E has a coal inventory policywhich it believes provides adequate protection under most contingencies.  LG&E had a coal inventory ofapproximately 1.5 million tons, or a****74-day supply, on hand at December 31,2002.

 

LG&E expects to continue purchasing most ofits coal, with sulfur content in the 2%-4.5% range, from western Kentucky,southwest Indiana, and West Virginia for the foreseeable future.  This supply is relatively low priced coal,and in combination with its sulfur dioxide removal systems is expected toenable LG&E to continue to provide electric service in compliance withexisting environmental laws and regulations.

 

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

 

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

 
|                               |   | **2002** |   | **2001** |   | **2000** |   |
|------------------------------------|--------|----------|--------|----------|--------|----------|--------|
| Per ton                            |   | $        | 25.30  |     | $      | 21.27    |   | $ | 20.96 |   |
| Per Mmbtu                          |   | $        | 1.11   |     | $      | .93      |   | $ | .92 |   |
| Spot purchases as % of all sources |   | 2        | %      | 3        | %      | 1        | %      |

 

The delivered cost of coal is expected to remain relatively flat during2003.  Slight increases in the cost ofcoal in multi-year contracts signed for 2002 are expected to be offset by lowerprices negotiated in contracts signed for 2003.

 

Gas Supply

 

LG&E purchases natural gas supplies frommultiple sources under contracts for varying periods of time, whiletransportation services are purchased from Texas Gas and Tennessee Gas.

 

On April 28, 2000, TexasGas filed with FERC in Docket RP00-260 for an increase in its base rateseffective June 1, 2000.  This filing ispart of a rate case Texas Gas was required to file pursuant to the settlementin its last rate case.  On May 31, 2000, FERC issued an Ordersuspending the effectiveness of Texas Gas’s proposed rates, subject to refund,until November 1, 2000, and establishing a hearing and settlement procedures.  As the result of reaching variousFERC-approved settlements, Texas Gas’s higher motion rates were not billedafter July 31, 2002, and its lower prospective rates went into effect on August1, 2002.  Refunds covering the period from November 1, 2000, through July31, 2002, were received on September 17, 2002, and are currently being 

 

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refunded to customersthrough the GSC.  LG&E participatesin rate and other proceedings affecting its regulated interstate pipelineservices, as appropriate.

 

LG&E transports on the Texas Gas system under NNS and FT rateschedules.  During the winter months,LG&E has 184,900 Mmbtu/day in NNS service and 18,000 Mmbtu/day (increasingto 36,000 Mmbtu/day effective November 1, 2003) in FT service.  LG&E’s summer NNS levels are 60,000Mmbtu/day and its summer FT levels are 54,000 Mmbtu/day.  Each of these NNS and FT agreements withTexas Gas are subject to termination by LG&E in equal portions during 2005,2006, and 2008.  LG&E alsotransports on the Tennessee system under Tennessee’s FT-A rate schedule.  LG&E’s contract levels with Tennesseeare 51,000 Mmbtu/day throughout the year. The FT-A agreement with Tennessee, which was subject to termination byLG&E during 2002, has been successfully renegotiated for a minimumadditional term of five years at a lower price.

 

LG&E also has a portfolio of supply arrangements with varioussuppliers in order to meet its firm sales obligations.  These gas supply arrangements includepricing provisions that are market-responsive. These firm gas supplies, in tandem with pipeline transportationservices, provide the reliability and flexibility necessary to serve LG&E’scustomers.

 

LG&E owns andoperates five underground gas storage fields with a current working gascapacity of about 15.1 million Mcf.  Gasis purchased and injected into storage during the summer season and is thenwithdrawn to supplement pipeline supplies to meet the gas-system loadrequirements during the winter heating season. See Gas Operations under Item 1.

 

The estimated maximumdeliverability from storage during the early part of the heating season is typicallyabout 373,000 Mcf/day.  Deliverabilitydecreases during the latter portion of the heating season as the storageinventory is reduced by seasonal withdrawals.

 

The average cost per Mcf of natural gas purchased by LG&E was $4.19in 2002, $5.27 in 2001 and $5.08 in 2000. Although natural gas prices in the unregulated wholesale marketincreased significantly throughout 2000 and early 2001, these prices decreaseddramatically in early 2002 and then began to increase again.  These increases in natural gas prices,caused in part by decreased natural gas production, decreased liquidity in themarketplace, increases in the price of oil, and increased reliance on naturalgas as a fuel for electric generation were mitigated in part by higher nationalstorage inventory levels, and decreased demand associated with a less robusteconomy.

 

Environmental Matters

 

Protection of the environment is a major priorityfor LG&E.  Federal, state, and localregulatory agencies have issued LG&E permits for various activities subjectto air quality, water quality, and waste management laws and regulations.  For the five-year period ending with 2002, expenditures for pollution control facilitiesrepresented $253.8 million or 27% of total construction expenditures.  LG&E estimates that constructionexpenditures for the installation of NOx control equipment from 2003 through2004 will be approximately $32 million. For a discussion of environmental matters, see Rates and Regulation forLG&E under Item 7 and Note 11 of LG&E’s Notes to Financial Statementsunder Item 8.

 

Competition

 

In the last several years, LG&E has takenmany steps to prepare for the expected increase in competition in its industry,including a reduction in the number of employees; aggressive cost cutting;write-offs of previously 

 

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deferred expenses; an increase in focus oncommercial, industrial and residential customers; an increase in employeeinvolvement and training; a major realignment and formation of new businessunits, and continuous modifications of its organizational structure.  LG&E will continue to take additionalsteps to better position itself for competition in the future.

 

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 477,000 customersin over 600 communities and adjacent suburban and rural areas in 77 counties incentral, southeastern and western 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 160 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, KUR.  KU R is a special purpose entityformed in September 2000 to enter into accounts receivable securitizationtransactions with KU.  KU R beganoperations in 2001.  KU is consideringunwinding its accounts receivable securitization arrangements involving KU Rduring 2003.

 

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ElectricOperations

 

The sources of KU’s electric operating revenues and the volumes ofsales for the three years ended December 31, 2002, were as follows:

 
|                                      |   | **2002** |    | **2001** |   | **2000** |   |
|-------------------------------------------|--------|----------|---------|----------|--------|----------|--------|
|                                      |   |     |    |     |   |     |   |
| ELECTRIC  OPERATING REVENUES              |   |     |    |     |   |     |   |
| (Thousands of $):                         |   |     |    |     |   |     |   |
| Residential                               |   | $        | 275,869 |     | $      | 244,004  |   | $ | 241,783 |   |
| Commercial                                |   | 179,157  |    | 165,389  |   | 161,291  |   |
| Industrial                                |   | 163,206  |    | 146,968  |   | 153,017  |   |
| Mine power                                |   | 29,453   |    | 28,196   |   | 27,089   |   |
| Public  authorities                       |   | 62,649   |    | 58,770   |   | 57,979   |   |
| Total retail                              |   | 710,334  |    | 643,327  |   | 641,159  |   |
| Wholesale sales                           |   | 143,807  |    | 203,181  |   | 198,073  |   |
| Provision for  rate collections (refunds) |   | 13,027   |    | (954     | )      | —   |   |
| Miscellaneous                             |   | 21,051   |    | 13,918   |   | 12,709   |   |
| Total                                     |   | $        | 888,219 |     | $      | 859,472  |   | $ | 851,941 |   |
|                                      |   |     |    |     |   |     |   |
| ELECTRIC SALES (Thousands of Mwh):        |   |     |    |     |   |     |   |
| Residential                               |   | 6,198    |    | 5,678    |   | 5,714    |   |
| Commercial                                |   | 4,161    |    | 3,990    |   | 3,954    |   |
| Industrial                                |   | 4,975    |    | 4,716    |   | 5,044    |   |
| Mine power                                |   | 766      |    | 771      |   | 767      |   |
| Public  authorities                       |   | 1,533    |    | 1,481    |   | 1,495    |   |
| Total retail                              |   | 17,633   |    | 16,636   |   | 16,974   |   |
| Wholesale sales                           |   | 5,780    |    | 7,713    |   | 7,573    |   |
| Total                                     |   | 23,413   |    | 24,349   |   | 24,547   |   |

 

KU’s weighted-average system-wide emission rate for sulfur dioxide in2002 was approximately****1.24****lbs./Mmbtu****of heat input, with everygenerating unit below its emission limit established by the Kentucky Divisionfor Air Quality.

 

KU set a record local peak load of 3,899Mw on Monday, August 5, 2002, when the peak daily temperaturewas 100 degrees 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, 2002, KU owned steam andcombustion turbine generating facilities with a net summer capability of 4,111Mw and a hydroelectric facility with a summer capability of 24 Mw.  See Item 2, Properties.  KU obtains power from other utilities underbulk power purchase and interchange contracts. At December 31, 2002, KU’ssystem net summer capability, including purchases from others and excluding thehydroelectric facility, was 4,630 Mw.

 

Under a contract expiring in 2020 with OMU, KU has agreed to purchasefrom OMU the surplus output of the 150-Mw and 250-Mw generating units at OMU’sElmer Smith station.  Purchases underthe contract are made under a contractual formula which has resulted in costswhich were and are expected to be comparable to the cost of other powerpurchased or generated by KU.  Suchpower equated to approximately 8% ofKU’s net 

 

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generation system output during 2002. See Note 11 of KU’s Notesto 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 systemoutput in 2002.  See Note 11 of KU’s Notes to FinancialStatements under Item 8.

 

KU and 11 other electric utilities are participating owners of OVEClocated in Piketon, Ohio. OVEC owns and operates two power plants that burncoal to generate electricity, Kyger Creek Station in Ohio and Clifty CreekStation in Indiana. KU’s share is 2.5%, approximately 55 Mws of generationcapacity.  KU also has agreements with anumber of entities throughout the United States for the purchase and/or sale ofcapacity and energy and for the utilization of their bulk transmission systems.

 

On February 1, 2002, KU (along with LG&E) turned over operationalcontrol of its high voltage transmission facilities (100kV and above) toMISO.  KU (along with LG&E) is afounding member of MISO.  Such membershipwas obtained in 1998 in response to and consistent with federal policyinitiatives.  MISO operates a singleOATT over the facilities under its control. Currently MISO controls over 100,000 miles of transmission over 1.1million square miles located in the northern Midwest between Manitoba, Canadaand Kentucky.  On September 18, 2002,FERC granted a 12.88% ROE on transmission facilities for LG&E, KU and therest of the MISO owners.  This ROEincludes a 50 basis point increase because of operational independence.

 

MISO plans to implement a Congestion Management System in December2003, in compliance with FERC Order 2000. This system will be similar to the Locational Marginal Pricing (LMP)system currently used by the PJM RTO and contemplated in FERC’s SMD NOPRcurrently being discussed.  MISO filedwith FERC a mechanism for recovery of costs for the Congestion ManagementSystem, designated Schedule 16 and Schedule 17.  MISO transmission owners, including LG&E and KU, and othershave objected to the allocation of costs between market participants and retailnative load.  This case is currently ina hearing at FERC.

 

In October 2001, the FERC issued an order requiring that the bundledretail load and grandfathered wholesale load of each member transmission owner(including KU) be included in the current calculation of MISO’s “cost-adder,” acharge designed to recover MISO’s costs of operation, including start-upcapital (debt) costs.  KU, along withseveral other transmission owners, opposed the FERC’s ruling in this regard,which opposition the FERC rejected in an order on rehearing issued in 2002.  Later that year, MISO’s transmission owners,including KU, appealed the FERC’s decision to the United States Court ofAppeals for the District of Columbia Circuit. In response, by petition filed November 25, 2002, FERC requested thatthe Court issue a partial remand of its challenged orders to allow the FERC torevisit certain issues raised therein, and further requested that the case beheld in abeyance pending the agency’s resolution of such issues.  The Court granted the FERC’s petition byorder dated December 6, 2002.  OnFebruary 24, 2003, FERC issued an order reaffirming its position concerning thecalculation of the “cost-adder”.

 

As a separate matter, MISO, its transmission owners and otherinterested industry segments reached a settlement in mid-2002 regarding thelevel**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).  On February 24, 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 transmission owners toimmediately treat unrecoverable Schedule 10 charges as regulatory assets.  FERC will consider allowing 

 

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regulatory asset treatment of unrecoverable Schedule 10 charges on acase-by-case basis.

 

Rates andRegulation

 

Following the purchase ofPowergen by E.ON, E.ON became a registered holding company under PUHCA.  As a result, E.ON, its utility subsidiaries,including KU, and certain of its non-utility subsidiaries are subject toextensive regulation by the SEC under PUHCA with respect to issuances and salesof securities, acquisitions and sales of certain utility properties, andintra-system sales of certain goods and services.  In addition, PUHCA generally limits the ability of registeredholding companies to acquire additional public utility systems and to acquireand retain businesses unrelated to the utility operations of the holdingcompany.  KU believes that it hasadequate authority (including financing authority) under existing SEC ordersand regulations to conduct its business. KU will seek additional authorization when necessary.

 

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.

 

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 at December 31,2002, KU is subject to the jurisdiction of the TRA. FERC has classified KU as a“public utility” as defined in the FPA. FERC has jurisdiction under the FPA over certain of the electric utilityfacilities and operations, wholesale sale of power and related transactions andaccounting practices of KU, and in certain other respects as provided in theFPA.

 

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.

 

KU’s Kentucky retail electric rates contain aFAC, whereby increases and decreases in the cost of fuel for electricgeneration are reflected in the rates charged to retail electriccustomers.  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.  The Kentucky Commissionalso requires that electric utilities, including KU, file certain documentsrelating to fuel procurement and the purchase of power and energy from otherutilities.  The FAC mechanism forVirginia customers uses an average fuel cost factor based primarily onprojected fuel costs.  The fuel costfactor may be adjusted annually for over or under collections of fuel costsfrom 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.  KU made its second ESM filingon March 1, 2002 for the calendar year 2001 reporting period.  KU is in the process of refunding $1 millionto customers for the 2001 reporting period. KU estimated that the rate of returnwill fall below the lower limit for the year ended December 31, 2002.  The 2002 financial statements include anaccrual to reflect the earnings, subject to Kentucky Commission approval,deficiency of $13.5 million to be recovered from customers commencing inApril 2003.

 

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On November 27, 2002, KU filed a revised ESM tariff which proposedcontinuance of the existing ESM through 2005. The Kentucky Commission issued an Order suspending the ESM tariff oneday making the effective date January 2, 2003. In addition, the Kentucky Commission is conducting a management audit toreview the ESM plan and reassess its reasonableness in 2003.  KU and interested parties will have theopportunity to provide recommendations for modification and continuance of theESM or other forms of alternative or incentive regulation.

 

KU’s Kentucky retail rates contain an ECRsurcharge which recovers certain costs incurred by KU that are required tocomply with the Clean Air Act and other environmental regulations.  See Note 3 of KU’s Notes to Financial Statementsunder Item 8.

 

Integrated resource planning regulations in Kentucky require KU and theother major utilities to make triennial filings with the Kentucky Commission ofvarious historical and forecasted information relating to load, capacitymargins and demand-side management techniques. KU filed its most recent integrated resource plan on October 1, 2002.

 

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.

 

The state of Virginia passed the Virginia Electric UtilityRestructuring Act in 1999.  This actgives Virginia customers a choice for energy services.  The change will be phased in graduallybetween January 2002 and January 2004. KU filed unbundled rates that became effective January 1, 2002.  Rates are capped at current levels throughJune 2007.  The Virginia Commission willcontinue to require each Virginia utility to make annual filings of either abase rate change or an Annual Informational Filing consisting of a set ofstandard financial schedules.  TheVirginia Staff will issue a Staff Report regarding the individual utility’sfinancial performance during the historic 12-month period.  The Staff Report can lead to an adjustmentin rates, but through June 2007 will be limited to decreases.  KU wasgranted a waiver from the Virginia Commission on October 29, 2002, exempting KUfrom retail choice through December 31, 2004. KU is also seeking a permanent legislative exemption from the VirginiaElectric Utility Restructuring Act.  Theoutcome of this legislative initiative is not expected be known until mid-2003.

 

Construction Program and Financing

 

KU’s construction program is designed to ensurethat there will be adequate capacity and reliability to meet the electric needsof its service area.  These needs arecontinually being reassessed and appropriate revisions are made, whennecessary, in construction schedules. KU’s estimates of its construction expenditures can vary substantiallydue to numerous items beyond KU’s control, such as changes in rates, economicconditions, construction costs, and new environmental or other governmentallaws and regulations.

 

During the five years ended December 31, 2002, gross property additionsamounted to approximately $754 million. Internally generated funds and external financings for the five-yearperiod were utilized to provide for these gross additions.  The gross additions during this periodamounted to approximately 23% oftotal utility plant at December 31, 2002. Gross retirements during the same period were $82 million.

 

Coal Supply

 

Coal-fired generating units provided over 97% of KU’s net kilowatt-hourgeneration for 2002.  The remaining 

 

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net generation for 2002 was provided by natural gas and oil fueledcombustion turbine peaking units and hydroelectric plants.  Coal will be the predominant fuel used by KUin the foreseeable future, with natural gas and oil being used for capacity andflame stabilization in coal-fired boilers or in emergencies.  KU has no nuclear generating units and has noplans to build any in the foreseeable future.

 

KU maintains its fuel inventory at levels estimated to be necessary toavoid operational disruptions at its coal-fired generating units.  Reliability of coal deliveries can beaffected from time to time by a number of factors, including fluctuations indemand, coal mine 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 1.4 milliontons, or a 67-day supply, on hand at December 31, 2002.

 

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, southwest Indiana, Wyoming and Pennsylvania for the foreseeablefuture.

 

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:

 
|                                |   | **2002** |   | **2001** |   | **2000** |   |
|-------------------------------------|--------|----------|--------|----------|--------|----------|--------|
|                                |   |     |   |     |   |     |   |
| Per ton                             |   | $        | 31.44  |     | $      | 27.84    |   | $ | 25.63 |   |
| Per Mmbtu                           |   | $        | 1.35   |     | $      | 1.20     |   | $ | 1.07 |   |
| Spot purchases  as % of all sources |   | 18       | %      | 44       | %      | 51       | %      |

 

KU’s historical average cost of coal purchased is higher 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 is expected to increase during 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 2002,expenditures for pollution control facilities represented $63.5 million or 11% of total construction expenditures. KU estimates thatconstruction expenditures for the installation of NOx control equipment from2003 through 2004 will be approximately $178million.  For a discussion ofenvironmental matters, see Rates and Regulation for KU under Item 7 and Note 11of KU’s Notes to Financial Statements under Item 8.

 

Competition

 

In the last several years, KU has taken manysteps to prepare for the expected increase in competition in its 

 

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industry, including a reduction in the number ofemployees; aggressive cost cutting; an increase in focus on commercial,industrial and residential customers; an increase in employee involvement andtraining; a major realignment and formation of new business units; andcontinuous modifications of its organizational structure.  KU will continue to take additional steps tobetter position itself for competition in the future.

 

EMPLOYEES AND LABOR RELATIONS

 

LG&E had 891 full-timeregular employees and KU had 946 full-timeregular employees at December 31, 2002. Of the LG&E total, 628operating, 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.  Of the KUtotal, 162 operating, maintenance, and construction employees were representedby IBEW Local 2100 and USWA Local 9447-01. In August 2001, KU and employees represented by IBEW Local 2100entered into a two-year collective bargaining agreement.  KU and employees represented by USWA Local9447-01 entered into a three-year collective bargaining agreement effectiveAugust 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 underthe Holding Company Act.  On January 1,2001, approximately 1,000 employees, mainly from LG&E Energy, LG&E andKU, were moved to LG&E Services.

 

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

 

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Executive Officersof LG&E and KU at December 31, 2002:

 
| **Name**              |   | **Age** |   | **Position**                                                        |   | **Effective Date of  Election to Present  Position** |
|-----------------------|--------|---------|--------|---------------------------------------------------------------------|--------|------------------------------------------------------|
|                  |   |    |   |                                                                |   |                                                 |
| Victor A. Staffieri   |   | 47      |   | Chairman of the Board,  President and Chief  Executive Officer      |   | May 1, 2001                                          |
|                  |   |    |   |                                                                |   |                                                 |
| Richard Aitken-Davies |   | 53      |   | Chief Financial Officer                                             |   | January 31, 2001                                     |
|                  |   |    |   |                                                                |   |                                                 |
| John R. McCall        |   | 59      |   | Executive Vice President,  General Counsel and  Corporate Secretary |   | July 1, 1994                                         |
|                  |   |    |   |                                                                |   |                                                 |
| S. Bradford Rives     |   | 44      |   | Senior Vice President -  Finance and Controller                     |   | December 11, 2000                                    |
|                  |   |    |   |                                                                |   |                                                 |
| Paul W. Thompson      |   | 45      |   | Senior Vice President -  Energy Services                            |   | June 7, 2000                                         |
|                  |   |    |   |                                                                |   |                                                 |
| Chris Hermann         |   | 55      |   | Senior Vice President -  Distribution Operations                    |   | December 11, 2000                                    |
|                  |   |    |   |                                                                |   |                                                 |
| Wendy C. Welsh        |   | 48      |   | Senior Vice President -  Information Technology                     |   | December 11, 2000                                    |
|                  |   |    |   |                                                                |   |                                                 |
| Martyn Gallus         |   | 38      |   | Senior Vice President -  Energy Marketing                           |   | December 11, 2000                                    |
|                  |   |    |   |                                                                |   |                                                 |
| A. Roger Smith        |   | 49      |   | Senior Vice President  Project Engineering                          |   | December 11, 2000                                    |
|                  |   |    |   |                                                                |   |                                                 |
| David A. Vogel        |   | 36      |   | Vice President – Retail  Services                              |   | December 11, 2000                                    |
|                  |   |    |   |                                                                |   |                                                 |
| Daniel K. Arbough     |   | 41      |   | Treasurer                                                           |   | December 11, 2000                                    |
|                  |   |    |   |                                                                |   |                                                 |
| Bruce D. Hamilton     |   | 47      |   | Vice President  Independent Power Operations                        |   | December 11, 2000                                    |
|                  |   |    |   |                                                                |   |                                                 |
| Robert E. Henriques   |   | 61      |   | Vice President  Regulated Generation                                |   | September 30, 2001                                   |
|                  |   |    |   |                                                                |   |                                                 |
| Michael S. Beer       |   | 44      |   | Vice President-Rates  and Regulatory                                |   | February 1, 2001                                     |
|                  |   |    |   |                                                                |   |                                                 |
| George R. Siemens     |   | 53      |   | Vice President-External  Affairs                                    |   | January 11, 2001                                     |
|                  |   |    |   |                                                                |   |                                                 |
| Paula H. Pottinger    |   | 45      |   | Vice President -  Human Resources                                   |   | June 1, 2002                                         |
|                  |   |    |   |                                                                |   |                                                 |
| D. Ralph Bowling      |   | 45      |   | Vice President -  Power Operations WKE                              |   | August 1, 2002                                       |
|                  |   |    |   |                                                                |   |                                                 |
| R. W. Chip Keeling    |   | 46      |   | Vice President -  Communications                                    |   | March 18, 2002                                       |

 

 

21

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The present term of office of each of the above executive officersextends to the meeting of the Board of Directors following the 2003 AnnualMeeting of Shareholders.

 

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, 2002.  Each of the aboveofficers serves in the same capacity for LG&E and KU.

 

Before he was elected to his current positions, Mr. Staffieri wasPresident, Distribution Services Division of LG&E Energy Corp. fromDecember 1995 to May 1997; Chief Financial Officer of LG&E Energy Corp. andLG&E from May 1997 to February 1999, (including Chief Financial Officer ofKU from May 1998 to February 1999); President and  Chief Operating Officer of LG&E Energy Corp. from March 1999to April 2001 (including President of LG&E and KU from June 2000 to April2001); Chairman, President and CEO of LG&E Energy Corp., LG&E and KUfrom May 2001 to present.

 

Before he was elected to his current positions,Mr. Aitken-Davies was Group Performance Director at Powergen from April 1998 toMarch 2000; Director - LG&E Transition Team at Powergen from March 2000 toJanuary 2001.

 

Mr. McCall has been Executive Vice President, General Counsel andCorporate Secretary of LG&E Energy Corp. 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 Vice President– Finance and Controller of LG&E Energy Corp. from March 1996 to February1999; and Senior Vice President – Finance and Business Development fromFebruary 1999 to December 2000.

 

Before he was elected to his current positions, Mr. Thompson was VicePresident – Business Development for LG&E Energy Corp. 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, Retail ElectricBusiness for LG&E from December 1998 to August 1999; and Senior VicePresident – Energy Services for LG&E Energy Corp. from August 1999 to June2000.

 

Before he was elected to his current positions, Mr. Hermann was Vice Presidentand General Manager, Wholesale Electric Business of LG&E from January 1993to June 1997; Vice President, Business Integration of LG&E from June 1997to May 1998; Vice President, Power Generation and Engineering Services, ofLG&E from May 1998 to December 1999; and Vice President Supply Chain andOperating Services from December 1999 to December 2000.

 

Before she was elected to her current positions, Ms. Welsh was VicePresident - Information Services of LG&E from January 1994 to May 1997;Vice President, Administration of LG&E Energy Corp. from May 1997 toFebruary 1998; and Vice President-Information Technology from February 1998 toDecember 2000.

 

22

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Before he was elected to his current positions, Mr. Gallus wasDirector, Trading and Risk Management from January 1996 to September 1996;Director, Product Development from September 1996 to April 1997; VicePresident, Structured Products from April 1997 to May 1998; Senior VicePresident, Trading, from May 1998 to August 1998 for LG&E Energy MarketingInc.; and Vice President, Energy Marketing from August 1998 to December 2000for LG&E Energy Corp.

 

Before he was elected to his current positions,Mr. Smith was Head of Construction Projects - Powergen from January 1996 to May1999; Director of Projects - Powergen from May 1999 to December 1999; andDirector of Engineering Projects for Powergen International from January 2000to December 2000.

 

Before he was elected to his current positions, Mr. Vogel served inmanagement positions within the Distribution organization of LG&E and KUprior to December 2000.  In his positionprior to his current role he was responsible for statewide outage managementand restoration of distribution network.

 

Before he was elected to his current positions, Mr. Arbough wasManager, Corporate Finance of LG&E Energy Corp., and LG&E from August1996 to May 1998; and he has held the position of Director, Corporate Financeof LG&E Energy Corp., LG&E and KU from May 1998 to present.

 

Before he was elected to his current positions, Mr. Hamilton wasVenture Manager from May 1992 to December 1995; Senior Venture Manager fromDecember 1995 to September 1997, and Vice President, Asset Management fromSeptember 1997 to December 2000.

 

Before he was elected to his current positions, Mr. Henriques wasSenior Venture Manager for LG&E Power Inc. from May 1993 to September 1995,and Vice President-Plant Operations from September 1995 to September 2001.

 

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

 

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

 

Before she was elected to her current positions as Vice President-HumanResources, Ms. Pottinger was Manager, Human Resources Development from May 1994to 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 Corp. from July 1998 to December2001; and General Manager Black Fossil Operations for Powergen in the UnitedKingdom from January 2002 to August 2002.

 

Before he was elected to his current positions, Mr. Keeling was GeneralManager, Marketing Communications for General Electric Company from January1998 to January 1999.  He joinedLG&E Energy Corp. and held the title Manager, Media Relations from January 1999 to February 2000; andDirector, Corporate Communications for LG&E Energy from February 2000 toMarch 2002.

 

23

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ITEM 2.  Properties.

 

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

 
|                                                 |   | **Summer  Capability  Rating (Kw)** |   |
|------------------------------------------------------|--------|-------------------------------------|--------|
|                                                 |   |                                |   |
| Steam Stations:                                      |   |                                |   |
| Mill Creek -  Kosmosdale, KY                         |   |                                |   |
| Unit 1                                               |   | 308,000                             |   |
| Unit 2                                               |   | 306,000                             |   |
| Unit 3                                               |   | 391,000                             |   |
| Unit 4                                               |   | 480,000                             |   |
| Total Mill Creek                                     |   | 1,485,000                           |   |
|                                                 |   |                                |   |
| 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                                               |   | 386,000                             |   |
|                                                 |   |                                |   |
| 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)                     |   | 189,000                             |   |
| Trimble County –  Bedford, KY(d)                |   | 90,000                              |   |
| Total combustion  turbine generators                 |   | 448,000                             |   |
|                                                 |   |                                |   |
| Total capability  rating                             |   | 2,882,000                           |   |

 

----

| (a) | Amount shown represents LG&E’s 75% interest in  Trimble County 1.  See Notes 11 and 12 of LG&E’s Notes 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 Run CTs.  See Notes 11 and 12 of LG&E’s Notes 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 to Financial 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, under Item 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, 2002, LG&E’s electric transmission system included 21 substations with a total capacity of 

 

24

----

 

approximately 11,519,700Kvaand approximately 656 structure miles of lines.  The electric distribution system included 84 substations with a total capacity of approximately 3,448,730Kva, 3,761 structure miles of overhead lines and 379 miles of undergroundconduit.

 

LG&E’s gas transmission system includes 212 miles of transmissionmains, and the gas distribution system includes 4,066 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 Bonds constitutesa direct first mortgage lien upon much of the property owned by LG&E.

 

25

----

 

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:

 
|                                                 |   | **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 1                                               |   | 22,000                              |   |
| Unit 2                                               |   | 22,000                              |   |
| Unit 3                                               |   | 68,000                              |   |
| Unit 4                                               |   | 100,000                             |   |
| Total Green  River                                   |   | 212,000                             |   |
|                                                 |   |                                |   |
| E.W. Brown –  Burgin, KY                        |   |                                |   |
| Unit 1                                               |   | 104,000                             |   |
| Unit 2                                               |   | 168,000                             |   |
| Unit 3                                               |   | 429,000                             |   |
| Total E.W. Brown                                     |   | 701,000                             |   |
|                                                 |   |                                |   |
| Ghent – Ghent,  KY                              |   |                                |   |
| Unit 1                                               |   | 509,000                             |   |
| Unit 2                                               |   | 494,000                             |   |
| Unit 3                                               |   | 496,000                             |   |
| Unit 4                                               |   | 467,000                             |   |
| Total Ghent                                          |   | 1,966,000                           |   |
|                                                 |   |                                |   |
| Combustion  Turbine Generators (Peaking capability): |   |                                |   |
| E.W. Brown –  Burgin, KY (Units 5-11)(a)        |   | 773,000                             |   |
| Haefling –  Lexington, KY                       |   | 36,000                              |   |
| Paddy’s Run –  Louisville, KY(b)           |   | 74,000                              |   |
| Trimble  County-Bedford, KY(c)                       |   | 220,000                             |   |
| Total combustion  turbine generators                 |   | 1,103,000                           |   |
|                                                 |   |                                |   |
| Total capability  rating                             |   | 4,111,000                           |   |

 

----

| (a) | Amount shown represents KU’s 47% interest in Unit 5,  62% interest in Units 6 and 7 and 100% of four other units at E.W. Brown. See  Notes 11 and 12 of KU’s Notes to Financial Statements, under Item 8 for  further discussion on ownership.            |
|-----|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| (b) | Amount shown represents KU’s 47% interest in Unit 13  at Paddy’s Run.  See Notes 11 and 12  of KU’s Notes to Financial Statements, under Item 8 for further discussion on  ownership.  LG&E operates this  unit on behalf of KU.       |
| (c) | Amount shown represents KU’s 71% interest in Units 5  and 6 at Trimble County.  See Notes 11  and 12 of KU’s Notes to Financial Statements, under Item 8 for further  discussion on ownership.  LG&E operates  these units on behalf of KU. |

 

KU also owns a 24 Mw hydroelectric generating station located in Burgin,Kentucky (Dix Dam), operated under a license issued by the FERC.

 

At December 31, 2002, KU’s electric transmission system included 112substations with a total capacity of approximately 14,855,396Kva and approximately 4,229 structuremiles of lines.  The electricdistribution system included 464 substations with a total capacity ofapproximately 5,046,335 Kva and 15,036 structure 

 

26

----

 

miles of lines.

 

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

 

Substantially all properties are subject to the lien of KU’s MortgageIndenture.

 

ITEM 3.  Legal Proceedings.

 

Rates and Regulatory Matters

 

For a discussion of current rate and regulatory matters, including (a)environmental surcharge and cost recovery proceedings, (b) fuel adjustment andgas supply clause proceedings,  (c)earnings sharing mechanism extension proceedings, (d) merger surcreditproceedings and (e) other rate or regulatory matters affecting LG&E and KU,see Rates and Regulation under Item 7 and Note 3 of LG&E’s Notes toFinancial Statements and Note 3 of KU’s Notes to Financial Statements underItem 8.

 

Environmental

 

For a discussion of environmental matters including (a) currentlyproposed reductions in NOx emission limits, (b) items regarding LG&E’s MillCreek generating plant, KU’s E.W. Brown plant, KU-related Tindall property andLG&E’s and KU’s manufactured gas plant sites and (c) other environmental itemsaffecting LG&E and KU, see Environmental Matters under Item 7 and Note 11of LG&E’s Notes to Financial Statements and Note 11 of KU’s Notes toFinancial 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 plaintiff’s claims.  Discovery hascommenced in the matter.  The court hasordered mediation and certain plaintiffs have settled for non-material amountsas a result of that process.  Inaddition, certain plaintiffs have sought administrative review before the U.S.Equal Employment Opportunity Commission which has, to date, declined to proceedto litigation on any claims reviewed. Amended pleadings have also reduced the size of the plaintiff anddefendant groups and eliminated certain prior demands.  The amended complaints included a reducedclaimed damage amount of $100 million as well as requests for injunctiverelief.  LG&E intends todefend itself vigorously in the action and managementdoes not anticipate that the outcome will have a material impact on LG&E’soperations or financial condition.

 

Combustion Turbine Litigation

 

In September 2002,LG&E and KU, or their affiliates, filed further amended complaints inlitigation in the U.S. District Court for the Eastern District of Kentuckyagainst Alstom Power, Inc. (formerly ABB Power Generation, Inc.) (“Alstom”)regarding two combustion turbines supplied by Alstom in 1999.  These units are installed at KU’s E.W. Browngenerating plant and are jointly owned by LG&E and KU.  The original purchase price for the turbineswas approximately $91.8 million.  Thesuit presents warranty, negligence, misrepresentation, fraud and other claimsrelating to numerous operational defects or deficiencies in connectiontherewith.  LG&E and KU haverequested rescission of the contract and recovery of all expenditures relatingto the 

 

27

----

 

turbines.  As an alternative to rescission, LG&Eand KU have requested relief for amounts incurred or expended to date inconnection with operational repairs, cover damages or liquidated damages andother costs, with possible further damages and interest to be proven at trial.The matter is currently in discovery with a trial presently scheduled for thethird quarter of 2003.

 

Preferred Stock Delisting

 

On April 16, 2002, the LG&E 5% CumulativePreferred class of stock was delisted from the NASDAQ Small CapitalizationMarket.  On June 3, 2002, the KU 4.75%Cumulative Preferred class of stock was delisted from the Philadelphia StockExchange.  Delisting will enable theCompanies to realize certain administrative and corporate governanceefficiencies.

 

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.

 

28

----

 

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

 

a)                                      LG&E’sand KU’s Annual Meetings of Shareholders were held on December 19, 2002.

 

b)                                     Notapplicable.

 

c)                                      Thematters voted upon and the results of the voting at the Annual Meetings are setforth below:

 

1.          LG&E

 
| i)     |   | The shareholders voted to elect LG&E’s nominees  for election to the Board of Directors, as follows:                                                                                                                                                                               |
|--------|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                                                                                                                        |
|   |   | Michael Söhlke - 21,294,223 common shares and 114,107  preferred shares cast in favor of election and 1,979 preferred shares  withheld.                                                                                                                                                |
|   |   |                                                                                                                                                                                                                                                                                        |
|   |   | Victor A. Staffieri - 21,294,223 common shares and 113,207  preferred shares cast in favor of election and 2,879 preferred shares  withheld.                                                                                                                                                |
|   |   |                                                                                                                                                                                                                                                                                        |
|   |   | Edmund A. Wallis  - 21,294,223 common shares and 114,246 preferred shares cast in favor of  election and 1,840 preferred shares  withheld.                                                                                                                                                  |
|   |   |                                                                                                                                                                                                                                                                                        |
|   |   | No holders of common or preferred shares abstained  from voting on this matter.                                                                                                                                                                                                             |
|   |   |                                                                                                                                                                                                                                                                                        |
| ii)    |   | The shareholders voted 21,294,223 common shares and  113,801 preferred shares in favor of and 331 preferred shares against the  approval of PricewaterhouseCoopers LLP as independent accountants for  2002.  Holders of 1,954 preferred  shares abstained from voting on this matter. |

 

2.   KU

 
| i)     |   | The sole shareholder voted to elect KU’s nominees  for election to the Board of Directors, as follows:                                                                      |
|--------|--------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                             |
|   |   | 37,817,878 common shares cast in favor of election  and no shares withheld for each of Michael Söhlke, Victor A. Staffieri and   Edmund A. Wallis,  respectively. |
|   |   |                                                                                                                                                                             |
| ii)    |   | The sole shareholder voted 37,817,878 common shares  in favor of and no shares withheld for approval of PricewaterhouseCoopers LLP  as independent accountants for 2002.         |
|   |   |                                                                                                                                                                             |
|   |   | No holders of common shares abstained from voting on  these matters.                                                                                                             |
|   |   |                                                                                                                                                                             |

d)                                     Notapplicable.

PART II.

 

ITEM 5.  Marketfor the Registrant’s Common Equity and Related Stockholder Matters.

 

LG&E:

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

 

29

----

 

for LG&E’s common stock.

 

The following table sets forth LG&E’s cash distributions on commonstock paid to LG&E Energy (in thousands of $):

 
|           |   | **2002** |   | **2001** |   |
|----------------|--------|----------|--------|----------|--------|
|           |   |     |   |     |   |
| First quarter  |   | $        | 0      |     | $      | 0 |   |
| Second quarter |   | 23,000   |   | 0        |   |
| Third quarter  |   | 23,000   |   | 0        |   |
| Fourth quarter |   | 23,000   |   | 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.

 

The following table sets forth KU’s cash distributions on common stockpaid to LG&E Energy (in thousands of $):

 
|           |   | **2002** |   | **2001** |   |
|----------------|--------|----------|--------|----------|--------|
|           |   |     |   |     |   |
| First quarter  |   | $        | 0      |     | $      | 0 |   |
| Second quarter |   | 0        |   | 0        |   |
| Third quarter  |   | 0        |   | 0        |   |
| Fourth quarter |   | 0        |   | 30,500   |   |
|                |        |          |        |          |        |  |  |

 

30

----

 

ITEM 6. Selected Financial Data.

 

The Consolidated FinancialStatements for 1998 through 2000 for LG&E and KU were audited by ArthurAndersen LLP (Andersen) who has ceased operations.  A copy of the report previously issued by Andersen on ourfinancial statements for the year ended December 31, 2000, is included elsewherein this report.  Such report has notbeen reissued by Andersen.

 
|                                                           |   | **Years  Ended December 31  (Thousands of $)** |      |
|----------------------------------------------------------------|--------|------------------------------------------------|-----------|
|                                                           |   | **2002**                                       |      | **2001** |   | **2000** |   | **1999** |   | **1998** |   |
| **LG&E:**                                                  |   |                                           |      |   |   |   |   |   |   |   |   |
| Operating  revenues:                                           |   |                                           |      |   |   |   |   |   |   |   |   |
| Revenues                                                       |   | $                                              | 1,013,917 |   | $ | 997,420 |   | $ | 985,947 |   | $ | 969,984 |   | $ | 854,556 |   |
| Provision for  rate collections (refunds)                      |   | 12,267                                         |      | (720 | ) | (2,500 | ) | (1,735 | ) | (4,500 | ) |
| Total operating  revenues                                      |   | 1,026,184                                      |      | 996,700 |   | 983,447 |   | 968,249 |   | 850,056 |   |
|                                                           |   |                                           |      |   |   |   |   |   |   |   |   |
| Net operating income                                           |   | 117,914                                        |      | 141,773 |   | 148,870 |   | 140,091 |   | 135,523 |   |
|                                                           |   |                                           |      |   |   |   |   |   |   |   |   |
| Net income                                                     |   | 88,929                                         |      | 106,781 |   | 110,573 |   | 106,270 |   | 78,120 |   |
|                                                           |   |                                           |      |   |   |   |   |   |   |   |   |
| Net income  available for common stock                         |   | 84,683                                         |      | 102,042 |   | 105,363 |   | 101,769 |   | 73,552 |   |
|                                                           |   |                                           |      |   |   |   |   |   |   |   |   |
| Total assets                                                   |   | 2,561,078                                      |      | 2,448,354 |   | 2,226,084 |   | 2,171,452 |   | 2,104,637 |   |
|                                                           |   |                                           |      |   |   |   |   |   |   |   |   |
| Long-term  obligations (including amounts due within one year) |   | $                                              | 616,904   |   | $ | 616,904 |   | $ | 606,800 |   | $ | 626,800 |   | $ | 626,800 |   |

 

LG&E’s Management’sDiscussion and Analysis of Financial Condition and Results of Operation andLG&E’s Notes to Financial Statements should be read in conjunction with theabove information.

 

31

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|                                                          |   | **Years Ended  December 31  (Thousands of $)** |    |
|---------------------------------------------------------------|--------|------------------------------------------------|---------|
|                                                          |   | **2002**                                       |    | **2001** |   | **2000** |   | **1999** |   | **1998** |   |
| **KU:**                                                       |   |                                           |    |   |   |   |   |   |   |   |   |
| Operating revenues:                                           |   |                                           |    |   |   |   |   |   |   |   |   |
| Revenues                                                      |   | $                                              | 875,192 |   | $ | 860,426 |   | $ | 851,941 |   | $ | 943,210 |   | $ | 831,614 |   |
| Provision for rate collections (refunds)                      |   | 13,027                                         |    | (954 | ) | — |   | (5,900 | ) | (21,500 | ) |
| Total operating revenues                                      |   | 888,219                                        |    | 859,472 |   | 851,941 |   | 937,310 |   | 810,114 |   |
|                                                          |   |                                           |    |   |   |   |   |   |   |   |   |
| Net operating income                                          |   | 108,643                                        |    | 121,370 |   | 128,136 |   | 136,016 |   | 125,388 |   |
|                                                          |   |                                           |    |   |   |   |   |   |   |   |   |
| Net income                                                    |   | 93,384                                         |    | 96,414 |   | 95,524 |   | 106,558 |   | 72,764 |   |
|                                                          |   |                                           |    |   |   |   |   |   |   |   |   |
| Net income available for common stock                         |   | 91,128                                         |    | 94,158 |   | 93,268 |   | 104,302 |   | 70,508 |   |
|                                                          |   |                                           |    |   |   |   |   |   |   |   |   |
| Total assets                                                  |   | 1,998,383                                      |    | 1,826,902 |   | 1,739,518 |   | 1,785,090 |   | 1,761,201 |   |
|                                                          |   |                                           |    |   |   |   |   |   |   |   |   |
| Long-term obligations (including amounts due within one year) |   | $                                              | 500,492 |   | $ | 488,506 |   | $ | 484,830 |   | $ | 546,330 |   | $ | 546,330 |   |

 

KU’s Management’s Discussionand Analysis of Financial Condition and Results of Operation and KU’s Notes toFinancial Statements should be read in conjunction with the above information.

 

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

 

LG&E:

 

GENERAL

 

The following discussion and analysis bymanagement focuses on those factors that had a material effect on LG&E’sfinancial results of operations and financial condition during 2002, 2001,and 2000 and should be read inconnection with the financial statements and notes thereto.

 

Some of the following discussion may containforward-looking statements that are subject to certain risks, uncertainties andassumptions.  Such forward-lookingstatements are intended to be identified in this document by the words“anticipate,” “expect,” “estimate,” “objective,” “possible,” “potential” andsimilar expressions.  Actual results maymaterially vary.  Factors that couldcause actual results to materially differ include; general economic conditions;business and competitive conditions in the energy industry; changes in federalor state legislation; unusual weather; actions by state or federal regulatoryagencies; actions by credit rating agencies; and other factors described fromtime to time in LG&E’s reports to the SEC, including Exhibit No. 99.01 tothis report on Form 10-K.

 

MERGERS and ACQUISITIONS

 

On December 11, 2000, LG&E Energy was acquired by Powergen forcash of approximately $3.2 billion or $24.85 per share and the assumption ofall of LG&E Energy’s debt.  As aresult of the acquisition, LG&E Energy became a wholly owned subsidiary ofPowergen and, as a result, LG&E became an indirect subsidiary ofPowergen.  LG&E has continued itsseparate identity and serves customers in Kentucky under its existing 

 

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name.  The preferred stock anddebt securities of LG&E were not affected by this transaction and LG&Econtinues to file SEC reports. Following the acquisition, Powergen became aregistered holding company under PUHCA, and LG&E, as a subsidiary of aregistered holding company, became subject to additional regulation underPUHCA.  See “Rates and Regulation” underItem 1.

 

On July 1, 2002, E.ON, a German company,completed its acquisition of Powergen plc (now Powergen Limited).  As aresult, LG&E and KU became indirect subsidiaries of E.ON.  E.ON had announced its pre-conditional cashoffer of £5.1 billion ($7.3 billion) for Powergen on April 9, 2001.  Following the acquisition, E.ON became aregistered holding company under PUHCA.

 

As contemplated 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.

 

RESULTS OF OPERATIONS

 

Net Income

 

LG&E’s net income in 2002 decreased $17.9million as compared to 2001.  Thedecrease resulted primarily from higher transmission operating expenses, anincrease in amortization of VDT regulatory asset, and increased propertyinsurance and pension expense, partially offset by an increase in electricsales to retail customers and lower interest expenses.

 

LG&E’s net income decreased $3.8 million for2001, as compared to 2000.  Thisdecrease is mainly due to higher pension related expenses and amortization ofVDT regulatory asset, partially offset by increased electric and gas netrevenues (operating revenues less fuel for electric generation, power purchasedand gas supply expenses) and decreased interest expenses.

 

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Revenues

 

A comparison of operating revenues for the years2002 and 2001, excluding the provisions recorded for rate collections (refunds),with the immediately preceding year reflects both increases and decreases,which have been segregated by the following principal causes (in thousands of$):

 
|                                  |   | **Increase  (Decrease) From Prior Period** |   |
|---------------------------------------|--------|--------------------------------------------|--------|
|                                  |   | **Electric  Revenues**                     |   | **Gas  Revenues** |   |
| **Cause**                             |   | **2002**                                   |   | **2001** |   | **2002** |   | **2001** |   |
|                                  |   |                                       |   |   |   |   |   |   |   |
| Retail sales:                         |   |                                       |   |   |   |   |   |   |   |
| Fuel and gas supply  adjustments      |   | $                                          | 19,449 |   | $ | (394 | ) | $ | (58,003 | ) | $ | 79,627 |   |
| LG&E/KU Merger surcredit          |   | (2,825                                     | )      | (2,456 | ) | — |   | — |   |
| Performance based rate                |   | —                                     |   | 1,962 |   | — |   | — |   |
| Environmental cost recovery surcharge |   | 9,694                                      |   | 1,246 |   | — |   | — |   |
| Demand side management                |   | 1,381                                      |   | — |   | 938 |   | — |   |
| Electric rate reduction               |   | —                                     |   | (3,671 | ) | — |   | — |   |
| VDT surcredit                         |   | (1,177                                     | )      | (1,014 | ) | (285 | ) | (68 | ) |
| Gas rate increase                     |   | —                                     |   | — |   | — |   | 15,265 |   |
| Weather normalization                 |   | —                                     |   | — |   | 2,234 |   | — |   |
| Variation in sales volumes and other  |   | 24,819                                     |   | 4,429 |   | 21,658 |   | (64,817 | ) |
| Total retail sales                    |   | 51,341                                     |   | 102 |   | (33,458 | ) | 30,007 |   |
| Wholesale sales                       |   | (16,404                                    | )      | (5,674 | ) | 10,683 |   | (11,642 | ) |
| Gas transportation-net                |   | —                                     |   | — |   | 189 |   | (880 | ) |
| Other                                 |   | 4,642                                      |   | (1,241 | ) | (496 | ) | 801 |   |
| Total                                 |   | $                                          | 39,579 |   | $ | (6,813 | ) | $ | (23,082 | ) | $ | 18,286 |   |

 

Electric revenues increased in 2002 primarily due to an increase inretail sales due to warmer summer weather, an increase in the recovery of fuelcosts passed through the FAC, partially offset by a decrease in wholesale salesdue to lower market prices as compared to 2001. Cooling degree days increased20% compared to 2001.  Electric revenuesdecreased in 2001 primarily due to a decrease in brokered activity in thewholesale electric sales market, an electric rate reduction ordered by theKentucky Commission and the effects of the LG&E/KU merger surcredit (SeeNote 2 of LG&E’s  Notes to FinancialStatements under Item 8) partially offset by an increase in electric retailsales. In January 2000, the Kentucky Commission ordered an electric ratereduction and the termination of LG&E’s proposed electric PBR mechanism.

 

Gas revenues in 2002 decreased due to a lower gas supply cost billed tocustomers through the gas supply clause offset partially by increased gasretail sales due to cooler winter weather and an increase in wholesale salesvolume.  Heating degree days increased17% as compared to 2001.  Gas revenuesin 2001 increased primarily as a result of higher gas supply costs billed tocustomers through the gas supply clause and the effects of a gas rate increaseordered by the Kentucky Commission in September 2000.  The gas revenue increase was partially offset by a decrease inretail and wholesale gas sales in 2001 due to warmer weather.  Heating degree days decreased 10.2% comparedto 2000.

 

Expenses

 

Fuel for electric generation and gas supply expenses comprise a largecomponent of LG&E’s total operating costs. The retail electric ratescontain a FAC and gas rates contain a GSC, whereby increases or decreases inthe 

 

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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 $35.7 million (22.4%) in 2002due to increased generation ($5.4 million) and higher cost of coal burned ($30.3 million). Fuel for electric generationdecreased $0.2 million (.1%) in 2001 primarily due to decreased generation as aresult of decreased electric sales ($2.2 million) partially offset by a highercost of coal burned ($2.0 million). The average delivered cost per ton of coalpurchased was $25.30 in 2002, $21.27 in 2001 and $20.96 in 2000.

 

Power purchased increased $2.9 million (3.5%) in 2002 due to anincrease in purchases to meet requirements for native load and off-system salespartially offset by decreased brokered sales activity in the wholesale electricmarket. Power purchased decreased $15.4 million (15.9%) in 2001 primarily dueto decreased brokered sales activity in the wholesale electric market and alower unit cost of the purchases partially offset by an increase in purchasesto meet requirements for native load and off-system sales.

 

Gas supply expenses decreased $24.1 million (11.7%) in 2002 due to adecrease in cost of net gas supply ($36.6 million), partially offset by anincrease in the volume of gas delivered to the distribution system ($12.5million). Gas supply expenses increased $9.3 million (4.7%) in 2001 primarilydue to an increase in cost of net gas supply ($36.2 million), partially offsetby a decrease in the volume of gas delivered to the distribution system ($26.9million). The average unit cost per Mcf of purchased gas was $4.19 in 2002,$5.27 in 2001 and $5.08 in 2000.

 

Other operation expenses increased $40.5 million (24.1%) in 2002primarily due to a full year amortization in 2002 of a regulatory asset createdas a result of the workforce reduction costs associated with LG&E’s VDT($17.0 million), higher costs for electric transmission primarily resultingfrom increased MISO costs ($13.9 million), an increase in property and otherinsurance costs ($3.9 million), an increase in pension costs due to change inpension assumptions to reflect current market conditions and change in marketvalue of the plan assets at the measurement date ($3.7 million), and anincrease in steam production costs ($3.4 million).  Other operation expenses increased $31.9 million (23.4%) in 2001primarily due to amortization of a regulatory asset resulting from workforcereduction costs associated with LG&E’s VDT ($13.0 million), an increase inpension expense  ($10.3 million) and anincrease in outside services ($8.5 million). Outside services increased in partdue to the reclassification of expenses as a result of the formation ofLG&E Services, as required by the SEC to comply with PUHCA.

 

Maintenance expenses for 2002 increased $1.5 million (2.6%) primarilydue to gas distribution expenses for main remediation work ($2.2 million).  Maintenance expenses for 2001 decreased $5.0million (7.9%) primarily due to decreases in scheduled outages ($2.8 million),and a decrease in software and communication equipment maintenance ($2.8million).

 

Depreciation and amortization increased $5.5 million (5.5%) in 2002 and$2.1 million (2.1%) in 2001 because of additional utility plant in service. The2001 increase was offset by a decrease in depreciation rates resulting from asettlement order in December 2001 from the Kentucky Commission.  Depreciation expenses decreased $5.6 millionas a result of the settlement order.

 

Variations in income tax expenses are largely attributable to changesin pre-tax income. LG&E’s 2002 effective income tax rate increased to 37.2%from the 36.5% rate in 2001. See Note 7 of LG&E’s Notes to FinancialStatements under Item 8.

 

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Property and other taxes decreased $0.3 million (1.6%) in 2002.Property and other taxes decreased $1.2 million (6.5%) in 2001 primarily due toa reduction in payroll taxes related to fewer employees as a result ofworkforce reductions and transfers to LG&E Services.

 

Other income – net decreased $2.1 million (72.0%) in 2002 primarily dueto increased  costs for non-utilityareas, $1.3 million and decreases in the gain on sale of property $0.8 million.Other income – net decreased $2.0 million (40.5%) in 2001 primarily due tolower interest and dividend income.

 

Interest charges for 2002 decreased $8.1 million (21.4%) primarily dueto lower interest rates on variable rate debt ($5.6 million) a decrease in debtto associated companies ($0.8 million) and an decrease in interest associatedwith LG&E’s accounts receivable securitization program ($1.5 million).  Interest charges for 2001 decreased $5.3million (12.2%) primarily due to lower interest rates on variable rate debt($2.2 million) and the retirement of short-term borrowings ($8.1 million)partially offset by an increase in debt to associated companies ($2.5 million) andan increase in interest associated with LG&E’s accounts receivablesecuritization program ($2.5 million). See Note 9 of LG&E’s Notes toFinancial Statements under Item 8.

 

LG&E’s weighted average cost of long-term debt, includingamortization of debt expense and interest rate swaps, was 3.87% at December 31,2002 compared to 4.17% at December 31, 2001. See Note 9 of LG&E’s Notes to Financial Statements underItem 8.

 

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

 

CRITICALACCOUNTING 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 to FinancialStatements under Item 8.

 

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Unbilled Revenue – At each month end LG&E preparesa financial estimate that projects electric and gas usage that has been used bycustomers, but not billed.  The estimatedusage is based on known weather and days not billed.  At December 31, 2002, a 10% change in these estimated quantitieswould cause revenue and accounts receivable to change by approximately $5.0million, including $2.3 million for electric usage and $2.7 million for gasusage.  See also Note 1 of LG&E’sNotes to Financial Statements under Item 8.

 

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.

 

LG&E’scosts of providing defined-benefit pension retirement plans is dependent upon anumber of factors, such as the rates of return on plan assets, discount rate,and contributions made to the plan.  Themarket value of LG&E plan assets has been affected by declines in theequity market since the beginning of the fiscal year.  As a result, at December 31, 2002, LG&E was required torecognize 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 for 2002.  Theamount of the liability depended upon the asset returns experienced in 2002 andcontributions made by LG&E to the plan during 2002.  Also, pension cost and cash contributions tothe plan could increase in future years without a substantial recovery in theequity market.  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.

 

Thecombination of poor market performance and a decrease in short-term corporatebond interest rates has created a divergence in the potential value of thepension liability and the actual value of the pension assets.  These conditions could result in an increasein LG&E’s funded accumulated benefit obligation and future pensionexpense.  The primary assumptions thatdrive the value of the unfunded accumulated benefit obligation are the discountrate and expected return on plan assets.

 

LG&E made a contribution to the pension plan of$83.1 million in January 2003.

 

A1% increase or decrease in the assumed discount rate could have an approximate$37.0 million positive or negative impact to the accumulated benefit obligationof LG&E.

 

See also Note 6 of LG&E’s Notes to Financial Statements under Item8.

 

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

 

Regulatoryassets represent incurred costs that have been deferred because they areprobable of future recovery in customer rates based upon Kentucky Commissionorders.  Regulatory liabilitiesgenerally represent obligations to make refunds to customers for previouscollections 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&Ehas accrued in the financial statements an estimate of $12.5 million for 2002ESM, with collection from 

 

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customercommencing in April 2003.  The ESM issubject to Kentucky Commission approval.

 

Seealso Note 3 of LG&E’s Notes to Financial Statements under Item 8.

 

NEWACCOUNTING PRONOUNCEMENTS

 

The following accountingpronouncements were issued that affected LG&E in 2002:

 

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 is January 1, 2003.  Management has calculated the impact of SFASNo. 143 and the recently released FERC NOPR No. RM02-7, *Accounting, Financial Reporting, andRate Filing Requirements for Asset Retirement Obligations*.  As of January 1, 2003, LG&E recordedasset retirement obligation (ARO) assets in the amount of $4.6 million and  liabilities in the amount of $9.3 million.LG&E also recorded a cumulative effect adjustment in the amount of $5.3million to reflect the accumulated depreciation and accretion of ARO assets atthe 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 of Regulation*.Also pursuant to SFAS No. 71, LG&E recorded regulatory liabilities in theamount of $60,000 offsetting removal costs previously accrued under regulatoryaccounting in excess of amounts allowed under SFAS No. 143.

 

LG&E also expects to record ARO accretion expense of approximately$617,000, ARO depreciation expense of approximately $117,000 and an offsettingregulatory credit in the income statement of approximately $734,000 in 2003,pursuant to regulatory treatment prescribed under SFAS No. 71, *Accountingfor the Effects of Certain Types of Regulation*.  The accretion, depreciation and regulatorycredit will be annual adjustments.  SFASNo. 143 will have no impact on the results of the operation of LG&E.

 

LG&E’s asset retirement obligations are primarily related to thefinal retirement of generating units. 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 obligationswill be 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 energy trading contracts bemarked to market on the balance sheet, with the gains and losses shown net inthe income statement.  In October 2002,the Emerging Issues Task Force reached a consensus to rescind EITF 98-10.  The effective date for the full rescissionis for fiscal periods beginning after December 15, 2002.  With the rescission of EITF No. 98-10,energy trading contracts that do not also meet the definition of a derivativeunder SFAS No. 133 must be accounted for as executory contracts.  Contracts previously recorded at fair valueunder EITF No. 98-10 that are not also derivatives under SFAS No. 133 must berestated to historical cost through a cumulative effect adjustment.  LG&E does not expect the rescission ofthis standard to have a material impact on financial position or results ofoperations.

 

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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 from other parties.  FIN 46 iseffective immediately for all new variable interest entities created oracquired after January 31, 2003.  Forvariable interest entities created or acquired prior to February 1, 2003, theprovisions of FIN 46 must be applied for the first interim or annual periodbeginning after June 15, 2003.  LG&Edoes not expect the adoption of this standard to have any impact on thefinancial position or results of operations.

 

LIQUIDITY AND CAPITAL RESOURCES

 

LG&E uses net cash generated from its operations and externalfinancing to fund construction of plant and equipment and the payment ofdividends.  LG&E believes that suchsources of funds will be sufficient to meet the needs of its business in theforeseeable future.

 

Operating Activities

 

Cash provided by operations was $212.4 million, $287.1 million and$156.2 million in 2002, 2001, and 2000, respectively.  The 2002 decrease compared to 2001 of $74.7 million resultedprimarily from the change in accounts receivable balances, including the saleof accounts receivable through the accounts receivable securitization programand a decrease in accounts payable and accrued taxes.  The 2001 increase of $130.9 million resulted primarily from anincrease in accounts receivable, and a decrease in accrued taxes.  See Note 1 of LG&E’s Notes to FinancialStatements under Item 8 for a discussion of accounts receivable securitization.

 

Investing Activities

 

LG&E’s primary use of funds for investing activities continues tobe for capital expenditures.  Capitalexpenditures were $220.4 million, $253.0 million and $144.2 million in 2002,2001, and 2000, respectively.  LG&Eexpects its capital expenditures for 2003 and 2004 to total approximately$340.0 million, which consists primarily of construction estimates associatedwith installation of NOx equipment as described in the section titled “EnvironmentalMatters,” purchase of jointly owned CTs with KU and on-going construction forthe distribution systems.

 

Net cash used for investment activities decreased $28.7 million in 2002compared to 2001 primarily due to the level of construction expenditures.  CT expenditures were approximately $35.9million in 2002 and $57.8 million in 2001. The $107.9 million increase in net cash used in 2001 as compared to 2000was due to NOx expenditures and the purchase of CTs.

 

Financing Activities

 

Net cash inflows for financing activities were $22.5 million in 2002 and outflows of $38.7 million and $67.7million in 2001 and 2000, respectively. In 2002, short-term borrowings increased $98.9 million which were usedin part for dividend payments of $73.3 million.  During 2001, short-term borrowings decreased $20.4 million from2000 and LG&E paid $28.0 million in dividends.

 

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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 million unsecuredpollution control bonds due November 1, 2027. The replacement variable rate bonds are secured by first mortgage bondsand will mature November 1, 2027.

 

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.

 

Under the provisions for LG&E’s variable-rate pollution controlbonds totaling $246.2million, thebonds are subject to tender for purchase at the option of the holder and tomandatory tender for purchase upon the occurrence of certain events, causingthe bonds to be classified as current portion of long-term debt.

 

Future Capital Requirements

 

Future capital requirements may be affected in varying degrees byfactors such as load growth, changes in construction expenditure levels, rateactions by regulatory agencies, new legislation, market entry of competingelectric power generators, changes in environmental regulations and otherregulatory requirements.  LG&Eanticipates funding future capital requirements through operating cash flow,debt, and/or infusions of capital from its parent.

 

LG&E’s debt ratings as of December 31, 2002, were:

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

 

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

 

Contractual Obligations

 

The following is provided to summarize LG&E’s contractual cashobligations for periods after December 31, 2002 (in thousands of $):

 
|                                   |   | **Payments  Due by Period** |    |
|----------------------------------------|--------|-----------------------------|---------|
| **Contractual cash  Obligations**      |   | **2003**                    |    | **2004-  2005** |   | **2006-  2007** |   | **After  2007** |   | **Total** |   |
|                                   |   |                        |    |   |   |   |   |   |   |   |   |
| Short-term debt(a)                     |   | $                           | 193,053 |   | $ | — |   | $ | — |   | $ | — |   | $ | 193,053 |   |
| Long-term debt(b)                      |   | 288,800                     |    | — |   | — |   | 328,104 |   | 616,904 |   |
| Operating  lease(c)                    |   | 3,371                       |    | 6,866 |   | 7,143 |   | 29,794 |   | 47,174 |   |
| Unconditional  purchase obligations(d) |   | 10,773                      |    | 20,268 |   | 21,632 |   | 184,544 |   | 237,217 |   |
| Other long-term  obligations(e)        |   | 28,401                      |    | 95,151 |   | — |   | — |   | 123,552 |   |
| Total  contractual cash obligations(f) |   | $                           | 524,398 |   | $ | 122,285 |   | $ | 28,775 |   | $ | 542,442 |   | $ | 1,217,900 |   |

 

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

(b)                                 Includeslong-term debt of $246.2 million classified as current liabilities becausethese bonds are subject to tender for purchase at the option of the holder andto mandatory tender for purchase upon the occurrence of certain events.  Maturity dates for these bonds range from2017 to 2027.

(c)                                  Operatinglease represents the lease of LG&E’s administrative office building.

(d)                                 Representsfuture minimum payments under purchased power agreements through 2020.

(e)                                  Representsconstruction commitments.

(f)                                    LG&Edoes not expect to pay the $246.2 million of long-term debt classified as acurrent liability in the consolidated balance sheets in 2003 as explained in(b) above.  LG&E anticipates cashfrom operations and external financing will be sufficient to fund futureobligations.  LG&E anticipates refinancinga portion of its short-term debt with long-term debt in 2003.

 

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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.

See Note 1 and 4 of LG&E’s Notes to Financial Statements under Item8.

 

Interest Rate Sensitivity

 

LG&E has short-term and long-term variable rate debt obligationsoutstanding.  At December 31, 2002, thepotential change in interest expense associated with a 1% change in base interest rates of LG&E’s unhedged debt isestimated at $5.5 million afterimpact 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, 2002, LG&E had swaps with a combined notionalvalue of $117.3 million.  The swaps exchange floating-rate interestpayments for fixed rate interest payments to reduce the impact of interest ratechanges on LG&E’s Pollution Control Bonds. The potential loss in fair value resulting from a hypothetical 1%adverse movement in base interest rates is estimated at $10.8 million as of December 31,2002.  This estimate is derived fromthird party valuations. Changes in the market value of these swaps if held tomaturity, as LG&E intends to do, will have no effect on LG&E’s netincome or cash flow.  See Note 4 ofLG&E’s Notes to Financial Statements under Item 8.

 

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Commodity Price Sensitivity

 

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

 

# **EnergyTrading & Risk Management Activities**

 

LG&E conducts energy trading and risk management activities tomaximize the value of power sales from physical assets it owns, in addition tothe wholesale sale of excess asset capacity. Certain energy trading activities are accounted for on a mark-to-marketbasis in accordance with *EITF 98-10 Accounting for Contracts Involved inEnergy Trading and Risk Management Activities*, S*FAS No. 133 Accounting for DerivativeInstruments and Hedging Activities,* and *SFAS No. 138 Accounting for CertainDerivative Instruments and Certain Hedging Activities*.  Wholesale sales of excess asset capacity andwholesale purchases are treated as normal sales and purchases under *SFAS No. 133*and *SFASNo. 138* and are not marked-to-market.

 

The rescission of *EITF 98-10*, effective for fiscal periods ending after December 15, 2002, willhave no impact on LG&E’s energy trading and risk management reporting asall contracts marked to market under *EITF 98-10* are also within the scope of *SFAS No. 133*.

 

The table belowsummarizes LG&E’s energy trading and risk management activities for 2002and 2001 (in thousands of $).

##  

|                                                          |   | **2002** |   | **2001** |   |
|---------------------------------------------------------------|--------|----------|--------|----------|--------|
| Fair value of contracts at beginning of period, net liability |   | $        | (186   | )        | $      | (17 | ) |
| Fair value of contracts when entered into during the period   |   | (65      | )      | 3,441    |   |
| Contracts realized or otherwise settled during the period     |   | 448      |   | (2,894   | )      |
| Changes in fair values due to changes in assumptions          |   | (353     | )      | (716     | )      |
| Fair value of contracts at end of period, net liability       |   | $        | (156   | )        | $      | (186 | ) |

 

No changes to valuation techniques for energy tradingand risk management activities occurred during 2002.  Changes in market pricing, interest rate and volatilityassumptions were made during both years. All contracts outstanding at December 31, 2002, have a maturity of lessthan one year and are valued using prices actively quoted for proposed orexecuted transactions or quoted by brokers.

 

LG&E maintains policies intended to minimize credit risk and revaluescredit exposures daily to monitor compliance with those policies.  At December 31, 2002, 86% of the trading andrisk management commitments were with counterparties rated BBB- equivalent orbetter.

 

Accounts Receivable Securitization

 

On February 6, 2001, LG&E implemented an accounts receivablesecuritization program.  The purpose ofthis program is 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 allows 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 is ableto terminate the program at any time without penalty.  If there is a significant deterioration in the payment record ofthe receivables by the retail 

 

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customers or if LG&E fails to meet certain covenants regarding theprogram, the program may terminate at the election of the financialinstitutions.  In this case, paymentsfrom retail customers would first be used to repay the financial institutionsparticipating in the program, and would then be available for use by LG&E.

 

As part of the program, LG&E sold retail accounts receivables to 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 can 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 programs is comparable to LG&E’s lowestcost source of capital, and is based on prime rated commercial paper. LG&Eretains servicing rights of the sold receivables through two separate servicingagreements with the third party purchaser. LG&E has obtained an opinion from independent legal counselindicating these transactions qualify as a true sale of receivables.  As of December 31, 2002, the outstandingprogram balance was $63.2 million. LG&E is considering unwinding its accounts receivable securitizationarrangements involving LG&E R during 2003.

 

The allowance for doubtful accounts associated with the eligiblesecuritized receivables was $2.1 millionat December 31, 2002.  This allowance isbased on historical experience of LG&E. Each securitization facilitycontains a fully funded reserve for uncollectible receivables.

 

RATES AND REGULATION

 

Following the purchase ofPowergen by E.ON, E.ON became a registered holding company under PUHCA.  As a result, E.ON, its utility subsidiaries,including LG&E, and certain of its non-utility subsidiaries are subject toextensive regulation by the SEC under PUHCA with respect to issuances and salesof securities, acquisitions and sales of certain utility properties, andintra-system sales of certain goods and services.  In addition, PUHCA generally limits the ability of registeredholding companies to acquire additional public utility systems and to acquireand retain businesses unrelated to the utility operations of the holdingcompany.  LG&E believes that it hasadequate authority (including financing authority) under existing SEC ordersand regulations to conduct its business. LG&E will seek additional authorization when necessary.

 

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 the state of Kentucky, LG&E has no plans or intentions to discontinueits application of SFAS No. 71.  SeeNote 3 of LG&E’s Notes to Financial Statements under Item 8.

 

Kentucky Commission Settlement Order - VDT Costs, ESM and Depreciation

 

During the first quarter 2001, LG&E recorded a $144 million chargefor a workforce reduction program. Primary components of the charge were separation benefits, enhancedearly retirement benefits, and health care benefits.  The result of this workforce reduction was the elimination ofapproximately 700 positions, accomplished primarily through a voluntaryenhanced severance program.

 

On June 1, 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 

 

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resulting depreciation rates implemented in 2001.

 

LG&E reached a settlement in the VDT case as well as the othercases involving depreciation rates and ESM with all intervening parties.  The settlement agreement was approved byKentucky Commission Order on December 3, 2001. The order allowed LG&E to set up a regulatory asset of $141 millionfor the workforce reduction costs and begin amortizing these costs over a fiveyear period starting in April 2001.  Thefirst quarter 2001 charge of $144 million represented all employees who hadaccepted a voluntary enhanced severance program.  Some employees rescinded their participation in the voluntaryenhanced severance program, thereby decreasing the original charge from $144million to $141 million.  The settlementwill also reduce revenues approximately $26 million through a surcredit onfuture bills to customers 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 LG&E’s new depreciation rates in effect December 2001,retroactive to January 1, 2001.  The newdepreciation rates decreased depreciation expense by $5.6 million in 2001.

 

Environmental Cost Recovery

 

In June 2000, the Kentucky Commission approved LG&E’s applicationfor a CCN to construct up to three SCR NOx reduction facilities. Theconstruction and subsequent operation of the SCRs is intended to reduce NOxemission levels to meet the EPA’s mandated NOx emission level of 0.15 lbs./Mmbtu by May 2004.  In its order, theKentucky Commission 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 Environmental Cost Recovery Tariff toinclude an overall rate of return on capital investments. Approval ofLG&E’s application in April 2001 allowed LG&E to begin to recover thecosts associated with these new projects, subject to Kentucky Commissionoversight during normal six-month and two-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 on October 22, 2002,in which LG&E was ordered to refund $325,000 to customers over the fourmonth period beginning November 2002 and ending February 2003.  Additionally, LG&E was ordered to roll$4.1 million into base rates and make corresponding adjustments to the monthlyenvironmental surcharge filings to reflect that portion of environmental ratebase now included in base rates on a going-forward basis.

 

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.  The Kentucky Commission conducteda public hearing on the case on December 20, 2002, final briefs were filed onJanuary 15, 2003, and a final order was issued February 11, 2003.  The final order approved recovery of fournew environmental compliance facilities totaling $43.1 million.  A fifth project, expansion of the land fillfacility at the Mill Creek Station, was denied without prejudice with aninvitation to reapply for recovery when required construction permits areapproved.  Cost 

 

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recovery through the environmental surcharge of the four approvedprojects will begin with the bills rendered in April 2003.

 

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; if earningsare below the lower limit, the earnings deficiency is recovered 40% fromratepayers 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.  LG&Emade its second ESM filing on March 1, 2002, for the calendar year 2001reporting period.  LG&E is in theprocess of refunding $441,000 to customers for the 2001 reporting period.  LG&Eestimated that the rate of return will fall below the lower limit, subject toKentucky Commission approval, for the year ended December 31, 2002.  The 2002 financial statements include anaccrual to reflect the earnings deficiency of $12.5 million to be recoveredfrom customers commencing in April 2003.

 

On November 27, 2002, LG&E filed a revised ESM tariff whichproposed continuance of the existing ESM through December 2005.  The Kentucky Commission issued an Ordersuspending the ESM tariff one day making the effective date January 2,2003.  In addition, the KentuckyCommission is conducting a management audit to review the ESM plan and reassessits reasonableness in 2003.  LG&Eand interested parties will have the opportunity to provide recommendations formodification and continuance of the ESM or other forms of alternative orincentive regulation.

 

DSM

 

LG&E’srates contain a DSM provision. The provision includes a rate mechanism that provides concurrentrecovery of DSM costs and provides an incentive for implementing DSMprograms.  This program had allowedLG&E to recover revenues from lost sales associated with the DSMprogram.  In May 2001, the KentuckyCommission approved LG&E’s plan to continue DSM programs.  This filing called for the expansion of theDSM programs into the service territory served by KU and proposed a mechanismto recover revenues from lost sales associated with DSM programs based onprogram planning engineering estimates and post-implementation evaluation.

 

Gas PBR

 

Since November 1, 1997,LG&E has operated under an experimental PBR mechanism related to its gasprocurement 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, 2002, LG&E has achieved $38.1 millionin savings. Of the total savings, LG&E has retained $16.5 million, and theremaining portion of $21.6 million has been distributed to customers.  In December 2000, LG&E filed anapplication reporting on the operation of the experimental PBR and requestedthe Kentucky Commission to extend the PBR as a result of the benefits providedto both LG&E and its customers during the experimental period. Following thediscovery and hearing process, the Kentucky Commission issued an ordereffective November 1, 2001, extending the experimental PBR program for anadditional four years, and making other modifications, 

 

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including changes to thesharing levels applicable to savings or expenses incurred under the PBR.  Specifically, the Kentucky Commissionmodified the sharing mechanism to a 25%/75% Company/Customer sharing for allsavings (and expenses) up to 4.5% of the benchmarked gas costs.  Savings (and expenses) in excess of 4.5% ofthe benchmarked gas costs are shared at a 50%/50% level.

 

FAC

 

Prior to implementation of the electric PBR in July 1999, and followingits termination in March 2000, LG&E employed an FAC mechanism, which underKentucky law allowed LG&E to recover from customers the actual fuel costsassociated with retail electric sales. In February 1999, LG&E received orders from the Kentucky Commissionrequiring a refund to retail electric customers of approximately $3.9 millionresulting from reviews of the FAC from November 1994, through April 1998.  While legal challenges to the KentuckyCommission order were pending acomprehensive settlement was reached by all parties and approved by the  Kentucky Commission on May 17, 2002.   Thereunder, LG&E agreed to credit itsfuel clause in the amount of $720,000 (such credit provided over the course ofJune and July 2002), and the parties agreed on a prospective interpretation ofthe state’s fuel adjustment clause regulation to ensure consistent and mutuallyacceptable application on a going-forward basis.

 

In December 2002, the Kentucky Commission initiated a two year reviewof the operation of LG&E’s FAC for the period November 2000 through October2002.  Testimony in the review case wasfiled on January 20, 2003 and a public hearing was held February 18, 2003.  Issues addressed at that time included theestablishment of the current base fuel factor to be included in LG&E’s baserates, verification of proper treatment of purchased power costs during unitoutages, and compliance with fuel procurement policies and practices.

 

Gas Rate Case

 

In March 2000, LG&E filed an application with the KentuckyCommission requesting an adjustment in LG&E’s gas rates.  In September 2000, the KentuckyCommission granted LG&E an annual increase in its base gas revenues of$20.2 million effective September 28, 2000.  The Kentucky Commission authorized a return on equity of 11.25%.  The Kentucky Commission approved LG&E’sproposal for a weather normalization billing adjustment mechanism that willnormalize the effect of weather on base gas revenues from gas sales.

 

Wholesale Natural Gas Prices

 

On September 12, 2000, the Kentucky Commission issued an orderestablishing Administrative Case No. 384 – “An Investigation of IncreasingWholesale Natural Gas Prices and the Impacts of such Increase on the RetailCustomers Served by Kentucky’s Jurisdictional Natural Gas DistributionCompanies”.  The impetus for thisadministrative proceeding was the escalation of wholesale natural gas pricesduring the summer of 2000.

 

The Kentucky Commissiondirected Kentucky’s natural gas distribution companies, including LG&E, tofile selected information regarding the individual companies’ natural gaspurchasing practices, expectations for the then-approaching winter heatingseason of 2000-2001, and potential actions which these companies might take tomitigate price volatility.  On July 17,2001, the Kentucky Commission issued an order encouraging the natural gas distributioncompanies in Kentucky to take various actions, among them to propose a naturalgas hedge plan, consider performance-based ratemaking mechanisms, and toincrease the use of storage.

 

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In April 2002, in Case No. 2002-00136, LG&E proposed a hedging planfor the 2002/2003 winter heating season with three alternatives, the first twousing a combination of storage and financial hedge instruments and the thirdrelying upon storage alone.  LG&Eand the Attorney General, who represents Kentucky consumers, entered into asettlement which selected the third option. In August 2002, the Kentucky Commission approved the plan contemplatedin the settlement.  The KentuckyCommission validated the effectiveness of storage to mitigate potentially highwinter gas prices by approving this natural gas hedging plan.

 

The Kentucky Commission also decided in Administrative Case No. 384 toengage a consultant to conduct a forward-looking audit of the gas procurementand supply procedures of Kentucky’s largest natural gas distributioncompanies.  The KentuckyCommission completed its audit in late 2002.  The audit recognized LG&E as ”efficient andeffective [in the] procurement and management of significant quantities ofnatural gas supplies.”  The auditors also recognized that “the Company’sresidential gas prices have long been below averages for the U. S. and for theCommonwealth of Kentucky” which “demonstrates [LG&E’s] effectiveness in[the] procurement and management of natural gas supplies.”  The audit alsostated that the ”Company’s very impressive record in keeping its ratesdown provides sound evidence on the excellent job done in the area of gassupply procurement and management.”

 

Kentucky Commission Administrative Case forAffiliate Transactions

 

In December 1997, the Kentucky Commission opened Administrative CaseNo. 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.  During theperiod September 1998 to February 2000, the Kentucky Commission issued draftcodes of conduct and cost allocation guidelines.  In early 2000, the  KentuckyGeneral Assembly enacted legislation, House Bill 897, which authorized theKentucky Commission to require utilities who provide nonregulated activities tokeep 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.  On February 14, 2001, theKentucky Commission published notice of their intent to promulgate newadministrative regulations under the auspices of the new law.  This effort is still on going.

 

Kentucky Commission Administrative Case forSystem Adequacy

 

On June 19, 2001, Kentucky Governor Paul E. Patton issued ExecutiveOrder 2001-771, which directed the Kentucky Commission to review and studyissues relating to the need for and development of new electric generatingcapacity in Kentucky.  The issues to beconsidered included the impact of new power plants on the electric supply grid,facility citing issues, and economic development matters, with the goal ofensuring a continued, reliable source of supply of electricity for the citizensof Kentucky and the continued environmental and economic vitality of Kentuckyand its communities.  In response tothat Executive Order, in July 2001 the 

 

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Kentucky Commission opened Administrative Case No. 387 to review theadequacy of Kentucky’s generation capacity and transmission system.  Specifically, the items reviewed were theappropriate level of reliance on purchased power, the appropriate reservemargins to meet existing and future electric demand, the impact of spikes innatural gas prices on electric utility planning strategies, and the adequacy ofKentucky’s electric transmission facilities. LG&E, as a party to this proceeding, filed written testimony andresponded to two requests for information. Public hearings were held and in October 2001, LG&E filed a finalbrief in the case.  In December 2001,the Kentucky Commission issued an order in which it noted that LG&E isresponsibly addressing the long-term supply needs of native load customers andthat current reserve margins are appropriate. However, due to the rapid pace of change in the industry, the order alsorequires LG&E to provide an annual assessment of supply resources, futuredemand, 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

 

On July 31, 2002,FERC issued a NOPR in Docket No. RM01-12-000 which would substantially alterthe regulations governing the nation’s wholesale electricity markets byestablishing a common set of rules — SMD. The SMD NOPR would require eachpublic utility that owns, operates, or controls interstate transmissionfacilities to become an Independent Transmission Provider (ITP), belong to anRTO that is an ITP, or contract with an ITP for operation of its transmissionassets. It would also establish a standardized congestion management system,real-time and day-ahead energy markets, and a single transmission service fornetwork and point-to-point transmission customers. Review of the proposedrulemaking is underway and a final rule is expected during 2003.  While it is expected that the SMD final rulewill affect LG&E revenues and expenses, the specific impact of the rulemakingis not known at this time.

 

MISO

 

LG&E is a member of the MISO, which began commercial operations onFebruary 1, 2002.  MISO now hasoperational control over LG&E’s high-voltage transmission facilities (100kV and greater), while LG&E continues to control and operate the lowervoltage transmission subject to the terms and conditions of the MISO OATT.  As a transmission-owning member of MISO,LG&E also incurs administrative costs of MISO pursuant to Schedule 10 ofthe MISO OATT.

 

MISO also proposedto implement a congestion management system. FERC directed the MISO to coordinate its efforts with FERC’s Rulemakingon SMD. OnSeptember 24, 2002, the MISO filed new rate schedules designated as Schedules16 and 17, which provide for the collection of costs incurred by the MISO toestablish day-ahead and real-time energy markets. The MISO proposed to recoverthese costs under Schedules 16 and 17 once service commences. If approved byFERC, these schedules will cause LG&E to incur additional costs.  LG&E opposes the establishment ofSchedules 16 and 17.  This effort isstill on-going and the ultimate impact of the two schedules, if approved, isnot known at this time.

 

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Merger Surcredit

 

As part of the LG&E Energy merger with KU Energy in 1998, LG&EEnergy estimated non-fuel savings over a ten–year period following themerger.  Costs to achieve these savingsfor LG&E of $50.2 million were recorded in the second quarter of 1998,$18.1 million of which was deferred and amortized over a five-year periodpursuant to regulatory orders.  Primarycomponents of the merger costs were separation benefits, relocation costs, andtransaction fees, the majority of which were paid by December 31, 1998.  LG&E expensed the remaining costsassociated with the merger ($32.1 million) in the second quarter of 1998.

 

In approving the merger, the Kentucky Commission adopted LG&E’sproposal to reduce its retail customers’ bills based on one-half of theestimated merger-related savings, net of deferred and amortized amounts, over afive-year period.  The surcreditmechanism provides that 50% of the net non-fuel cost savings estimated to beachieved from the merger be provided to ratepayers through a monthly billcredit, and 50% be retained by the Companies, over a five-year period.  The surcredit was allocated 53% to KU and47% to LG&E.  In that same order,the Commission required LG&E and KU, after the end of the five-year period,to present a plan for sharing with customers the then-projected non-fuelsavings associated with the merger.  TheCompanies submitted this filing on January 13, 2003, proposing to continue toshare with customers, on a 50%/50% basis, the estimated fifth-year gross levelof non-fuel savings associated with the merger.  The filing is currently under review.

 

Any fuel cost savings are passed to Kentucky customersthrough the fuel adjustment clause.  SeeFAC above.

 

Environmental Matters

 

The Clean Air Act imposed stringent new SO2 and NOx emission limits onelectric generating units.  LG&Epreviously had installed scrubbers on all of its generating units.  LG&E’s strategy for Phase II SO2reductions, which commenced January 1, 2000, is to increase scrubber removalefficiency to delay additional capital expenditures and may also include fuelswitching or upgrading scrubbers. LG&E met the NOx emission requirements of the Act throughinstallation of low-NOx burner systems. LG&E’s compliance plans are subject to many factors includingdevelopments in the emission allowance and fuel markets, future regulatory andlegislative initiatives, and advances in clean air control technology.  LG&E will continue to monitor thesedevelopments to ensure that its environmental obligations are met in the mostefficient and cost-effective manner.

 

In September 1998, the EPA announced its final “NOx SIP Call” rulerequiring states to impose significant additional reductions in NOx emissionsby May 2003, in order to mitigate alleged ozone transport impacts on theNortheast region.  The Commonwealth ofKentucky is currently in the process of revising its SIP to require reductionsin NOx emissions from coal-fired generating units to the 0.15 lb./Mmbtu levelon a system-wide basis.  In related proceedingsin response to petitions filed by various Northeast states, in December 1999,EPA issued a final rule pursuant to Section 126 of the Clean Air Act 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 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 

 

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in late 2000 and continuing through the final compliance date.  LG&E estimates that it will incur totalcapital costs of approximately $178 million to reduce its NOx emissions to the0.15 lb./Mmbtu level on a company-wide basis. In addition, LG&E will incur additional operating 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 asignificant portion 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 the appeal of the D.C.Circuit’s remand of the EPA’s revised air quality standards for ozone andparticulate matter, measures to implement EPA’s regional haze rule, and EPA’sDecember 2000 determination to regulate mercury emissions from powerplants.  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 in the process of converting the Mill CreekStation to wet stack operation in an effort to resolve all outstanding issuesrelated to particulate matter emissions.

 

LG&E owns or formerly owned three properties which are the locationof past MGP operations.  Variouscontaminants are typically found at such former MGP sites and environmentalremediation measures are frequently required. With respect to the sites, LG&E has completed cleanups, obtainedregulatory approval of site management plans, or reached agreements for otherparties to assume responsibility for cleanup. Based on currently available information, management estimates that itwill incur additional costs of $400,000. Accordingly, an accrual of $400,000 has been recorded in theaccompanying financial statements at December 31, 2002 and 2001.

 

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

 

Deferred Income Taxes

 

LG&E expects to have adequate levels of taxable income to realizeits recorded deferred tax assets.  At December31, 2002, deferred tax assets totaled $98.2million  and were principallyrelated to expenses attributable to LG&E’s pension plans and postretirement benefit obligations.

 

FUTURE OUTLOOK

 

Competition and Customer Choice

 

LG&E has moved aggressively over the past decade to be positionedfor the energy industry’s shift to customer choice and a competitive market forenergy services.  Specifically, LG&Ehas taken many steps to prepare for the expected increase in competition in itsbusiness, including support for PBR structures; aggressive cost reductionactivities; strategic acquisitions, dispositions and growth initiatives;write-offs of previously deferred expenses; an increase in focus on commercialand industrial customers; an increase in employee training; and necessarycorporate and business unit realignments.

 

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In December 1997, the Kentucky Commission issued a set of principleswhich was intended to serve as its guide in consideration of issues relating toindustry restructuring.  Among theissues addressed by these principles are: consumer protection and benefit,system reliability, universal service, environmental responsibility, costallocation, stranded costs and codes of conduct.  During 1998, the Kentucky Commission and a task force of theKentucky General Assembly had each initiated proceedings, including meetingswith representatives of utilities, consumers, state agencies and other groupsin Kentucky, to discuss the possible structure and effects of energy industryrestructuring in Kentucky.

 

In November 1999, the task force issued a report to the Governor ofKentucky and a legislative agency recommending no general electric industryrestructuring actions during the 2000 legislative session.  No general restructuring actions have beentaken to date by the legislature.

 

Thus, at the time of this report, neither the Kentucky General Assemblynor the Kentucky Commission has adopted or approved a plan or timetable forretail electric industry competition in Kentucky.  The nature or timing of the ultimate legislative or regulatoryactions regarding industry restructuring and their impact on LG&E, whichmay be significant, cannot currently be predicted.

 

While many states have moved forward in providing retail choice, manyothers have not. Some are reconsidering their initiatives and have even delayedimplementation.

 

KU

 

GENERAL

 

The following discussion and analysis bymanagement focuses on those factors that had a material effect on KU’s financialresults of operations and financial condition during 2002, 2001,and 2000 and should be read inconnection with the financial statements and notes thereto.

 

Some of the following discussion may containforward-looking statements that are subject to certain risks, uncertainties andassumptions.  Such forward-lookingstatements are intended to be identified in this document by the words“anticipate,” “expect,” “estimate,” “objective,” “possible,” “potential” and similarexpressions.  Actual results may materiallyvary.  Factors that could cause actualresults to materially 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 KU’s reports to the SEC, including Exhibit No. 99.01 to this report onForm 10-K.

 

MERGERS and ACQUISITIONS

 

On December 11, 2000, LG&E Energy was acquired by Powergen forcash of approximately $3.2 billion or $24.85 per share and the assumption ofall of LG&E Energy’s debt.  As aresult of the acquisition, LG&E Energy became a wholly owned subsidiary ofPowergen and, as a result, KU became an indirect subsidiary of Powergen.  KU has continued its separate identity andserves customers in Kentucky, Virginia and Tennessee  under its existing name. The preferred stock and debt securities of KU were not affected by thistransaction and KU continued to file SEC reports. Following the acquisition,Powergen became a registered holding company under PUHCA and KU, as asubsidiary of a registered holding company, became subject to additional 

 

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regulation under PUHCA.  See“Rates and Regulation” under Item 1.

 

On July 1, 2002, E.ON, a German company,completed its acquisition of Powergen plc (now Powergen Limited).  As aresult, LG&E and KU became indirect subsidiaries of E.ON.  E.ON had announced its pre-conditional cashoffer of £5.1 billion ($7.3 billion) for Powergen on April 9, 2001.  Following the acquisition, E.ON became aregistered holding company under PUHCA.

 

As contemplated 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.

 

RESULTS OF OPERATIONS

 

Net Income

 

KU’s net income in 2002 decreased $3.0 million compared to 2001.  The decrease resulted primarily from highertransmission operating expenses, an increase in amortization of regulatoryassets, and increased property insurance, partially offset by an increase insales to retail customers and lower interest expenses.

 

KU’s net income in 2001 was relatively flat as compared to 2000 with anincrease of $.9 million. The increase resulted primarily from decreaseddepreciation, interest expenses and property and other taxes, partially offsetby higher pension related expenses and amortization of regulatory assets.

 

Revenues

 

A comparison of operating revenues for the years 2002 and 2001,excluding the provision for rate collections (refunds), with the immediatelypreceding year reflects both increases and decreases which have been segregatedby the following principal causes (in thousands of $):

 
|                                   |   | **Increase  (Decrease)  From Prior Period** |   |
|----------------------------------------|--------|---------------------------------------------|--------|
| **Cause**                              |   | **2002**                                    |   | **2001** |   |
|                                   |   |                                        |   |   |   |
| Retail sales:                          |   |                                        |   |   |   |
| Fuel clause  adjustments               |   | $                                           | 18,223 |   | $ | 10,220 |   |
| KU/LG&E Merger surcredit           |   | (2,641                                      | )      | (3,856 | ) |
| Environmental  cost recovery surcharge |   | 3,781                                       |   | 1,458 |   |
| Demand side  management                |   | 1,570                                       |   | — |   |
| Performance  based rate                |   | —                                      |   | 1,747 |   |
| Electric rate  reduction               |   | —                                      |   | (5,395 | ) |
| VDT surcredit                          |   | (527                                        | )      | (372 | ) |
| Variation in  sales volumes, and other |   | 46,601                                      |   | (1,627 | ) |
| Total retail  sales                    |   | 67,007                                      |   | 2,175 |   |
| Wholesale sales                        |   | (59,373                                     | )      | 5,108 |   |
| Other                                  |   | 7,132                                       |   | 1,202 |   |
| Total                                  |   | $                                           | 14,766 |   | $ | 8,485 |   |

 

Electric revenues increased in 2002 primarily due to an increase inretail sales due to warmer weather and an increase in the recovery of fuelcosts passed through the FAC. Cooling degree days for 2002 increased 26% over2001. The increase in retail sales was partially offset by a decrease inwholesale sales volumes. The 

 

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decrease in wholesale sales was due in large part to fewer megawattsavailable due to increased retail sales. Electric revenues increased in 2001 primarily due to an increase in therecovery of fuel costs passed through the FAC and an increase in wholesaleactivity partially offset by a rate reduction ordered by Kentucky Commission in2000 and lower sales volumes.

 

Expenses

 

Fuel for electric generation comprises a large component of KU’s totaloperating expenses.  KU’s Kentuckyjurisdictional electric rates are subject to a FAC whereby increases ordecreases are reflected in the FAC factor, subject to the approval of theKentucky Commission.   KU’s wholesaleand 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 generation increased $13.1 million (5.5%) in 2002 becauseof an increase in the cost of coal burned ($29.7 million), partially offset bya decrease in generation ($16.5 million). Fuel for electric generationincreased $17.1 million (7.8%) in 2001 because of an increase in the cost ofcoal burned ($21.8 million), partially offset by a decrease in generation ($4.7million).  The average delivered costper ton of coal purchased was $31.44 in 2002, $27.84 in 2001 and  $25.63 in 2000.

 

Power purchased expense in 2002 increased slightly over 2001, $.8million (.5%) primarily due to an increase in purchases to meet requirementsfor native load and off-system sales partially offset by a decrease in purchaseprice.  Power purchased expensedecreased $9.8 million (5.9%) in 2001 primarily due to decreased brokered salesactivity in the wholesale electric market and a lower unit cost of thepurchases partially offset by an increase in purchases to meet requirements fornative load and off-system sales.

 

Other operation expenses increased $25.8 million (21.8%) in 2002. Theprimary cause for the increase was the full year amortization in 2002 of aregulatory asset created as a result of the workforce reduction associated withKU’s VDT of $6.5 million, higher costs for electric transmission primarilyresulting from increased MISO costs of $7.4 million, an increase in propertyinsurance costs of $2.8 million, an increase in employee benefit costs due tochanges in pension assumptions to reflect current market conditions and changesin market value of plan assets at the measurement date of $1.7 million, and anincrease in outside services of $4.9 million.  Other operation expenses increased $10.3 million (9.5%) in 2001. Theprimary cause for the increase was the amortization of a regulatory asset as aresult of the workforce reduction associated with KU’s VDT of $5.0 million andan increase in pension expense of $5.5 million.

 

Maintenance expenses increased $5.9 million (10.3%) in 2002 primarilydue to increases in steam maintenance of $6.1 million related to annual outagesat the Ghent, Green River, and Tyrone steam facilities.  Maintenance expenses for 2001 decreased $4.6million (7.5%) primarily due to decreased repairs to steam facilities ($6.5million).

 

Depreciation and amortization increased $5.2 million (5.7%) in 2002primarily due to an increase in plant in service.  Depreciation and amortization decreased $8.0 million (8.1%) in2001 primarily due to a reduction in depreciation rates as a result of asettlement order in December 2001 from the Kentucky Commission.  Depreciation expenses decreased by $6.0million as a result of the settlement order.

 

Variations in income tax expense are largely attributable to changes inpre-tax income.  The 2002 effectiveincome tax rate decreased to 34.9% from the 35.9% rate in 2001. See Note 7 ofKU’s Notes to Financial Statements under Item 8.

 

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Property and other taxes increased $1.1 million (7.6%) in 2002 due tohigher property taxes and payroll taxes. Property and other taxes decreased$3.1 million (18.2%) in 2001 due to decreases in payroll taxes related to feweremployees as a result of workforce reductions and transfers to LG&E EnergyServices Company.

 

Other income-net increased $1.5 million (16.8%) in 2002 primarily dueto a non-recurring increase in earnings from KU’s equity earnings in a minorityinterest of  $5.2 million, partiallyoffset by a gain on disposition of property in 2001,  $1.8 million, lower interest and dividend income frominvestments, $0.7 million, and higher benefit and other costs, $1.4million.  The increased equity earningsin 2002 are due to the gain on the sale of emissions allowances. Otherincome-net increased $2.1 million (30.5%) in 2001 due to an increase in the gainon sale of assets.

 

Interest charges decreased $8.3 million (24.5%) in 2002 as compared to2001 due to lower interest rates on variable rate debt and refinancing of longterm debt with lower interest rates, $8.0 million. Interest charges decreased$5.4 million (13.7%) in 2001 from 2000 due to lower interest rates on variablerate debt, $4.6 million, the retirement of short-term borrowings, $1.6 million,lower interest on debt to parent company, $1.2 million, partially offset by anincrease in interest associated with KU’s accounts receivable securitizationprogram, $1.8 million.

 

KU’s weighted average cost of long-term debt, including amortization ofdebt expense and interest rate swaps, was 3.30% at December 31, 2002 comparedto 4.91% at December 31, 2001.  See Note9 of KU’s Notes to Financial Statements under Item 8.

 

The rate of inflation may have a significant impact on KU’s operations,its ability to control costs and the need to seek timely and adequate rateadjustments.  However, relatively lowrates of inflation in the past few years have moderated the impact on currentoperating results.

 

CRITICALACCOUNTING POLICIES/ESTIMATES

 

Preparationof financial statements and related disclosures in compliance with generallyaccepted accounting principles requires the application of appropriate technicalaccounting rules and guidance, as well as the use of estimates.  The application of these policiesnecessarily involves judgments regarding future events, including legal andregulatory 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 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 KU’s Notes to FinancialStatements under Item 8.

 

Unbilled Revenue – At each month end KU prepares a financial estimatethat projects electric usage that has been used by customers, but notbilled.  The estimated usage is based onknown weather and days not billed.  AtDecember 31, 2002, a 10% change in these estimated quantities would causerevenue and accounts receivable to change by approximately $4.2 million.  See also Note 1 of KU’s Notes to FinancialStatements under Item 8.

 

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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 and otheractuarial assumptions.

 

KU’scosts of providing defined-benefit pension retirement plans is dependent upon anumber of factors, such as the rates of return on plan assets, discount rate,and contributions made to the plan.  Themarket value of KU plan assets has been affected by declines in the equitymarket since the beginning of the fiscal year. As a result, 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 for 2002.  The amount of the liability depended uponthe asset returns experienced in 2002 and contributions made by KU to the planduring 2002.  Also, pension cost andcash contributions to the plan could increase in future years without asubstantial recovery in the equity market. If the fair value of the plan assets exceeds the accumulated benefitobligation, the recorded liability will be reduced and other comprehensiveincome will be restored in the consolidated balance sheet.

 

Thecombination of poor market performance and a decrease in short-term corporatebond interest rates has created a divergence in the potential value of thepension liability and the actual value of the pension assets.  These conditions could result in an increasein KU’s funded accumulated benefit obligation and future pension expense.  The primary assumptions that drive the valueof the unfunded accumulated benefit obligation are the discount rate andexpected return on plan assets.

 

KU made a contribution to the pension plan of $3.5million in January 2003.

 

A1% increase or decrease in the assumed discount rate could have an approximate$26.0 million positive or negative impact to the accumulated benefit obligationof KU.

 

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

 

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

 

Regulatoryassets represent incurred costs that have been deferred because they areprobable of future recovery in customer rates based upon Kentucky Commissionorders.  Regulatory liabilitiesgenerally represent obligations to make refunds to customers for previouscollections 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.

 

KUhas accrued in the financial statements, an estimate of $13.5 million for 2002ESM, with collection from customers commencing in April 2003.  The ESM is subject to Kentucky Commissionapproval.

 

Seealso Note 3 of KU’s Notes to Financial Statements under Item 8.

 

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NEW ACCOUNTING PRONOUNCEMENTS

 

The following accountingpronouncements were issued that affected KU in 2002:

 

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 is January 1,2003.  Management has calculated theimpact of SFAS No. 143 and the recently released FERC NOPR No. RM02-7, *Accounting,Financial Reporting, and Rate Filing Requirements for Asset RetirementObligations*.  As of January1, 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 $888,000 offsetting removal costspreviously accrued under regulatory accounting in excess of amounts allowedunder SFAS No. 143.

 

KU also expects to record ARO accretion expense of approximately $1.2million, ARO depreciation expense of approximately $176,000 and an offsettingregulatory credit in the income statement of approximately $1.4 million in2003, pursuant to regulatory treatment prescribed under SFAS No. 71, *Accountingfor the Effects of Certain Types of Regulation*.  The accretion, depreciation and regulatorycredit will be annual adjustments.  SFASNo. 143 will have no impact on the results of the operation of KU.

 

KU’s asset retirement obligations are primarily related to the finalretirement of generating units.  KUtransmission and distribution lines largely operate under perpetual propertyeasement agreements which do not generally require restoration upon removal ofthe property.  Therefore, under SFAS No.143, no material asset retirement obligations will be recorded for transmissionand distribution assets.

 

KU adopted EITF No. 98-10, *Accounting for Energy Trading and Risk ManagementActivities*, effective January 1, 1999.  This pronouncement required that energy trading contracts bemarked to market on the balance sheet, with the gains and losses shown net inthe income statement.  In October 2002,the Emerging Issues Task Force reached a consensus to rescind EITF 98-10.  The effective date for the full rescissionis for fiscal periods beginning after December 15, 2002.  With the rescission of EITF No. 98-10,energy trading contracts that do not also meet the definition of a derivativeunder SFAS No. 133 must be accounted for as executory contracts.  Contracts previously recorded at fair valueunder EITF No. 98-10 that are not also derivatives under SFAS No. 133 must berestated to historical cost through a cumulative effect adjustment.  KU does not expect the rescission of thisstandard to have a material impact on financial position or results ofoperations.

 

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 from other parties.  FIN 46 iseffective immediately for all new variable interest entities created or acquiredafter January 31, 2003.  For variableinterest entities created or acquired prior to February 1, 2003, the provisionsof FIN 46 must be applied for the first interim or annual period beginningafter June 15, 2003.  KU 

 

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does not expect the adoption of this standard to have any impact on thefinancial position or results of operations.

 

LIQUIDITY AND CAPITAL RESOURCES

 

KU uses net cash generated from its operations and external financingto fund 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 $175.8million, $188.1 million and $176.3million in 2002, 2001 and 2000, respectively. The 2002 decrease from 2001 of $12.3 million was primarily the result ofa decrease in accrued taxes and changes in accounts receivable. The 2001increase resulted from sale of accounts receivable through a securitization program.  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 for investing activities continues to be forcapital expenditures.  Capital expenditureswere $237.9 million, $142.4 millionand $100.3 million in 2002, 2001 and 2000, respectively.  KU expects its capital expenditures for 2003and 2004 will total approximately $550.0 million, which consists primarily ofconstruction costs associated with installation of NOx equipment as describedin the section titled “Environmental Matters,” purchase of jointly owned CTswith LG&E and on going construction for the distribution system.

 

Net cash used for investment activities increased $99.0 million in 2002compared to 2001 and $38.6 million in 2001 compared to 2000 primarily due tothe level of construction expenditures. NOx expenditures increased $50.6 million and CT expenditures increased$27.0 million in 2002.

 

Financing Activities

 

Net cash inflows from financing activities were $64.2 million in 2002and outflows of $46.2 million and $82.4 million in 2001 and 2000,respectively.  In 2002, short-term debtincreased $72.0 million from 2001.  In2001, short-term debt decreased $13.4 million from 2000 and KU paid $32.8million in dividends.

 

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

 

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

 

Future Capital Requirements

 

Future capital requirements may be affected in varying degrees byfactors such as load growth, changes in construction expenditure levels, rateactions by regulatory agencies, new legislation, market entry of competing 

 

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electric power generators, changes in environmental regulations andother regulatory requirements.  KUanticipates funding future capital requirements through operating cash flow,debt, and/or infusion of capital from its parent.

 

KU’s debt ratings as of December 31, 2002, were:

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

 

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

 

Contractual Obligations

 

The following is provided to summarize KU’s contractual cashobligations for periods after December 31, 2002 (in thousands of $):

 
|                                    |   | **Payments  Due by Period** |    |
|-----------------------------------------|--------|-----------------------------|---------|
| **Contractual cash  Obligations**       |   | **2003**                    |    | **2004-  2005** |   | **2006-  2007** |   | **After  2007** |   | **Total** |   |
|                                    |   |                        |    |   |   |   |   |   |   |   |   |
| Short-term debt(a)                      |   | $                           | 119,490 |   | $ | — |   | $ | — |   | $ | — |   | $ | 119,490 |   |
| Long-term debt(b)                       |   | 153,930                     |    | — |   | 89,000 |   | 257,562 |   | 500,492 |   |
| Unconditional  purchase  obligations(c) |   | 34,317                      |    | 79,306 |   | 79,878 |   | 643,946 |   | 837,447 |   |
| Other long-term  obligations(d)         |   | 128,199                     |    | 201,249 |   | — |   | — |   | 329,448 |   |
| Total  contractual cash obligations(e)  |   | $                           | 435,936 |   | $ | 280,555 |   | $ | 168,878 |   | $ | 901,508 |   | $ | 1,786,877 |   |

 

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

(b)                                 Includeslong-term debt of $91.9 million is classified as a current liability becausethe bonds are subject to tender for purchase at the option of the holder and tomandatory tender for purchase upon the occurrence of certain events.  Maturity dates for the bonds range from 2024to 2032.

(c)                                  Representsfuture minimum payments under purchased power agreements through 2020.

(d)                                 Representsconstruction commitments.

(e)                                  KUdoes not expect to pay the $91.9 million of long-term debt classified as acurrent liability in the consolidated balance sheets in 2003 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 2003.

 

Market Risks

 

KU is exposed to market risks from changes in interest rates andcommodity prices.  To mitigate changes in

 

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cash flows attributable to these exposures, KU uses various financialinstruments including derivatives. Derivative positions are monitored using techniques that include marketvalue and sensitivity analysis. See Notes 1 and 4 of KU’s Notes to FinancialStatements under Item 8.

 

Interest Rate Sensitivity

 

KU has short-term and long-term variable rate debt obligationsoutstanding.  At December 31, 2002,the potential change in interest expense associated with a 1% change in baseinterest rates of KU’s variable rate debt is estimated at $5.2 million after impact of interest rateswaps.

 

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 of December 31, 2002, KU has swaps with a combined notionalvalue of $153 million.  The swaps exchange fixed-rate interestpayments for floating rate interest payments on KU’s Series P, R, and PCS-9Bonds.  The potential loss in fair valueresulting from a hypothetical 1% adverse movement in base interest rates isestimated at $6.9 million as ofDecember 31, 2002.  This estimateis derived from third party valuations. Changes in the market value of theseswaps if held to maturity, as KU intends to do, will have no effect on KU’s netincome or cash flow.  See Note 4 of KU’sNotes to Financial Statements under Item 8.

 

Commodity Price Sensitivity

 

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

 

# **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 *EITF 98-10 Accounting for Contracts Involved inEnergy Trading and Risk Management Activities*, *SFAS No. 133 Accounting for DerivativeInstruments and Hedging Activities,* and *SFAS No. 138 Accounting for CertainDerivative Instruments and Certain Hedging Activities*.  Wholesale sales of excess asset capacity andwholesale purchases are treated as normal sales and purchases under *SFAS No. 133*and *SFASNo. 138* and are not marked-to-market.

 

The rescission of *EITF 98-10*, effective for fiscal years ending after December 15, 2002, will haveno impact on KU’s energy trading and risk management reporting as all contractsmarked to market under *EITF 98-10* are also within the scope of *SFAS No. 133*.

 

The table below summarizesKU’s energy trading and risk management activities for 2002 and 2001(inthousands of $).

##  

|                                                          |   | **2002** |   | **2001** |   |
|---------------------------------------------------------------|--------|----------|--------|----------|--------|
| Fair value of contracts at beginning of period, net liability |   | $        | (186   | )        | $      | (17 | ) |
| Fair value of contracts when entered into during the period   |   | (65      | )      | 3,441    |   |
| Contracts realized or otherwise settled during the period     |   | 448      |   | (2,894   | )      |
| Changes in fair values due to changes in assumptions          |   | (353     | )      | (716     | )      |
| Fair value of contracts at end of period, net liability       |   | $        | (156   | )        | $      | (186 | ) |

 

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No changes to valuation techniques for energy tradingand risk management activities occurred during 2002.  Changes in market pricing, interest rate and volatilityassumptions were made during both years. All contracts outstanding at December31, 2002 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, 2002, 86% of the trading andrisk management commitments were with counterparties rated BBB- equivalent orbetter.

 

Accounts Receivable Securitization

 

On February 6, 2001, KU implemented an accounts receivablesecuritization program.  The purpose ofthis program is to enable KU to accelerate the receipt of cash from thecollection of retail accounts receivable, thereby reducing dependence upon morecostly sources of working capital. The securitization program allows for apercentage of eligible receivables to be sold. Eligible receivables are generally all receivables associated withretail sales that have standard terms and are not past due.  KU is able to terminate this program at anytime without penalty. If there is a significant deterioration in the paymentrecord of the receivables by the retail customers or if KU fails to meetcertain covenants regarding the program, the program may terminate at theelection 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.

 

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 Rcan sell, on a revolving basis, an undivided interest in certain of theirreceivables and receive up to $50 million from an unrelated third partypurchaser.  The effective cost of thereceivables programs is comparable to KU’s lowest cost source of capital, andis based on prime rated commercial paper. KU retains servicing rights of the sold receivables through two separateservicing agreements with the third party purchaser.  KU has obtained an opinion from independent legal counselindicating these transactions qualify as a true sale of receivables.  As of December 31, 2002, the outstandingprogram balance was $49.3 million.  KU is considering unwinding the accountsreceivable securitization arrangements involving KU R during 2003.

 

The allowance for doubtful accounts associated with the eligiblesecuritized receivables was $520,000 atDecember 31, 2002.  This allowance isbased on historical experience of KU. Each securitization facility contains afully funded reserve for uncollectible receivables.

 

RATES AND REGULATION

 

Following the purchase ofPowergen by E.ON, E.ON became a registered holding company under PUHCA.  As a result, E.ON, its utility subsidiaries,including KU, and certain of its non-utility subsidiaries are subject toextensive regulation by the SEC under PUHCA with respect to issuances and salesof securities, acquisitions and sales of certain utility properties, andintra-system sales of certain goods and services.  In addition, PUHCA generally limits the ability of registeredholding companies to acquire additional public utility systems and to acquireand retain businesses unrelated to the utility operations of the holdingcompany.  KU believes that it has 

 

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adequate authority(including financing authority) under existing SEC orders and regulations toconduct its business.  KU will seekadditional authorization when necessary.

 

KU is subject to the jurisdiction of the Kentucky Commission, theVirginia Commission and FERC in virtually all matters related to electricutility regulation, and as such, its accounting is subject to SFAS No. 71, *Accountingfor the Effects of Certain Types of Regulation*.  Given KU’s competitive position in themarket and the status of regulation in the states of Kentucky and Virginia, KUhas no plans or intentions to discontinue its application of SFAS No. 71.  See Note 3 of KU’s Notes to FinancialStatements under Item 8.

 

Kentucky Commission Settlement Order - VDT Costs, ESMand Depreciation

 

During the first quarter 2001, KU recorded a $64 million charge for aworkforce reduction program.  Primarycomponents of the charge were separation benefits, enhanced early retirementbenefits, and health care benefits. The result of this workforce reduction wasthe elimination of approximately 300 positions, accomplished primarily througha voluntary enhanced severance program.

 

On June 1, 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 the new depreciation study and resulting depreciation ratesimplemented in 2001.

 

KU reached a settlement in the VDT case as well as the other casesinvolving depreciation rates and ESM with all intervening parties.  The settlement agreement was approved by theKentucky Commission on December 3, 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 $64 millionrepresented all employees who had accepted a voluntary enhanced severanceprogram.  Some employees rescinded theirparticipation in the voluntary enhanced severance program and, along with thenon-recurring charge of $6.9 million for FERC and Virginia jurisdictions,thereby decreasing the original charge of the regulatory asset from $64 millionto $54 million. The settlement will also reduce revenues approximately $11million through a surcredit on future bills to customers over the same fiveyear period.  The surcredit representsstipulated net savings KU is expected to realize from implementation of bestpractices through the VDT. The agreement also established KU’s new depreciationrates in effect December 2001, retroactive to January 1, 2001.  The new depreciation rates decreaseddepreciation expense by $6.0 million in 2001.

 

Environmental Cost Recovery

 

In June 2000, the Kentucky Commission approved KU’s application for aCCN to construct up to four 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 May 2004.  In its order, the Kentucky Commission ruledthat KU’s proposed plan for construction was “reasonable, cost-effective andwill not result in the wasteful duplication of facilities”.  In October 2000, KU filed an applicationwith the Kentucky Commission to amend its Environmental Compliance Plan toreflect the addition of the proposed NOx reduction technology projects and toamend its Environmental Cost Recovery Tariff to include an overall rate ofreturn on capital investments. Approval of KU’s application in April 2001,allowed KU to begin to recover the costs associated with these new projects,subject to Kentucky Commission oversight during normal six-month and two-yearreviews.

 

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In August 2002, KU filed an application with the Kentucky Commission toamend its compliance plan to allow recovery of the cost of a new and additionalenvironmental compliance facility.  Theestimated capital cost of the additional facilities is $17.3 million.  The Kentucky Commission conducted a publichearing on the case on December 20, 2002, final briefs were filed on January15, 2003, and a final order was issued February 11, 2003.  The final order approved recovery of the newenvironmental compliance facility totaling $17.3 million.  Cost recovery through the environmentalsurcharge of the approved project will begin with bills rendered in April 2003.

 

ESM

 

KU’s electric rates are subject toan ESM.  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 successiveperiods.  KU made its second ESMfiling on March 1, 2002 for the calendar year 2001 reporting period.  KU is in the process of refunding $1 millionto customers for the 2001 reporting period. KU estimated that the rate of returnwill fall below the lower limit, subject to Kentucky Commission approval, forthe year ended December 31, 2002. The 2002 financial statements include anaccrual to reflect the earnings deficiency of $13.5 million to be recoveredfrom customers commencing in April 2003.

 

On November 27, 2002, KU filed a revised ESM tariff which proposedcontinuance of the existing ESM through December 2005.  The Kentucky Commission issued an Ordersuspending the ESM tariff one day making the effective date January 2,2003.  In addition, the KentuckyCommission is conducting a management audit to review the ESM plan and reassessits reasonableness in 2003.  KU and interestedparties will have the opportunity to provide recommendations for modificationand continuance of the ESM or other forms of alternative or incentiveregulation.

 

DSM

 

In May 2001, the Kentucky Commission approved a plan that would expandLG&E’s current DSM programs into the service territory served by KU.  The filing included a rate mechanism thatprovided for concurrent recovery of DSM costs, provided an incentive forimplementing DSM programs, and recovered revenues from lost sales associatedwith the DSM program based on program planning engineering estimates andpost-implementation evaluations.

 

FAC

 

KU employs an FAC mechanism, which allows KU to recover from customersthe actual 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 on May 17, 2002.  Thereunder, KU agreed to credit 

 

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its fuel clause in the amount of $954,000 (refundmade in June and July 2002), and the parties agreed on a prospectiveinterpretation of the state’s fuel adjustment clause regulation to ensureconsistent and mutually acceptable application on a going-forward basis.

 

In December 2002, the Kentucky Commission initiated a two year reviewof the operation of KU’s fuel adjustment clause for the period November 2000through October 2002.  Testimony in thereview case was filed on January 20, 2003 and a public hearing was heldFebruary 18, 2003.  Issues addressed atthat time included the establishment of the current base fuel factor to beincluded in KU’s base rates, verification of proper treatment of purchasedpower costs during unit outages, and compliance with fuel procurement policiesand practices.

 

In January 2003, the Kentucky Commission reviewedthe FAC of KU for the six month period ended October 31, 2001. The KentuckyCommission ordered KU to reduce its fuel costs for purposes of calculating itsFAC by $673,000. At issue was the purchase of approximately 102,000 tons ofcoal from Western Kentucky Energy Corporation, a non-regulated affiliate, foruse at KU’s Ghent Facility. The Kentucky Commission further ordered that anindependent audit be conducted to examine operational and management aspects ofKU’s fuel procurement functions.

 

Kentucky Commission Administrative Case forAffiliate Transactions

 

In December 1997, the Kentucky Commission opened Administrative CaseNo. 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.  During theperiod September 1998 to February 2000, the Kentucky Commission issued draftcodes of conduct and cost allocation guidelines.  In early 2000, the Kentucky General Assembly enacted legislation,House Bill 897, which authorized the Kentucky Commission to require utilitiesthat provide nonregulated activities to keep separate accounts and allocatecosts in accordance with procedures established by the Kentucky Commission. Inthe same bill, 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.  On February 14, 2001, the KentuckyCommission published notice of their intent to promulgate new administrativeregulation under the auspices of the new law. This effort is still on going.

 

Kentucky Commission Administrative Case forSystem Adequacy

 

On June 19, 2001, Kentucky Governor Paul E. Patton issued ExecutiveOrder 2001-771, which directed the Kentucky Commission to review and studyissues relating to the need for and development of new electric generatingcapacity in Kentucky.  The issues to beconsidered included the impact of new power plants on the electric supply grid,facility siting issues, and economic development matters, with the goal ofensuring a continued, reliable source of supply of electricity for the citizensof Kentucky and the continued environmental and economic vitality of Kentuckyand its communities.  In response tothat Executive Order, in July 2001 the Kentucky Commission openedAdministrative Case No. 387 to review the adequacy of Kentucky’s generation 

 

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capacity and transmission system. Specifically, the items reviewed were the appropriate level of relianceon purchased power, the appropriate reserve margins to meet existing and futureelectric demand, the impact of spikes in natural gas prices on electric utilityplanning strategies, and the adequacy of Kentucky’s electric transmissionfacilities.  KU, as a party to thisproceeding, filed written testimony and responded to two requests forinformation.  Public hearings were heldand in October 2001, KU filed a final brief in the case.  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 transmission system, the Kentucky Commission concludedthat the transmission system within Kentucky can reliably serve native load anda significant portion of the proposed new unregulated power plants.  However, it will not be able to handle thevolume of transactions envisioned by FERC without future upgrades, the costs ofwhich should be borne by those for whom the upgrades are required.

 

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

 

FERC SMD NOPR

 

On July 31, 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 eachpublic utility that owns, operates, or controls interstate transmissionfacilities to become an Independent Transmission Provider (ITP), belong to anRTO that is an ITP, or contract with an ITP for operation of its transmissionassets. It would also establish a standardized congestion management system,real-time and day-ahead energy markets, and a single transmission service fornetwork and point-to-point transmission customers. Review of the proposedrulemaking is underway and a final rule is expected during 2003.  While it is expected that the SMD final rulewill affect KU revenues and expenses, the specific impact of the rulemaking isnot known at this time.

 

MISO

 

KU is a member of the MISO, which began commercial operations onFebruary 1, 2002.  MISO now hasoperational control over KU’s high-voltage transmission facilities (100 kV andgreater), while KU continues to control and operate the lower voltagetransmission subject to the terms and conditions of the MISO OATT.  As a transmission-owning member of MISO, KUalso incurs administrative costs of MISO pursuant to Schedule 10 of the MISOOATT.

 

MISO also proposedto implement a congestion management system. FERC directed the MISO to coordinate its efforts with FERC’s Rulemakingon SMD. OnSeptember 24, 2002, the MISO filed new rate schedules designated as Schedules16 and 17, which provide for the collection of costs incurred by the MISO toestablish day-ahead and real-time energy markets. The MISO proposed to recoverthese costs under Schedules 16 and 17 once service commences. If approved byFERC, these schedules will cause KU to incur additional costs.  KU opposes the establishment of Schedules 16and 17.  This effort is still on-goingand the ultimate impact of the two schedules, if approved, is not known at thistime.

 

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Merger Surcredit

 

As part of the LG&E Energy merger with KU Energy in 1998, LG&EEnergy 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 achievedfrom the merger be provided to ratepayers through a monthly bill credit, and50% be retained by the Companies, over a five-year period.  The surcredit was allocated 53% to KU and47% to LG&E.  In that same order,the Commission required LG&E and KU, after the end of the five-year period,to present a plan for sharing with customers the then-projected non-fuelsavings associated with the merger.  TheCompanies submitted this filing on January 13, 2003, proposing to continue toshare with customers, on a 50%/50% basis, the estimated fifth-year gross levelof non-fuel savings associated with the merger.  The filing is currently under review.

 

Any fuel cost savings are passed to Kentucky customers through the fueladjustment clause.  See FAC above.

 

Environmental Matters

 

The Clean Air Act imposed stringent new SO2 and NOx emission limits onelectric generating units.  KU met itsPhase I SO2 requirements primarily through installation of a scrubber on GhentUnit 1.  KU’s strategy for Phase II SO2reductions, which commenced January 1, 2000, is to use accumulated emissionsallowances to delay additional capital expenditures and may also include fuelswitching or the installation of additional scrubbers.  KU met the NOx emission requirements of theAct through installation of low-NOx burner systems. KU’s compliance plans aresubject to many factors including developments in the emission allowance andfuel markets, future regulatory and legislative initiatives, and advances inclean air control technology.  KU willcontinue to monitor these developments to ensure that its environmentalobligations are met in the most efficient and cost-effective manner.

 

In September 1998, the EPA announced its final “NOx SIP Call” rulerequiring states to impose significant additional reductions in NOx emissionsby May 2003, in order to mitigate alleged ozone transport impacts on theNortheast region.  The Commonwealth ofKentucky is currently in the process of revising its SIP to require 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 the Clean AirAct directing similar NOx reductions from a number of specifically targetedgenerating units including 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 a plan for adding significant additionalNOx controls to its generating units. Installation of additional NOx controls will proceed on a phased basis,with installation of controls commencing in late 2000 and continuing throughthe final compliance date.  KU estimatesthat it will incur total capital costs 

 

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of approximately $232 million to reduce its NOx emissions to the 0.15lb./Mmbtu level on a company-wide basis. In addition, KU will incur additional operating and maintenance costs inoperating new NOx controls.  KU believesits costs in this regard to be comparable to those of similarly situatedutilities with like generation assets. KU had anticipated that such capital and operating costs are the type ofcosts that are eligible for recovery from customers under its environmentalsurcharge mechanism and believed that a significant portion of such costs couldbe recovered.  In April 2001, theKentucky Commission granted recovery of these costs for KU.

 

KU is also monitoring several other air quality issues which maypotentially impact coal-fired power plants, including the appeal of the D.C.Circuit’s remand of the EPA’s revised air quality standards for ozone andparticulate matter, measures to implement EPA’s regional haze rule, and EPA’sDecember 2000 determination to regulate mercury emissions from power plants.

 

KU owns or formerly owned several properties that contained past MGPoperations.  Various contaminants aretypically found at such former MGP sites and environmental remediation measuresare frequently required.  KU hascompleted the cleanup of a site owned by KU. With respect to other former MGP sites no longer owned by KU, KU isunaware of what, if any, additional exposure or liability it may have.

 

In October 1999, approximately 38,000 gallons of diesel fuel leakedfrom a cracked valve in an underground pipeline at KU’s E.W. BrownStation.  Under the oversight of EPA andstate officials, KU commenced immediate spill containment and recovery measureswhich prevented the spill from reaching the Kentucky River.  KU ultimately recovered approximately 34,000gallons of diesel fuel.  In November1999, the Kentucky Division of Water issued a notice of violation for theincident.  KU is currently negotiatingwith the state in an effort to reach a complete resolution of this matter.  KU incurred costs of approximately $1.8million and received insurance reimbursement of $1.2 million.  In December 2002, the Department of Justice(DOJ) sent correspondence to KU regarding a potential per-day fine for failureto timely submit a spill control plan and a per-gallon fine for the amount ofoil discharged.  KU and the DOJ havecommenced settlement discussions using existing DOJ settlement guidelines onthis matter.

 

In April 2002, the EPA sent correspondence to KU regarding potentialexposure in connection with $1.5 million in completed remediation costsassociated with a transformer scrap-yard. KU believes it is one of the more remote among a number of potentiallyresponsible parties and has entered into settlement discussions with the EPA onthis matter.

 

See Note 11 of KU’sNotes to Financial Statements under Item 8 for an additional discussion ofenvironmental issues.

 

Deferred Income Taxes

 

KU expects to have adequate levels of taxable income to realize itsrecorded deferred tax assets.  AtDecember 31, 2002, deferred tax assets totaled $61 million  and were principally related to expensesattributable to KU’s pension plans and post retirement benefit obligations.

 

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FUTURE OUTLOOK

 

Competition and Customer Choice

 

KU has moved aggressively over the past decade to be positioned for theenergy industry’s shift to customer choice and a competitive market for energyservices.  Specifically, KU has takenmany steps to prepare for the expected increase in competition in its business,including support for PBR structures, aggressive cost reduction activities;strategic acquisitions, dispositions and growth initiatives; write-offs ofpreviously deferred expenses; an increase in focus on commercial and industrialcustomers; an increase in employee training; and necessary corporate andbusiness unit realignments.

 

In December 1997, the Kentucky Commission issued a set of principleswhich was intended to serve as its guide in consideration of issues relating toindustry restructuring.  Among theissues addressed by these principles are: consumer protection and benefit,system reliability, universal service, environmental responsibility, costallocation, stranded costs and codes of conduct.  During 1998, the Kentucky Commission and a task force of theKentucky General Assembly each initiated proceedings, including meetings withrepresentatives of utilities, consumers, state agencies and other groups inKentucky, to discuss the possible structure and effects of energy industryrestructuring in Kentucky.

 

In November 1999, the task force issued a report to the Governor ofKentucky and a legislative agency recommending no general electric industryrestructuring actions during the 2000 legislative session.  No general industry restructuring actionshave been taken to date by the legislature.

 

Thus, at the time of this report, neither the Kentucky General Assemblynor the Kentucky Commission has adopted or approved a plan or timetable forretail electric industry competition in Kentucky.  The nature or timing of the ultimate legislative or regulatoryactions regarding industry restructuring and their impact on KU, which may besignificant, cannot currently be predicted.

 

While many states have moved forward in providingretail choice, many others have not. Some are reconsidering their initiatives and have even delayedimplementation.

 

Virginia has enacted a phase-in of customerchoice through the Virginia Electric Restructuring Act.  The Virginia Commission is promulgatingregulations to govern the various activities required by the Act.  KU filed unbundled rates that becameeffective January 1, 2002.  KU was granted a waiver from the VirginiaCommission on October 29, 2002, exempting KU from retail choice throughDecember 31, 2004.  KU is also seeking apermanent legislative exemption to the Virginia Electric RestructuringAct.  The outcome of such legislativeinitiatives will not be known until mid-2003.

 

ITEM 7A.  Quantitative and Qualitative DisclosureAbout Market Risk.

 

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

 

 

ITEM 8. Financial Statements andSupplementary Data.

 

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INDEX OF ABBREVIATIONS

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

 

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

 

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Louisville Gas andElectric Company and SubsidiaryConsolidated Statements of Income(Thousands of $)

 
|                                               |   | **Years  Ended December 31** |    |
|----------------------------------------------------|--------|------------------------------|---------|
|                                               |   | **2002**                     |    | **2001** |   | **2000** |   |
| OPERATING  REVENUES:                               |   |                         |    |   |   |   |   |
| Electric                                           |   | $                            | 746,224 |   | $ | 706,645 |   | $ | 713,458 |   |
|                                               |   |                         |    |   |   |   |   |
| Gas                                                |   | 267,693                      |    | 290,775 |   | 272,489 |   |
|                                               |   |                         |    |   |   |   |   |
| Provision for  rate collections (refunds) (Note 3) |   | 12,267                       |    | (720 | ) | (2,500 | ) |
| Total operating  revenues (Note 1)                 |   | 1,026,184                    |    | 996,700 |   | 983,447 |   |
|                                               |   |                         |    |   |   |   |   |
| OPERATING  EXPENSES:                               |   |                         |    |   |   |   |   |
| Fuel for  electric generation                      |   | 194,900                      |    | 159,231 |   | 159,418 |   |
| Power purchased                                    |   | 84,330                       |    | 81,475 |   | 96,894 |   |
| Gas supply  expenses                               |   | 182,108                      |    | 206,165 |   | 196,912 |   |
| Other operation  expenses                          |   | 208,322                      |    | 167,818 |   | 135,943 |   |
| Maintenance                                        |   | 60,210                       |    | 58,687 |   | 63,709 |   |
| Depreciation and  amortization (Note 1)            |   | 105,906                      |    | 100,356 |   | 98,291 |   |
| Federal and  state income taxes (Note 7)           |   | 55,035                       |    | 63,452 |   | 64,425 |   |
| Property and  other taxes                          |   | 17,459                       |    | 17,743 |   | 18,985 |   |
| Total operating  expenses                          |   | 908,270                      |    | 854,927 |   | 834,577 |   |
|                                               |   |                         |    |   |   |   |   |
| Net operating  income                              |   | 117,914                      |    | 141,773 |   | 148,870 |   |
|                                               |   |                         |    |   |   |   |   |
| Other income -  net (Note 8)                       |   | 820                          |    | 2,930 |   | 4,921 |   |
| Interest charges                                   |   | 29,805                       |    | 37,922 |   | 43,218 |   |
|                                               |   |                         |    |   |   |   |   |
| Net income                                         |   | 88,929                       |    | 106,781 |   | 110,573 |   |
|                                               |   |                         |    |   |   |   |   |
| Preferred stock  dividends                         |   | 4,246                        |    | 4,739 |   | 5,210 |   |
|                                               |   |                         |    |   |   |   |   |
| Net income  available for common stock             |   | $                            | 84,683  |   | $ | 102,042 |   | $ | 105,363 |   |

 

Consolidated Statementsof Retained Earnings

(Thousands of $)

 
|                                                  |   | **Years  Ended December 31** |    |
|-------------------------------------------------------|--------|------------------------------|---------|
|                                                  |   | **2002**                     |    | **2001** |   | **2000** |   |
|                                                  |   |                         |    |   |   |   |   |
| Balance January  1                                    |   | $                            | 393,636 |   | $ | 314,594 |   | $ | 259,231 |   |
| Add net income                                        |   | 88,929                       |    | 106,781 |   | 110,573 |   |
|                                                  |   | 482,565                      |    | 421,375 |   | 369,804 |   |
|                                                  |   |                         |    |   |   |   |   |
| Deduct:  Cash  dividends declared on stock: |   |                         |    |   |   |   |   |
| 5% cumulative  preferred                              |   | 1,075                        |    | 1,075 |   | 1,075 |   |
| Auction rate  cumulative preferred                    |   | 1,702                        |    | 2,195 |   | 2,666 |   |
| $5.875  cumulative preferred                          |   | 1,469                        |    | 1,469 |   | 1,469 |   |
| Common                                                |   | 69,000                       |    | 23,000 |   | 50,000 |   |
|                                                  |   | 73,246                       |    | 27,739 |   | 55,210 |   |
|                                                  |   |                         |    |   |   |   |   |
| Balance December  31                                  |   | $                            | 409,319 |   | $ | 393,636 |   | $ | 314,594 |   |

 

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

 

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Louisville Gas andElectric Company and SubsidiaryConsolidated Statements of Comprehensive Income(Thousands of $)

 
|                                                                                                                      |   | **Years  Ended December 31** |   |
|---------------------------------------------------------------------------------------------------------------------------|--------|------------------------------|--------|
|                                                                                                                      |   | **2002**                     |   | **2001** |   | **2000** |   |
|                                                                                                                      |   |                         |   |   |   |   |   |
| Net income                                                                                                                |   | $                            | 88,929 |   | $ | 106,781 |   | $ | 110,573 |   |
|                                                                                                                      |   |                         |   |   |   |   |   |
| Cumulative  effect of change in accounting principle – Accounting for derivative  instruments and hedging activities |   | —                       |   | (5,998 | ) | — |   |
|                                                                                                                      |   |                         |   |   |   |   |   |
| Losses on  derivative instruments and hedging activities (Note 1)                                                         |   | (8,511                       | )      | (2,606 | ) | — |   |
|                                                                                                                      |   |                         |   |   |   |   |   |
| Additional  minimum pension liability adjustment (Note 6)                                                                 |   | (25,999                      | )      | (24,712 | ) | — |   |
|                                                                                                                      |   |                         |   |   |   |   |   |
| Income tax  benefit related to items of other comprehensive income                                                        |   | 13,898                       |   | 13,416 |   | — |   |
|                                                                                                                      |   |                         |   |   |   |   |   |
| Other  comprehensive loss, net of tax                                                                                     |   | (20,612                      | )      | (19,900 | ) | — |   |
|                                                                                                                      |   |                         |   |   |   |   |   |
| Comprehensive  income                                                                                                     |   | $                            | 68,317 |   | $ | 86,881 |   | $ | 110,573 |   |

 

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

 

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Louisville Gas andElectric Company and SubsidiaryConsolidated Balance Sheets(Thousands of $)

 
|                                                                        |   | **December  31** |      |
|-----------------------------------------------------------------------------|--------|------------------|-----------|
|                                                                        |   | **2002**         |      | **2001** |   |
| ASSETS:                                                                     |   |             |      |   |   |
| Utility plant,  at original cost (Note 1):                                  |   |             |      |   |   |
| Electric                                                                    |   | $                | 2,717,187 |   | $ | 2,598,152 |   |
| Gas                                                                         |   | 435,235          |      | 409,994 |   |
| Common                                                                      |   | 169,577          |      | 159,817 |   |
|                                                                        |   | 3,321,999        |      | 3,167,963 |   |
| Less:  reserve for depreciation                                        |   | 1,463,674        |      | 1,381,874 |   |
|                                                                        |   | 1,858,325        |      | 1,786,089 |   |
| Construction  work in progress                                              |   | 300,986          |      | 255,074 |   |
|                                                                        |   | 2,159,311        |      | 2,041,163 |   |
|                                                                        |   |             |      |   |   |
| Other property  and investments – less reserve of $63 in 2002 and 2001 |   | 764              |      | 1,176 |   |
|                                                                        |   |             |      |   |   |
| Current assets:                                                             |   |             |      |   |   |
| Cash                                                                        |   | 17,015           |      | 2,112 |   |
| Accounts  receivable - less reserve of $2,125 in 2002 and $1,575 in 2001    |   | 68,440           |      | 85,667 |   |
| Materials and  supplies - at average cost:                                  |   |             |      |   |   |
| Fuel  (predominantly coal) (Note 1)                                         |   | 36,600           |      | 22,024 |   |
| Gas stored  underground (Note 1)                                            |   | 50,266           |      | 46,395 |   |
| Other                                                                       |   | 25,651           |      | 29,050 |   |
| Prepayments and  other                                                      |   | 5,298            |      | 4,688 |   |
|                                                                        |   | 203,270          |      | 189,936 |   |
|                                                                        |   |             |      |   |   |
| Deferred debits  and other assets:                                          |   |             |      |   |   |
| Unamortized debt  expense (Note 1)                                          |   | 6,532            |      | 5,921 |   |
| Regulatory  assets (Note 3)                                                 |   | 153,446          |      | 197,142 |   |
| Other                                                                       |   | 37,755           |      | 13,016 |   |
|                                                                        |   | 197,733          |      | 216,079 |   |
|                                                                        |   | $                | 2,561,078 |   | $ | 2,448,354 |   |
|                                                                        |   |             |      |   |   |
| CAPITAL AND  LIABILITIES:                                                   |   |             |      |   |   |
| Capitalization  (see statements of capitalization):                         |   |             |      |   |   |
| Common equity                                                               |   | $                | 833,141   |   | $ | 838,070 |   |
| Cumulative  preferred stock                                                 |   | 95,140           |      | 95,140 |   |
| Long-term debt  (Note 9)                                                    |   | 328,104          |      | 370,704 |   |
|                                                                        |   | 1,256,385        |      | 1,303,914 |   |
| Current  liabilities:                                                       |   |             |      |   |   |
| Current portion  of long-term debt (Note 9)                                 |   | 288,800          |      | 246,200 |   |
| Notes payable  (Note 10)                                                    |   | 193,053          |      | 94,197 |   |
| Accounts payable                                                            |   | 122,771          |      | 149,070 |   |
| Accrued taxes                                                               |   | 1,450            |      | 20,257 |   |
| Other                                                                       |   | 19,536           |      | 18,658 |   |
|                                                                        |   | 625,610          |      | 528,382 |   |
|                                                                        |   |             |      |   |   |
| Deferred credits  and other liabilities:                                    |   |             |      |   |   |
| Accumulated  deferred income taxes (Notes 1 and 7)                          |   | 313,225          |      | 298,143 |   |
| Investment tax  credit, in process of amortization                          |   | 54,536           |      | 58,689 |   |
| Accumulated  provision for pensions and related benefits (Note 6)           |   | 224,703          |      | 167,526 |   |
| Regulatory  liabilities (Note 3)                                            |   | 52,424           |      | 65,349 |   |
| Other                                                                       |   | 34,195           |      | 26,351 |   |
|                                                                        |   | 679,083          |      | 616,058 |   |
| Commitments and  contingencies (Note 11)                                    |   |             |      |   |   |
| .                                                                           |   | $                | 2,561,078 |   | $ | 2,448,354 |   |

 

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

 

72

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Louisville Gas andElectric Company and Subsidiary

Consolidated Statementsof Cash Flows

(Thousands of $)

 
|                                                            |   | **Years  Ended December 31** |   |
|-----------------------------------------------------------------|--------|------------------------------|--------|
|                                                            |   | **2002**                     |   | **2001** |   | **2000** |   |
|                                                            |   |                         |   |   |   |   |   |
| CASH FLOWS FROM  OPERATING ACTIVITIES:                          |   |                         |   |   |   |   |   |
| Net income                                                      |   | $                            | 88,929 |   | $ | 106,781 |   | $ | 110,573 |   |
| Items not  requiring cash currently:                            |   |                         |   |   |   |   |   |
| Depreciation and  amortization                                  |   | 105,906                      |   | 100,356 |   | 98,291 |   |
| Deferred income  taxes - net                                    |   | 11,915                       |   | 3,021 |   | 31,020 |   |
| Investment tax  credit - net                                    |   | (4,153                       | )      | (4,290 | ) | (4,274 | ) |
| Other                                                           |   | 37,260                       |   | (528 | ) | 8,481 |   |
|                                                            |   |                         |   |   |   |   |   |
| Change in  certain net current assets:                          |   |                         |   |   |   |   |   |
| Accounts  receivable                                            |   | (3,973                       | )      | 43,185 |   | (56,993 | ) |
| Materials and  supplies                                         |   | (15,048                      | )      | (2,018 | ) | (4,311 | ) |
| Accounts payable                                                |   | (26,299                      | )      | 14,678 |   | 21,384 |   |
| Accrued taxes                                                   |   | (18,807                      | )      | 12,184 |   | (15,686 | ) |
| Prepayments and  other                                          |   | 321                          |   | (10,500 | ) | (7,816 | ) |
| Sale of accounts  receivable (Note 1)                           |   | 21,200                       |   | 42,000 |   | — |   |
| Other                                                           |   | 15,130                       |   | (17,806 | ) | (24,431 | ) |
|                                                            |   |                         |   |   |   |   |   |
| Net cash flows  from operating activities                       |   | 212,381                      |   | 287,063 |   | 156,238 |   |
|                                                            |   |                         |   |   |   |   |   |
| CASH FLOWS FROM  INVESTING ACTIVITIES:                          |   |                         |   |   |   |   |   |
| Purchases of  securities                                        |   | —                       |   | — |   | (708 | ) |
| Proceeds from  sales of securities                              |   | 412                          |   | 4,237 |   | 4,089 |   |
| Construction  expenditures                                      |   | (220,416                     | )      | (252,958 | ) | (144,216 | ) |
| Net cash flows  from investing activities                       |   | (220,004                     | )      | (248,721 | ) | (140,835 | ) |
|                                                            |   |                         |   |   |   |   |   |
| CASH FLOWS FROM  FINANCING ACTIVITIES:                          |   |                         |   |   |   |   |   |
| Short-term  borrowings and repayments                           |   | 98,856                       |   | (20,392 | ) | (5,508 | ) |
| Issuance of  pollution control bonds                            |   | 158,635                      |   | 9,662 |   | 106,545 |   |
| Retirement of  first mortgage bonds and pollution control bonds |   | (161,665                     | )      | — |   | (130,627 | ) |
| Additional  paid-in capital                                     |   | —                       |   | — |   | 40,000 |   |
| Payment of  dividends                                           |   | (73,300                      | )      | (27,995 | ) | (78,079 | ) |
| Net cash flows  from financing activities                       |   | 22,526                       |   | (38,725 | ) | (67,669 | ) |
|                                                            |   |                         |   |   |   |   |   |
| Change in cash  and temporary cash investments                  |   | 14,903                       |   | (383 | ) | (52,266 | ) |
|                                                            |   |                         |   |   |   |   |   |
| Cash and  temporary cash investments at beginning of year       |   | 2,112                        |   | 2,495 |   | 54,761 |   |
|                                                            |   |                         |   |   |   |   |   |
| Cash and  temporary cash investments at end of year             |   | $                            | 17,015 |   | $ | 2,112 |   | $ | 2,495 |   |
|                                                            |   |                         |   |   |   |   |   |
| Supplemental  disclosures of cash flow information:             |   |                         |   |   |   |   |   |
| Cash paid during  the year for:                                 |   |                         |   |   |   |   |   |
| Income taxes                                                    |   | $                            | 51,540 |   | $ | 35,546 |   | $ | 46,562 |   |
| Interest on  borrowed money                                     |   | 25,673                       |   | 30,989 |   | 42,958 |   |

 

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

 

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Louisville Gas andElectric Company and SubsidiaryConsolidated Statements of Capitalization(Thousands of $)

 
|                                                                                            |   | **December  31** |    |
|-------------------------------------------------------------------------------------------------|--------|------------------|---------|
|                                                                                            |   | **2002**         |    | **2001** |   |
|                                                                                            |   |             |    |   |   |
| 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                                                         |   | (40,512          | )       | (19,900 | ) |
| Retained  earnings                                                                              |   | 409,319          |    | 393,636 |   |
|                                                                                            |   |             |    |   |   |
|                                                                                            |   | 833,141          |    | 838,070 |   |
|                                                                                                 |        |                  |         |  |  |  |  |

 

CUMULATIVE PREFERRED STOCK:

Redeemable on 30 days noticeby LG&E

 
|                                                                            |   | **Shares  Outstanding** |   | **Current  Redemption Price** |   |    |      |    |   |
|---------------------------------------------------------------------------------|--------|-------------------------|--------|-------------------------------|--------|---------|-----------|---------|--------|
|                                                                            |   |                    |   |                          |   |    |      |    |   |
| $25 par value,  1,720,000 shares authorized -  5% series                        |   | 860,287                 |   | $                             | 28.00  |    | 21,507    |    | 21,507 |   |
| Without par  value, 6,750,000 shares authorized -  Auction rate                 |   | 500,000                 |   | 100.00                        |   | 50,000  |      | 50,000  |   |
| $5.875 series                                                                   |   | 250,000                 |   | 101.18                        |   | 25,000  |      | 25,000  |   |
| Preferred stock  expense                                                        |   |                    |   |                          |   | (1,367  | )         | (1,367  | )      |
|                                                                            |   |                    |   |                          |   |    |      |    |   |
|                                                                            |   |                    |   |                          |   | 95,140  |      | 95,140  |   |
|                                                                            |   |                    |   |                          |   |    |      |    |   |
| LONG-TERM DEBT  (Note 9):                                                       |   |                    |   |                          |   |    |      |    |   |
| First mortgage  bonds -  Series due August 15, 2003, 6%                         |   |                    |   |                          |   | 42,600  |      | 42,600  |   |
| Pollution  control series:                                                      |   |                    |   |                          |   |    |      |    |   |
| R due November  1, 2020, 6.55%                                                  |   |                    |   |                          |   | —  |      | 41,665  |   |
| 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 |      | 102,000 |   |
| W due October  15, 2020, 5.45%                                                  |   |                    |   |                          |   | 26,000  |      | 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  |      | —  |   |
| CC due September  1, 2026, variable%                                            |   |                    |   |                          |   | 27,500  |      | —  |   |
| DD due November  1, 2027, variable%                                             |   |                    |   |                          |   | 35,000  |      | —  |   |
| EE due November  1, 2027, variable%                                             |   |                    |   |                          |   | 35,000  |      | —  |   |
| FF due October  1, 2032, variable%                                              |   |                    |   |                          |   | 41,665  |      | —  |   |
| Total first  mortgage bonds                                                     |   |                    |   |                          |   | 616,904 |      | 496,904 |   |
| Pollution  control bonds (unsecured) -  Series due September 1, 2026, variable% |   |                    |   |                          |   | —  |      | 22,500  |   |
| Series due  September 1, 2026, variable%                                        |   |                    |   |                          |   | —  |      | 27,500  |   |
| Series due  November 1, 2027, variable%                                         |   |                    |   |                          |   | —  |      | 35,000  |   |
| Series due  November 1, 2027, variable%                                         |   |                    |   |                          |   | —  |      | 35,000  |   |
| Total unsecured  pollution control bonds                                        |   |                    |   |                          |   | —  |      | 120,000 |   |
|                                                                            |   |                    |   |                          |   |    |      |    |   |
| Total bonds  outstanding                                                        |   |                    |   |                          |   | 616,904 |      | 616,904 |   |
|                                                                            |   |                    |   |                          |   |    |      |    |   |
| Less current  portion of long-term debt                                         |   |                    |   |                          |   | 288,800 |      | 246,200 |   |
|                                                                            |   |                    |   |                          |   |    |      |    |   |
| Long-term debt                                                                  |   |                    |   |                          |   | 328,104 |      | 370,704 |   |
|                                                                            |   |                    |   |                          |   |    |      |    |   |
| Total  capitalization                                                           |   |                    |   |                          |   | $       | 1,256,385 |    | $      | 1,303,914 |   |
|                                                                                 |        |                         |        |                               |        |         |           |         |        |  |  |  |

 

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

 

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Louisville Gas andElectric Company and SubsidiaryNotes to Consolidated Financial Statements

 

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

 

LG&E, a subsidiary of LG&E Energy and an indirect subsidiary ofPowergen and E.ON, is a regulated public utility engaged in the generation,transmission, distribution, and sale of electric energy and the storage,distribution, and sale of natural gas in Louisville and adjacent areas inKentucky.  LG&E Energy is an exemptpublic utility holding company with wholly owned subsidiaries includingLG&E, KU, Capital Corp., LEM, and LG&E Services.  All of the LG&E’s Common Stock is heldby LG&E Energy.  LG&E has onewholly owned consolidated subsidiary, LG&E R.

 

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.  E.ON and Powergen are registered public utility holding companiesunder PUHCA.  No costs associated withthese acquisitions nor any of the effects of purchase accounting have beenreflected in the financial statements of LG&E.

 

Certain reclassification entries have been made to the previous year’sfinancial statements to conform to the 2002 presentation with no impact on the balancesheet totals or previously reported income.

 

**Utility Plant.** LG&E’s utility plant is stated at original cost, which includespayroll-related costs such as taxes, fringe benefits, and administrative andgeneral costs.  Construction work inprogress has been included in the rate base for determining retail customerrates.  LG&E has not recorded anyallowance for funds used during construction.

 

The cost of plant retired or disposed of in thenormal course of business is deducted from plant accounts and such cost, plusremoval expense less salvage value, is charged to the reserve fordepreciation.  When complete operatingunits are disposed of, appropriate adjustments are made to the reserve fordepreciation and gains and losses, if any, are recognized.

 

**Depreciation and Amortization.** Depreciation is provided on the straight-line method over the estimatedservice lives of depreciable plant. Pursuant to a final order of the Kentucky Commission dated December 3,2001, LG&E implemented new depreciation rates effective January 1,2001.  The amounts provided wereapproximately 3.1% in 2002 (2.9% electric, 2.8% gas and 6.6% common); 3.0% for2001 (2.9% electric, 2.9% gas and 5.7% common); and 3.6% for 2000 (3.3% electric,3.8% gas and 7.3% common), of average depreciable plant.  Of the amount provided for depreciation, atDecember 31, 2002, 2001 and 2000, respectively, approximately 0.4 % electric,0.9 % gas and 0.04% common were related to the retirement, removal and disposalcosts of long lived assets.

 

**Fuel Inventory.**  Fuel inventories of $36.6million and $22.0 million at December 31, 2002, and 2001, respectively, areincluded in Fuel in the balance sheet. The inventory is accounted for using the average-cost method.

 

**Gas Stored Underground.**  Gasinventories of $50.3 million and $46.4 million at December 31, 2002, and 2001,respectively, are included in gas stored underground in the balance sheet.  The inventory is accounted for using theaverage-cost method.

 

**Financial Instruments.**  LG&Euses 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.  In 2000, LG&E used exchange traded U.S. 

 

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Treasurynote and bond futures to hedge its exposure to fluctuations in the value of itsinvestments in the preferred stocks of other companies.  Gains and losses on U.S. Treasury note andbond futures were charged or credited to other income-net. See Note 4 - Financial Instruments.

 

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

 

**Deferred Income Taxes.** Deferredincome taxes are recognized at currently enacted tax rates for allmaterial  temporary differences betweenthe financial reporting and income tax basis of assets and liabilities.

 

**Investment Tax Credits.** Investment tax credits resulted from provisions of the tax law thatpermitted a reduction of LG&E’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 onservice rendered to customers through month-end.  LG&E accrues an estimate for unbilled revenues from eachmeter reading date to the end of the accounting period.  The unbilled revenue estimates included inaccounts receivable were approximately $40.7million and $37.3 million, at December 31, 2002 and 2001, respectively.  See Note3, Rates and RegulatoryMatters.  LG&E recorded electric revenuesthat resulted from sales to a related party, KU, of $46.5 million, $28.5million and $20.9 million for years ended December 31, 2002, 2001 and 2000,respectively.

 

**Fuel and Gas Costs.**  The cost of fuel for electricgeneration is charged to expense as used, and the cost of gas supply is chargedto expense as delivered to the distribution system.  LG&E implemented a Kentucky Commission-approvedperformance-based ratemaking mechanism related to gas procurement andoff-system gas sales activity.  See Note 3, Rates and Regulatory Matters.

 

**Management’s Use of Estimates.**  Thepreparation of financial statements in conformity with generally acceptedaccounting principles requires management to make estimates and assumptionsthat affect the reported assets and liabilities and disclosure of contingentitems at the date of the financial statements and the reported amounts ofrevenues and expenses during the reporting period.  Actual results could differ from those estimates. See Note 11, Commitments and Contingencies, fora further discussion.

 

**AccountsReceivable Securitization. **SFASNo. 140, *Accountingfor Transfers and Servicing of Financial Assets and Extinguishments ofLiabilities*, revises the standards for accounting forsecuritizations and other transfers of financial assets and collateral andrequires certain disclosures, and provides accounting and reporting standardsfor transfers and servicing of financial assets and extinguishments ofliabilities. SFAS No. 140 was adopted in the first quarter of 2001, whenLG&E entered into an accounts receivable securitization transaction.

 

On February 6, 2001, LG&E implemented an accounts receivablesecuritization program.  The purpose ofthis program is 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. The securitization program allows for apercentage of eligible receivables to be sold. Eligible receivables are generally all receivables associated withretail sales that have standard terms and are not past due.  LG&E is able to terminate this programat any time without penalty. If there is a significant deterioration in thepayment record of the receivables by the retail customers or if LG&E failsto meet certain covenants regarding the program, the program may 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 LG&E.

 

As part of the program, LG&E sold retail accounts receivables to awholly owned subsidiary, LG&E R.  

 

76

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Simultaneously, LG&E R entered into two separate three-yearaccounts receivable securitization facilities with two financial institutionsand their affiliates whereby LG&E R can sell, on a revolving basis, anundivided interest in certain of its receivables and receive up to $75 millionfrom an unrelated third party purchaser. The effective cost of the receivables programs is comparable toLG&E’s lowest cost source of capital, and is based on prime ratedcommercial paper. LG&E retains servicing rights of the sold receivablesthrough two separate servicing agreements with the third party purchaser.  LG&E has obtained an opinion fromindependent legal counsel indicating these transactions qualify as true sale ofreceivables.  As of December 31, 2002,the outstanding program balance was $63.2million.  LG&E is consideringunwinding its accounts receivable securitization arrangements involvingLG&E R during 2003.

 

The allowance for doubtful accounts associated with the eligiblesecuritized receivables was $2.125 millionat December 31, 2002.  This allowance isbased on historical experience of LG&E. Each securitization facilitycontains a fully funded reserve for uncollectible receivables.

 

**New Accounting Pronouncements.**The following accounting pronouncementswere issued that affected LG&E in 2002:

 

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 is January 1,2003.  Management has calculated theimpact of SFAS No. 143 and the recently released FERC NOPR No. RM02-7, *Accounting,Financial Reporting, and Rate Filing Requirements for Asset Retirement Obligations*.  As of January 1, 2003, LG&E recordedasset retirement obligation (ARO) assets in the amount of $4.6 million andliabilities 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 $60,000offsetting removal costs previously accrued under regulatory accounting inexcess of amounts allowed  under SFASNo. 143.

 

LG&E also expects to record ARO accretion expense of approximately$617,000, ARO depreciation expense of approximately $117,000 and an offsettingregulatory credit in the income statement of approximately $734,000 in 2003,pursuant to regulatory treatment prescribed under SFAS No. 71, *Accountingfor the Effects of Certain Types of Regulation*.  The accretion, depreciation and regulatorycredit will be annual adjustments.  SFASNo. 143 will have no impact on the results of the operation of LG&E.

 

LG&E asset retirement obligations are primarily related to thefinal retirement of generating units. LG&E transmission and distribution lines largely operate underperpetual property easement agreements which do not generally require restorationupon removal of the property. Therefore, under SFAS No. 143, no material asset retirement obligationswill be 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 energy trading contracts bemarked to market on the balance sheet, with the gains and losses shown net inthe income statement.  In October 2002,the Emerging Issues Task Force reached a consensus to rescind EITF 98-10.  The effective date for the full rescissionis for fiscal periods beginning after December 15, 2002.  With the recession of EITF No. 98-10, energytrading contracts that do not also meet the definition of a derivative underSFAS No. 133 must be accounted for as executory contracts.  Contracts previously recorded at fair valueunder EITF No. 98-10 that are not also 

 

77

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derivatives under SFAS No. 133 must be restated to historical costthrough a cumulative effect adjustment. LG&E does not expect the rescission of this standard to have amaterial impact on financial position or results of operations.

 

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 from other parties.  FIN 46 is effectiveimmediately for all new variable interest entities created or acquired afterJanuary 31, 2003.  For variable interestentities created or acquired prior to February 1, 2003, the provisions of FIN46 must be applied for the first interim or annual period beginning after June15, 2003.  LG&E does not expect theadoption of this standard to have any impact on the financial position orresults of operations.

 

**Note 2 –Mergers and Acquisitions**

 

On July 1, 2002,E.ON completed its acquisition of Powergen, including LG&E Energy, forapproximately £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 theirregulatory filings in connection with the E.ON acquisition, E.ON, Powergen andLG&E Energy completed an administrative reorganization to move the LG&EEnergy group from an indirect Powergen subsidiary to an indirect E.ONsubsidiary.   This reorganization waseffective in March 2003.

 

LG&E Energy and KU Energy merged on May 4, 1998, with LG&EEnergy as the surviving corporation. Management accounted for the merger as a pooling of interests and as atax-free reorganization under the Internal Revenue Code.  Following the acquisition, LG&E hascontinued to maintain its separate corporate identity and serve customers inKentucky under its present name.

 

**Note 3 -Rates and Regulatory Matters**

 

Accounting for the regulated utility business conforms with generallyaccepted accounting principles as applied to regulated public utilities and asprescribed by FERC and the Kentucky Commission.  LG&E is subject to SFAS No. 71, *Accounting for the Effects of CertainTypes of Regulation*, under which certain costs that would otherwisebe charged to expense are deferred as regulatory assets based on expectedrecovery from 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.  The following regulatory assetsand liabilities were included in LG&E’s balance sheets

as of December 31 (in thousands of $):

 
|                                       |   | **2002** |    | **2001** |   |
|--------------------------------------------|--------|----------|---------|----------|--------|
|                                       |   |     |    |     |   |
| VDT Costs                                  |   | $        | 98,044  |     | $      | 127,529 |   |
| Gas supply  adjustments due from customers |   | 13,714   |    | 30,135   |   |
| Unamortized loss  on bonds                 |   | 18,843   |    | 17,902   |   |
| ESM provision                              |   | 12,500   |    | —   |   |
| LGE/KU merger  costs                       |   | 1,815    |    | 5,444    |   |
| Manufactured gas  sites                    |   | 1,757    |    | 2,062    |   |
| One utility  costs                         |   | 954      |    | 3,643    |   |
| Other                                      |   | 5,819    |    | 10,427   |   |
| Total regulatory  assets                   |   | 153,446  |    | 197,142  |   |
|                                       |   |     |    |     |   |
| Deferred income taxes - net                |   | (45,536  | )       | (48,703  | )      |
| Gas supply  adjustments due to customers   |   | (3,154   | )       | (15,702  | )      |
| Other                                      |   | (3,734   | )       | (944     | )      |
| Total regulatory  liabilities              |   | (52,424  | )       | (65,349  | )      |
| Regulatory  assets – net              |   | $        | 101,022 |     | $      | 131,793 |   |

 

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**KentuckyCommission Settlement - VDT Costs.**During the first quarter2001, LG&E recorded a $144 million charge for a workforce reductionprogram.  Primary components of thecharge were separation benefits, enhanced early retirement benefits, and healthcare benefits.  The result of thisworkforce reduction was the elimination of approximately 700 positions,accomplished primarily through a voluntary enhanced severance program.

 

On June 1, 2001, LG&E filed an application (VDT case) with theKentucky Commission to create a regulatory asset 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.

 

LG&E reached a settlement in the VDT case as well as the othercases involving depreciation rates and ESM with all intervening parties.  The settlement agreement was approved by theKentucky Commission on December 3, 2001. The order allowed LG&E to set up aregulatory asset of $141 million for the workforce reduction costs and beginamortizing these costs over a five year period starting in April 2001. Thefirst quarter 2001 charge of $144 million represented all employees who hadaccepted a voluntary enhanced severance program.  Some employees rescinded their participation in the voluntaryenhanced severance program, thereby decreasing the original charge from $144million to $141 million. The settlement will also reduce revenues approximately$26 million through a surcredit on future bills to customers over the same fiveyear period.  The surcredit representsnet savings stipulated by LG&E.  Theagreement also established LG&E’s new depreciation rates in effect December2001, retroactive to January 1, 2001. The new depreciation rates decreased depreciation expense by $5.6million in 2001.

 

**PUHCA.** LG&E Energy was purchased by Powergen on December 11, 2000.  Effective July 1, 2002, Powergen wasacquired by E.ON, which became a registered holding company under PUHCA.  As a result, E.ON, its utility subsidiaries,including LG&E, and certain of its non-utility subsidiaries are subject toextensive regulation by the SEC under PUHCA with respect to issuances and salesof securities, acquisitions and sales of certain utility properties, andintra-system sales of certain goods and services.  In addition, PUHCA generally limits the ability of registeredholding companies to acquire additional public utility systems and to acquireand retain businesses unrelated to the utility operations of the holdingcompany.  LG&E believes that it hasadequate authority (including financing authority) under existing SEC ordersand regulations to conduct its business. LG&E will seek additional authorization when necessary.

 

**EnvironmentalCost Recovery.**In June 2000, the Kentucky Commission approvedLG&E’s application for a CCN to construct up to three SCR NOx reductionfacilities. The construction and subsequent operation of the SCRs is intendedto reduce NOx emission levels to meet the EPA’s mandated NOx emission level of0.15 lbs./ Mmbtu by May 2004.  In itsorder, the Kentucky Commission ruled that LG&E’s proposed plan for constructionwas “reasonable, cost-effective and will not result in the wasteful duplicationof facilities.”  In October 2000, 

 

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LG&E filed an application with the Kentucky Commission to amend itsEnvironmental Compliance Plan to reflect the addition of the proposed NOxreduction technology projects and to amend its ECR Tariff to include an overallrate of return on capital investments. Approval of LG&E’s application inApril 2001 allowed LG&E to begin to recover the costs associated with thesenew projects, subject to Kentucky Commission oversight during normal six-monthand two-year reviews.

 

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.  The Kentucky Commissionconducted a public hearing on the case on December 20, 2002, final briefs werefiled on January 15, 2003, and a final order was issued February 11, 2003.  The final order approved recovery of fournew environmental compliance facilities totaling $43.1 million.  A fifth project, expansion of the land fillfacility 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 will begin with the billsrendered in April 2003.

 

**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.  LG&Emade its second ESM filing on March 1, 2002 for the calendar year 2001reporting period.  LG&E is in theprocess of refunding $441,000 to customers for the 2001 reporting period.  LG&Eestimated that the rate of return will fall below the lower limit, subject toKentucky Commission approval, for the year ended December 31, 2002.  The 2002 financial statements include anaccrual to reflect the earnings deficiency of $12.5 million to be recoveredfrom customers commencing in April 2003.

 

On November 27, 2002, LG&E filed a revised ESM tariff whichproposed continuance of the existing ESM through December 2005.  The Kentucky Commission issued an Ordersuspending the ESM tariff one day making the effective date January 2,2003.  In addition, the KentuckyCommission is conducting a management audit to review the ESM plan and reassessits reasonableness in 2003.  LG&Eand interested parties will have the opportunity to provide recommendations formodification and continuance of the ESM or other forms of alternative orincentive regulation.

 

**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 program had allowed LG&E to recover revenues from lost salesassociated with the DSM program.  In May2001, the Kentucky Commission approved LG&E’s plan to continue DSMprograms.  This filing 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 planning engineering estimates andpost-implementation evaluation.

 

**Gas PBR.**  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 October 31, 2001, LG&E has achieved $38.1 millionin savings. Of the total savings, LG&E has retained $16.5 million, and theremaining portion of $21.6 million has been distributed to customers.  In December 2000, LG&E filed anapplication reporting on the operation of the experimental PBR and requestedthe Kentucky Commission to extend the PBR 

 

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as a result of the benefits provided to both LG&E and its customersduring the experimental period. Following the discovery and hearing process,the Kentucky Commission issued an order effective November 1, 2001, extendingthe experimental PBR program for an additional four years, and making othermodifications, including changes to the sharing levels applicable to savings orexpenses incurred under the PBR. Specifically, the Kentucky Commission modified the savings mechanism toa 25%/75% Company/Customer sharing for all savings (and expenses) up to 4.5% ofthe benchmarked gas costs.  Savings (andexpenses) in excess of 4.5% of the benchmarked gas costs are shared at a50%/50% level.

 

**FAC.** Prior to implementation of the electric PBRin July 1999, and following its termination in March 2000, LG&E employed anFAC mechanism, which under Kentucky law allowed LG&E to recover fromcustomers the actual fuel costs associated with retail electric sales.  In February 1999, LG&E received ordersfrom the Kentucky Commission requiring a refund to retail electric customers ofapproximately $3.9 million resulting from reviews of the FAC from November1994, through April 1998.  While legalchallenges to the Kentucky Commission order were pending, a comprehensivesettlement was reached by all parties and approved by the  Kentucky Commission on May 17, 2002.  Thereunder, LG&E agreed to credit itsfuel clause in the amount of $720,000 (such credit provided over the course ofJune and July 2002), and the parties agreed on a prospective interpretation ofthe state’s FAC regulation to ensure consistent and mutually acceptableapplication on a going-forward basis.

 

In December 2002, the Kentucky Commission initiated a two year reviewof the operation of LG&E’s FAC for the period November 2000 through October2002.  Testimony in the review case wasfiled on January 20, 2003 and a public hearing was held February 18, 2003.  Issues addressed at that time included theestablishment of the current base fuel factor to be included in LG&E’s baserates, verification of proper treatment of purchased power costs during unitoutages, and compliance with fuel procurement policies and practices.

 

**Gas RateCase.**   In March 2000,LG&E filed an application with the Kentucky Commission requesting anadjustment in LG&E’s gas rates.  InSeptember 2000, the Kentucky Commission granted LG&E an annualincrease in its base gas revenues of $20.2 million effective September 28,2000.  The Kentucky Commissionauthorized a return on equity of 11.25%. The Kentucky Commission approved LG&E’s proposal for a weathernormalization billing adjustment mechanism that will normalize the effect ofweather on base gas revenues from gas sales.

 

**WholesaleNatural Gas Prices.** On September 12, 2000, the Kentucky Commission issued an orderestablishing Administrative Case No. 384 – “An Investigation of IncreasingWholesale Natural Gas Prices and the Impacts of such Increase on the RetailCustomers Served by Kentucky’s Jurisdictional Natural Gas Distribution Companies”.  The impetus for this administrativeproceeding was the escalation of wholesale natural gas prices during the summerof 2000.

 

The Kentucky Commissiondirected Kentucky’s natural gas distribution companies, including LG&E, tofile selected information regarding the individual companies’ natural gaspurchasing practices, expectations for the then-approaching winter heatingseason of 2000-2001, and potential actions which these companies might take tomitigate price volatility.  On July 17,2001, the Kentucky Commission issued an order encouraging the natural gasdistribution companies in Kentucky to take various actions, among them topropose a natural gas hedge plan, consider performance-based ratemakingmechanisms, and to increase the use of storage.

 

In April 2002, in Case No. 2002-00136, LG&E proposed a hedging planfor the 2002/2003 winter heating season with three alternatives, the first twousing a combination of storage and financial hedge instruments and the thirdrelying upon storage alone.  LG&Eand the Attorney General, who represents Kentucky consumers, entered into asettlement which selected the third option. In August 2002, the Kentucky Commission approved the plan contemplatedin the settlement.  The KentuckyCommission validated the effectiveness of storage to 

 

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mitigate potentially high winter gas prices by approving this naturalgas hedging plan.

 

The Kentucky Commission also decided in Administrative Case No. 384 toengage a consultant to conduct a forward-looking audit of the gas procurementand supply procedures of Kentucky’s largest natural gas distributioncompanies.  The KentuckyCommission completed its audit in late 2002.  The audit recognized LG&E as “efficient andeffective [in the] procurement and management of significant quantities ofnatural gas supplies.”  The auditors also recognized that “the Company’sresidential gas prices have long been below averages for the U. S. and for theCommonwealth of Kentucky” which “demonstrates [LG&E’s] effectiveness in[the] procurement and management of natural gas supplies.”  The audit alsostated that the “Company’s very impressive record in keeping its ratesdown provides sound evidence on the excellent job done in the area of gas supplyprocurement and management.”

 

**KentuckyCommission Administrative Case for Affiliate Transactions.** InDecember 1997, the Kentucky Commission opened Administrative Case No. 369 toconsider Kentucky Commission policy regarding cost allocations, affiliate transactionsand codes of conduct governing the relationship between utilities and theirnon-utility operations and affiliates. The Kentucky Commission intended to address two major areas in theproceedings: the tools and conditions needed to prevent cost shifting andcross-subsidization between regulated and non-utility operations; and whether acode of conduct should be established to assure that non-utility segments ofthe holding company are not engaged in practices that could result in unfaircompetition caused by cost shifting from the non-utility affiliate to theutility.  During the period September1998 to February 2000, the Kentucky Commission issued draft codes of conductand cost allocation guidelines.  Inearly 2000, the  Kentucky GeneralAssembly enacted legislation, House Bill 897, which authorized the KentuckyCommission to require utilities that provide nonregulated activities to keepseparate accounts and allocate costs in accordance with procedures establishedby 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 LG&E has been operating pursuant thereto since that time.  On February 14, 2001, the KentuckyCommission published notice of its intent to promulgate new administrativeregulations under the auspices of this new law.  This effort is still on going.

 

**Kentucky Commission Administrative Case for SystemAdequacy. **On June 19,2001, Kentucky Governor Paul E. Patton issued Executive Order 2001-771, whichdirected the Kentucky Commission to review and study issues relating to theneed for and development of new electric generating capacity in Kentucky.  The issues to be considered included theimpact of new power plants on the electric supply grid, facility citing issues,and economic development matters, with the goal of ensuring a continued,reliable source of supply of electricity for the citizens of Kentucky and thecontinued environmental and economic vitality of Kentucky and its communities.  In response to that Executive Order, in July2001 the Kentucky Commission opened Administrative Case No. 387 to review theadequacy of Kentucky’s generation capacity and transmission system.  Specifically, the items reviewed were theappropriate level of reliance on purchased power, the appropriate reservemargins to meet existing and future electric demand, the impact of spikes innatural gas prices on electric utility planning strategies, and the adequacy ofKentucky’s electric transmission facilities. LG&E, as a party to this proceeding, filed written testimony andresponded to two requests for information. Public hearings were held and in October 2001, LG&E filed a finalbrief in the case.  In December 2001,the Kentucky Commission issued an order in which it noted that LG&E isresponsibly addressing the long-term supply needs of native load customers andthat current reserve margins are appropriate. However, due to the rapid pace of change in the industry, the order alsorequires LG&E to provide an annual assessment of supply resources, futuredemand, reserve margin, and the need for new resources.

 

Regarding the transmission system, the Kentucky Commission concludedthat the transmission system within 

 

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Kentucky can reliably serve native load and a significant portion ofthe proposed 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 pledged to continue to monitor all relevantissues and advocate Kentucky’s interests at all opportunities.

 

**FERC SMDNOPR. **On July 31,2002, 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 eachpublic utility that owns, operates, or controls interstate transmissionfacilities to become an Independent Transmission Provider (ITP), belong to anRTO that is an ITP, or contract with an ITP for operation of its transmissionassets. It would also establish a standardized congestion management system,real-time and day-ahead energy markets, and a single transmission service fornetwork and point-to-point transmission customers. Review of the proposedrulemaking is underway and a final rule is expected during 2003.  While it is expected that the SMD final rulewill affect LG&E revenues and expenses, the specific impact of therulemaking is not known at this time.

 

**MISO. **LG&E is a member ofthe MISO, which began commercial operations on February 1, 2002.  MISO now has operational control overLG&E’s high-voltage transmission facilities (100 kV and greater), whileLG&E continues to control and operate the lower voltage transmissionsubject to the terms and conditions of the MISO OATT.  As a transmission-owning member of MISO, LG&E also incursadministrative costs of MISO pursuant to Schedule 10 of the MISO OATT.

 

MISO also proposedto implement a congestion management system. FERC directed the MISO to coordinate its efforts with FERC’s Rulemakingon SMD. OnSeptember 24, 2002, the MISO filed new rate schedules designated as Schedules16 and 17, which provide for the collection of costs incurred by the MISO toestablish day-ahead and real-time energy markets. The MISO proposed to recoverthese costs under Schedules 16 and 17 once service commences. If approved by FERC,these schedules will cause LG&E to incur additional costs.  LG&E opposes the establishment ofSchedules 16 and 17.  This effort isstill on-going and the ultimate impact of the two schedules, if approved, isnot known at this time.

 

**ARO.**  In 2003, LG&E expects to recordapproximately $6.0 million in regulatory assets and approximately $60,000 inregulatory liabilities related to SFAS No. 143, *Accounting for Asset RetirementObligations*.

 

**MergerSurcredit.**  As part ofthe LG&E Energy merger with KU Energy in 1998, LG&E Energy estimatednon-fuel savings over a ten–year period following the merger.  Costs to achieve these savings for LG&Eof $50.2 million were recorded in the second quarter of 1998, $18.1 million ofwhich was deferred and amortized over a five-year period pursuant to regulatoryorders.  Primary components of themerger costs were separation benefits, relocation costs, and transaction fees,the majority of which were paid by December 31, 1998.  LG&E expensed the remaining costs associated with the merger($32.1 million) in the second quarter of 1998.

 

In approving the merger, the Kentucky Commission adopted LG&E’sproposal to reduce its retail customers’ bills based on one-half of theestimated merger-related savings, net of deferred and amortized amounts, over afive-year period.  The surcreditmechanism provides that 50% of the net non-fuel cost savings estimated to beachieved from the merger be provided to ratepayers through a monthly billcredit, and 50% be retained by the Companies, over a five-year period.  The surcredit was allocated 53% to KU and47% to LG&E.  In that same order,the Commission required LG&E and KU, after the end of the five-year period,to present a plan for sharing with customers the then-projected non-fuelsavings associated with the merger.  TheCompanies submitted this filing on January 13, 2003, proposing to continue toshare with customers, on a 50%/50% basis, the estimated fifth-year gross levelof non-fuel savings associated with the merger.  The filing is currently under 

 

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review.

 

Any fuel cost savings are passed to Kentucky customers through the fueladjustment clause.  See FAC above.

 

**Note 4 -Financial Instruments**

 

The cost and estimated fair values of LG&E’snon-trading financial instruments as of December 31, 2002, and 2001 follow (inthousands of $):
|                                             |   | **2002** |   | **2001**        |   |
|--------------------------------------------------|--------|----------|--------|-----------------|--------|
|                                             |   | **Cost** |   | **Fair  Value** |   | **Cost** |   | **Fair  Value** |   |
|                                             |   |     |   |            |   |   |   |   |   |
| Preferred stock  subject to mandatory redemption |   | $        | 25,000 |            | $      | 25,188 |   | $ | 25,000 |   | $ | 25,125 |   |
| Long-term debt  (including current portion)      |   | 616,904  |   | 623,325         |   | 616,904 |   | 620,504 |   |
| Interest-rate  swaps                             |   | —   |   | (17,115         | )      | — |   | (8,604 | ) |
|                                                  |        |          |        |                 |        |  |  |  |  |  |  |  |  |

 

All of the above valuations reflect prices quotedby exchanges except for the swaps. The fair values of the swaps reflect pricequotes from dealers or amounts calculated using accepted pricing models.

 

**Interest Rate Swaps. **LG&E uses interest rate swaps to hedgeexposure to market fluctuations in certain of its debt instruments.  Pursuant to policy, use of these financialinstruments is intended to mitigate risk and earnings volatility and is notspeculative in nature.  Management hasdesignated all of the interest rate swaps as hedge instruments.  Financial instruments designated as cashflow hedges have resulting gains and losses recorded within other comprehensiveincome and stockholders’ equity.  To theextent a financial instrument or the underlying item being hedged isprematurely terminated or the hedge becomes ineffective, the resulting gains orlosses are reclassified from other comprehensive income to net income.  Financial instruments designated as fairvalue hedges are periodically marked to market with the resulting gains andlosses recorded directly into net income to correspond with income or expenserecognized from changes in market value of the items being hedged.

 

As of December 31, 2002 and 2001, LG&E was party to variousinterest rate swap agreements with aggregate notional amounts of $117.3 million.  Under these swap agreements, LG&E paid fixed rates averaging 5.13% and received variable rates based onthe Bond Market Association’s municipal swap index averaging 1.52% and 1.61% at December 31, 2002 and2001, respectively. The swap agreements in effect at December 31, 2002 havebeen designated as cash flow hedges and mature on dates ranging from 2003 to 2020.  The hedges have been deemed to be fullyeffective resulting in a pretax loss of $8.5million for 2002, recorded in other comprehensive income.  Upon expiration of these hedges, the amountrecorded in other comprehensive income will be reclassified into earnings.  The amounts expected to be reclassified fromother comprehensive income to earnings in the next twelve months is immaterial.

 

# **Energy Trading & 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 EITF 98-10,*Accountingfor Contracts Involved in Energy Trading and Risk Management Activities*,SFAS No. 133,*Accountingfor Derivative Instruments and Hedging Activities,* and SFAS No. 138,*Accounting for Certain DerivativeInstruments and Certain Hedging Activities*.  Wholesale sales of excess asset capacity andwholesale purchases are treated as normal sales and purchases under SFAS No. 133 and SFAS No. 138 and are notmarked-to-market.

 

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The rescission of EITF 98-10,effective for fiscal years after December 15, 2002, will have no impact onLG&E’s energy trading and risk management reporting as all contracts markedto market under EITF 98-10 are also within the scope of SFAS No. 133.

 

The table belowsummarizes LG&E’s energy trading and risk management activities for 2002and 2001 (in thousands of $).

##  

|                                                          |   | **2002** |   | **2001** |   |
|---------------------------------------------------------------|--------|----------|--------|----------|--------|
| Fair value of contracts at beginning of period, net liability |   | $        | (186   | )        | $      | (17 | ) |
| Fair value of contracts when entered into during the period   |   | (65      | )      | 3,441    |   |
| Contracts realized or otherwise settled during the period     |   | 448      |   | (2,894   | )      |
| Changes in fair values due to changes in assumptions          |   | (353     | )      | (716     | )      |
| Fair value of contracts at end of period, net liability       |   | $        | (156   | )        | $      | (186 | ) |

 

No changes to valuation techniques for energy tradingand risk management activities occurred during 2002.  Changes in market pricing, interest rate and volatilityassumptions were made during both years. All contracts outstanding at December 31, 2002, have a maturity of lessthan one year and are valued using prices actively quoted for proposed orexecuted transactions or quoted by brokers.

 

LG&E maintains policies intended to minimize credit risk andrevalues credit exposures daily to monitor compliance with those policies.  At December 31, 2002, 86% of the trading andrisk management commitments were with counterparties rated BBB- equivalent orbetter.

 

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

 

Creditrisk represents the accounting loss that would be recognized at the reportingdate 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’scustomer receivables and gas and electric revenues arise from deliveries ofnatural gas to approximately 310,000 customers and electricity to approximately382,000 customers in Louisville and adjacent areas in Kentucky.  For the year ended December 31, 2002, 74% oftotal revenue was derived from electric operations and 26% from gas operations.

 

In November 2001, LG&E and IBEWLocal 2100 employees, which represent approximately 70% of LG&E’sworkforce, entered into a four-year collective bargaining agreement.

 

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**Note 6 -Pension Plans and Retirement Benefits**

 

LG&E sponsors several qualified and non-qualified pension plans andother postretirement benefit plans for its employees.  The following tables provide a reconciliation of the changes inthe plans’ benefit obligations and fair value of assets over the three-yearperiod ending December 31, 2002, and a statement of the funded status as ofDecember 31 for each of the last three years (in thousands of $):

 
|                                           |   | **2002** |     | **2001** |   | **2000** |   |
|------------------------------------------------|--------|----------|----------|----------|--------|----------|--------|
| Pension Plans:                                 |   |     |     |     |   |     |   |
| Change in benefit obligation                   |   |     |     |     |   |     |   |
| Benefit obligation at beginning of year        |   | $        | 356,293  |     | $      | 310,822  |   | $ | 283,267 |   |
| Service cost                                   |   | 1,484    |     | 1,311    |   | 3,408    |   |
| Interest cost                                  |   | 24,512   |     | 25,361   |   | 22,698   |   |
| Plan amendments                                |   | 576      |     | 1,550    |   | 17,042   |   |
| Curtailment loss                               |   | —   |     | 24,563   |   | —   |   |
| Special termination benefits                   |   | —   |     | 53,610   |   | —   |   |
| Benefits paid                                  |   | (34,823  | )        | (53,292  | )      | (16,656  | )      |
| Actuarial (gain) or loss and other             |   | 16,752   |     | (7,632   | )      | 1,063    |   |
| Benefit obligation at end of year              |   | $        | 364,794  |     | $      | 356,293  |   | $ | 310,822 |   |
|                                           |   |     |     |     |   |     |   |
| Change in plan assets                          |   |     |     |     |   |     |   |
| Fair value of plan assets at beginning of year |   | $        | 233,944  |     | $      | 333,378  |   | $ | 360,095 |   |
| Actual return on plan assets                   |   | (15,648  | )        | (27,589  | )      | (6,150   | )      |
| Employer contributions and plan transfers      |   | 14,150   |     | (17,134  | )      | (1,804   | )      |
| Benefits paid                                  |   | (34,824  | )        | (53,292  | )      | (16,656  | )      |
| Administrative expenses                        |   | (1,308   | )        | (1,419   | )      | (2,107   | )      |
| Fair value of plan assets at end of year       |   | $        | 196,314  |     | $      | 233,944  |   | $ | 333,378 |   |
|                                           |   |     |     |     |   |     |   |
| Reconciliation of funded status                |   |     |     |     |   |     |   |
| Funded status                                  |   | $        | (168,480 | )        | $      | (122,349 | )      | $ | 22,556 |   |
| Unrecognized actuarial (gain) or loss          |   | 60,313   |     | 18,800   |   | (74,086  | )      |
| Unrecognized transition (asset) or obligation  |   | (3,199   | )        | (4,215   | )      | (5,853   | )      |
| Unrecognized prior service cost                |   | 32,265   |     | 35,435   |   | 47,984   |   |
| Net amount recognized at end of year           |   | $        | (79,101  | )        | $      | (72,329  | )      | $ | (9,399 | ) |
|                                           |   |     |     |     |   |     |   |
| Other Benefits:                                |   |     |     |     |   |     |   |
| Change in benefit obligation                   |   |     |     |     |   |     |   |
| Benefit obligation at beginning of year        |   | $        | 89,946   |     | $      | 56,981   |   | $ | 44,997 |   |
| Service cost                                   |   | 444      |     | 358      |   | 822      |   |
| Interest cost                                  |   | 5,956    |     | 5,865    |   | 4,225    |   |
| Plan amendments                                |   | —   |     | 1,487    |   | 5,826    |   |
| Curtailment loss                               |   | —   |     | 8,645    |   | —   |   |
| Special termination benefits                   |   | —   |     | 18,089   |   | —   |   |
| Benefits paid                                  |   | (4,988   | )        | (4,877   | )      | (4,889   | )      |
| Actuarial (gain) or loss                       |   | 1,875    |     | 3,398    |   | 6,000    |   |
| Benefit obligation at end of year              |   | $        | 93,233   |     | $      | 89,946   |   | $ | 56,981 |   |
|                                           |   |     |     |     |   |     |   |
| Change in plan assets                          |   |     |     |     |   |     |   |
| Fair value of plan assets at beginning of year |   | $        | 2,802    |     | $      | 7,166    |   | $ | 10,526 |   |
| Actual return on plan assets                   |   | (533     | )        | (765     | )      | (92      | )      |
| Employer contributions and plan transfers      |   | 4,213    |     | 1,282    |   | 1,621    |   |
| Benefits paid                                  |   | (5,004   | )        | (4,881   | )      | (4,889   | )      |
| Fair value of plan assets at end of year       |   | $        | 1,478    |     | $      | 2,802    |   | $ | 7,166 |   |
|                                           |   |     |     |     |   |     |   |
| Reconciliation of funded status                |   |     |     |     |   |     |   |
| Funded status                                  |   | $        | (91,755  | )        | $      | (87,144  | )      | $ | (49,815 | ) |
| Unrecognized actuarial (gain) or loss          |   | 16,971   |     | 15,947   |   | 5,623    |   |
| Unrecognized transition (asset) or obligation  |   | 6,697    |     | 7,346    |   | 13,374   |   |
| Unrecognized prior service cost                |   | 5,995    |     | 5,302    |   | 8,960    |   |
| Net amount recognized at end of year           |   | $        | (62,092  | )        | $      | (58,549  | )      | $ | (21,858 | ) |

 

86

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There are no plan assets in the nonqualified plans due to the nature ofthe plans.

 

LG&E made a contribution to the pension plan of$83.1 million in January 2003.

 

The following tables provide the amounts recognized in the balancesheet and information for plans with benefit obligations in excess of planassets as of December 31, 2002, 2001and 2000 (in thousands of $):

 
|                                                                                                           |   | **2002** |    | **2001** |   | **2000** |   |
|----------------------------------------------------------------------------------------------------------------|--------|----------|---------|----------|--------|----------|--------|
|                                                                                                           |   |     |    |     |   |     |   |
| Pension Plans:                                                                                                 |   |     |    |     |   |     |   |
| Amounts recognized in the balance sheet consisted of:                                                          |   |     |    |     |   |     |   |
| Prepaid benefits cost                                                                                          |   | $        | —  |     | $      | —   |   | $ | 18,880 |   |
| Accrued benefit liability                                                                                      |   | (162,611 | )       | (108,977 | )      | (28,279  | )      |
| Intangible asset                                                                                               |   | 32,799   |    | 11,936   |   | —   |   |
| Accumulated other comprehensive income                                                                         |   | 50,711   |    | 24,712   |   | —   |   |
| Net amount recognized at year-end                                                                              |   | $        | (79,101 | )        | $      | (72,329  | )      | $ | (9,399 | ) |
|                                                                                                           |   |     |    |     |   |     |   |
| Additional year-end  information for plans with accumulated benefit obligations in excess of  plan assets (1): |   |     |    |     |   |     |   |
| Projected benefit obligation                                                                                   |   | $        | 364,794 |     | $      | 356,293  |   | $ | 4,088 |   |
| Accumulated benefit obligation                                                                                 |   | 358,956  |    | 352,477  |   | 3,501    |   |
| Fair value of plan assets                                                                                      |   | 196,314  |    | 233,944  |   | —   |   |

 

----

| (1)  2002 and 2001 includes all  plans. 2000 includes SERPs only. |
|------------------------------------------------------------------------|

 

 
| Other Benefits:                                                                               |   |   |    |   |   |    |   |
|-----------------------------------------------------------------------------------------------|--------|--------|---------|--------|--------|---------|--------|
| Amounts recognized in the balance sheet consisted of:                                         |   |   |    |   |   |    |   |
| Accrued benefit liability                                                                     |   | $      | (62,092 | )      | $      | (58,549 | )      | $ | (21,858 | ) |
|                                                                                          |   |   |    |   |   |    |   |
| Additional year-end information for plans with benefit obligations in  excess of plan assets: |   |   |    |   |   |    |   |
| Projected benefit obligation                                                                  |   | $      | 93,233  |   | $      | 89,946  |   | $ | 56,981 |   |
| Fair value of plan assets                                                                     |   | 1,478  |    | 2,802  |   | 7,166   |   |

 

87

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The following table provides the components of net periodic benefitcost for the plans for 2002, 2001 and 2000 (in thousands of $):

 
|                                             |   | **2002** |   | **2001** |   | **2000** |   |
|--------------------------------------------------|--------|----------|--------|----------|--------|----------|--------|
|                                             |   |     |   |     |   |     |   |
| Pension Plans:                                   |   |     |   |     |   |     |   |
| Components of net periodic benefit cost          |   |     |   |     |   |     |   |
| Service cost                                     |   | $        | 1,484  |     | $      | 1,311    |   | $ | 3,408 |   |
| Interest cost                                    |   | 24,512   |   | 25,361   |   | 22,698   |   |
| Expected return on plan assets                   |   | (21,639  | )      | (26,360  | )      | (33,025  | )      |
| Amortization of prior service cost               |   | 3,777    |   | 3,861    |   | 4,646    |   |
| Amortization of transition (asset) or obligation |   | (1,016   | )      | (1,000   | )      | (1,112   | )      |
| Recognized actuarial (gain) or loss              |   | 21       |   | (777     | )      | (6,856   | )      |
| Net periodic benefit cost                        |   | $        | 7,139  |     | $      | 2,396    |   | $ | (10,241 | ) |
|                                             |   |     |   |     |   |     |   |
| 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                                     |   | $        | 444    |     | $      | 358      |   | $ | 822 |   |
| Interest cost                                    |   | 5,956    |   | 5,865    |   | 4,225    |   |
| Expected return on plan assets                   |   | (204     | )      | (420     | )      | (683     | )      |
| Amortization of prior service cost               |   | 920      |   | 951      |   | 1,158    |   |
| Amortization of transition (asset) or obligation |   | 650      |   | 719      |   | 1,114    |   |
| Recognized actuarial (gain) or loss              |   | 116      |   | (32      | )      | (485     | )      |
| Net periodic benefit cost                        |   | $        | 7,882  |     | $      | 7,441    |   | $ | 6,151 |   |
|                                             |   |     |   |     |   |     |   |
| Special charges                                  |   |     |   |     |   |     |   |
| Curtailment loss                                 |   | $        | — |     | $      | 6,671    |   | $ | — |   |
| Prior service cost recognized                    |   | —   |   | 2,391    |   | —   |   |
| Transition obligation recognized                 |   | —   |   | 4,743    |   | —   |   |
| Special termination benefits                     |   | —   |   | 18,089   |   | —   |   |
| Total charges                                    |   | $        | — |     | $      | 31,894   |   | $ | — |   |

 

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

 
|                                             |   | **2002** |   | **2001** |   | **2000** |   |
|--------------------------------------------------|--------|----------|--------|----------|--------|----------|--------|
|                                             |   |     |   |     |   |     |   |
| Weighted-average assumptions as of December 31:  |   |     |   |     |   |     |   |
| Discount rate                                    |   | 6.75     | %      | 7.25     | %      | 7.75     | %      |
| Expected long-term rate of return on plan assets |   | 9.00     | %      | 9.50     | %      | 9.50     | %      |
| Rate of compensation increase                    |   | 3.75     | %      | 4.25     | %      | 4.75     | %      |

 

For measurement purposes, a 12.00% annual increase in the per capitacost of covered health care benefits was assumed for 2003.  The rate was assumed to decrease graduallyto 5.00% for 2014 and remain at that level thereafter.

 

Assumed health care cost trend rates have a significant effect on theamounts reported for the health care plans. A 1% change in assumed health carecost trend rates would have the following effects (in thousands of $):

 

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|                                                              |   | **1%  Decrease** |   | **1% Increase** |   |
|-------------------------------------------------------------------|--------|------------------|--------|-----------------|--------|
|                                                              |   |             |   |            |   |
| Effect on total  of service and interest cost components for 2002 |   | (201             | )      | 227             |   |
| Effect on  year-end 2002 postretirement benefit obligations       |   | (3,001           | )      | 3,347           |   |

 

**ThriftSavings Plans.**  LG&E has a thrift savings plan under section401(k) of the Internal Revenue Code. Under the plan, eligible employees may defer and contribute to the plana portion of current compensation in order to provide future retirementbenefits. LG&E makes contributions to the plan by matching a portion of theemployee contributions.  The costs ofthis matching were approximately $1.7 million for 2002, $1.2 million for 2001and $2.7 million for 2000.

 

**Note 7 -Income Taxes**

 

Components of income tax expense are shown in the table below (inthousands of $):

 
|                                                              |   | **2002** |   | **2001** |   | **2000** |   |
|-------------------------------------------------------------------|--------|----------|--------|----------|--------|----------|--------|
|                                                              |   |     |   |     |   |     |   |
| Included in  operating expenses:                                  |   |     |   |     |   |     |   |
| Current        -  federal |   | $        | 26,231 |     | $      | 42,997   |   | $ | 32,612 |   |
| - state                                                           |   | 8,083    |   | 8,668    |   | 5,018    |   |
| Deferred      -  federal – net |   | 20,464   |   | 12,310   |   | 24,272   |   |
| - state – net                                                |   | 4,410    |   | 3,767    |   | 6,797    |   |
| Amortization of  investment tax credit                            |   | (4,153   | )      | (4,290   | )      | (4,274   | )      |
| Total                                                             |   | 55,035   |   | 63,452   |   | 64,425   |   |
|                                                              |   |     |   |     |   |     |   |
| Included in other income - net:                                   |   |     |   |     |   |     |   |
| Current        -  federal |   | (1,667   | )      | (1,870   | )      | (2,187   | )      |
| - state                                                           |   | (430     | )      | (483     | )      | (568     | )      |
| Deferred      -  federal – net |   | (206     | )      | 285      |   | (39      | )      |
| - state – net                                                |   | (53      | )      | 73       |   | (10      | )      |
| Total                                                             |   | (2,356   | )      | (1,995   | )      | (2,804   | )      |
|                                                              |   |     |   |     |   |     |   |
| Total income tax  expense                                         |   | $        | 52,679 |     | $      | 61,457   |   | $ | 61,621 |   |

 

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

 
|                                                    |   | **2002** |    | **2001** |   |
|---------------------------------------------------------|--------|----------|---------|----------|--------|
| Deferred tax  liabilities:                              |   |     |    |     |   |
| Depreciation and  other plant-related items             |   | $        | 346,737 |     | $      | 334,914 |   |
| Other  liabilities                                      |   | 64,734   |    | 77,611   |   |
|                                                    |   | 411,471  |    | 412,525  |   |
| Deferred tax  assets:                                   |   |     |    |     |   |
| Investment tax  credit                                  |   | 22,012   |    | 23,713   |   |
| Income taxes due  to customers                          |   | 18,431   |    | 19,709   |   |
| Pensions                                                |   | 21,056   |    | 6,621    |   |
| Accrued  liabilities not currently deductible and other |   | 36,747   |    | 64,339   |   |
|                                                    |   | 98,246   |    | 114,382  |   |
|                                                    |   |     |    |     |   |
| Net deferred  income tax liability                      |   | $        | 313,225 |     | $      | 298,143 |   |

 

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

 

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tax rate follows:

 
|                                        |   | **2002** |   | **2001** |   | **2000** |   |
|---------------------------------------------|--------|----------|--------|----------|--------|----------|--------|
|                                        |   |     |   |     |   |     |   |
| Statutory federal income tax rate           |   | 35.0     | %      | 35.0     | %      | 35.0     | %      |
| State income  taxes, net of federal benefit |   | 5.6      |   | 4.7      |   | 4.3      |   |
| Amortization of investment tax credit       |   | (2.9     | )      | (2.6     | )      | (2.6     | )      |
| Other  differences – net               |   | (0.5     | )      | (0.6     | )      | (0.9     | )      |
| Effective income  tax rate                  |   | 37.2     | %      | 36.5     | %      | 35.8     | %      |

 

# **Note 8 - Other Income - net**

 

Other income – net consisted of the following at December 31 (inthousands of $):

 
|                           |   | **2002** |   | **2001** |   | **2000** |   |
|--------------------------------|--------|----------|--------|----------|--------|----------|--------|
|                           |   |     |   |     |   |     |   |
| Interest and dividend income   |   | $        | 457    |     | $      | 748      |   | $ | 3,103 |   |
| Gains on fixed asset disposals |   | 421      |   | 1,217    |   | 1,014    |   |
| Income taxes and other         |   | (58      | )      | 965      |   | 804      |   |
| Other income – net        |   | $        | 820    |     | $      | 2,930    |   | $ | 4,921 |   |

 

**Note 9 -First Mortgage Bonds and Pollution Control Bonds**

 

Long-term debt and the current portion of long-term debt, summarizedbelow (in thousands of $), consists primarily of first mortgage bonds andpollution control bonds.  Interest ratesand maturities in the table below are for the amounts outstanding at December31, 2002.

 
|                |   | **Stated  Interest Rates** |   | **Weighted  Average  Interest  Rate** |   | **Maturities** |   | **Principal  Amounts** |    |
|---------------------|--------|----------------------------|--------|---------------------------------------|--------|----------------|--------|------------------------|---------|
|                |   |                       |   |                                  |   |           |   |                   |    |
| Noncurrent  portion |   | Variable - 5.90            | %      | 3.53                                  | %      | 2019-2032      |   | $                      | 328,104 |   |
| Current portion     |   | Variable - 6.00            | %      | 2.08                                  | %      | 2003-2027      |   | 288,800                |    |
|                     |        |                            |        |                                       |        |                |        |                        |         |  |

 

Under the provisions for some of LG&E’s variable-rate pollutioncontrol bonds, the bonds are subject to tender for purchase at the option ofthe holder and to mandatory tender for purchase upon the occurrence of certainevents, causing the bonds to be classified as current portion of long-term debtin the consolidated balance sheets.  Theaverage annualized interest rate for these bonds during 2002 was 1.61%.

 

LG&E’s First Mortgage Bond, 6% Series of $42.6 million is scheduledto mature in 2003.  There are no otherscheduled maturities of pollution control bonds for the five years subsequentto December 31,2002.

 

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 pollution controlbonds with an aggregate principal balance of $120 million and replaced themwith secured pollution control bonds. The new bonds and the previous bonds were all variable rate bonds, andthe maturity dates remained unchanged.

 

In September 2001, LG&E issued $10.1 million variable ratetax-exempt environmental facility revenue bonds due September 1, 2027.

 

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In January 2000, LG&E exercised its call option on its $20 million7.50% First Mortgage Bonds due July 1, 2002. The bonds were redeemed utilizing proceeds from issuance of commercialpaper.

 

In May 2000, LG&E issued $25 million variable rate pollutioncontrol bonds due May 1, 2027 and exercised its call option on $25million, 7.45%, pollution control bonds due June 15, 2015.  In August 2000, LG&E issued $83 millionin variable rate pollution control bonds due August 1, 2030 and exercisedits call option on its $83 million, 7.625%, pollution control bonds dueNovember 1, 2020.

 

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.

 

Substantially all of LG&E’s utility plants are pledged as securityfor its first mortgage bonds. LG&E’s indenture, as supplemented, provides that portions ofretained earnings will not be available for the payment of dividends on commonstock, under certain specified conditions. No portion of retained earnings isrestricted by this provision as of December 31, 2002.

 

# **Note 10 - Notes Payable**

 

LG&E participates in an intercompany money pool agreement whereinLG&E Energy can make funds available to LG&E at market based rates upto $400 million.  The balance of themoney pool loan from LG&E Energy was $193.1 million at a rate of 1.61% and$64.2 million at an average rate of 2.37%, at December 31, 2002 and 2001,respectively.  LG&E also hadoutstanding commercial paper of $30 million at an average rate of 2.54% atDecember 31, 2001.  The remaining moneypool availability at December 31, 2002, was $206.9 million.  LG&E Energy maintains facilities of $450million with affiliates to ensure funding availability for the money pool.  The outstanding balance under thesefacilities as of December 31, 2002 was $230 million, and availability of $220million remained.

 

**Note 11- Commitments and Contingencies**

 

**ConstructionProgram.**  LG&E had approximately $15.1 million ofcommitments in connection with its construction program at December 31,2002.  Construction expenditures for theyears 2003 and 2004 are estimated to total approximately $340.0 million,although all of this amount is not currently committed, including the purchaseof four jointly owned CTs, $89.0 million, and construction of NOx equipment,$34.0 million.

 

**OperatingLease.**  LG&E leases office space and accountsfor its office space lease as an operating lease.  Total lease expense for 2002,2001, and 2000, less amounts contributed by the parent company, was $1.6million, $1.1 million, and $0.9 million, respectively.  The future minimum annual lease paymentsunder this lease agreement for years subsequent to December 31, 2002, are asfollows (in thousands of $):

 
| 2003       |   | $      | 3,371  |   |
|------------|--------|--------|--------|--------|
| 2004       |   | 3,399  |   |
| 2005       |   | 3,467  |   |
| 2006       |   | 3,536  |   |
| 2007       |   | 3,607  |   |
| Thereafter |   | 29,794 |   |
| Total      |   | $      | 47,174 |   |

 

91

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In December 1999, LG&E and KU entered into an 18-year cross-borderlease of its two jointly owned combustion turbines recently installed at KU’sBrown facility (Units 6 and 7). LG&E’s obligation was defeased upon consummation of the cross-borderlease.  The transaction produced apre-tax gain of approximately $1.2 million which was recorded in other incomeon the income statement in 2000, pursuant to a Kentucky Commission order.

 

**Environmental. **The Clean Air Act imposedstringent new SO2 and NOx emission limits on electric generatingunits.  LG&E previously hadinstalled scrubbers on all of its generating units.  LG&E’s strategy for Phase II SO2 reductions, whichcommenced January 1, 2000, is to increase scrubber removal efficiency to delayadditional capital expenditures and may also include fuel switching orupgrading scrubbers.  LG&E met theNOx emission 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 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 is currently in the process of revising its SIP to require 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 the Clean AirAct directing similar NOx reductions from a number of specifically targetedgenerating units including all LG&E units. As a result of appeals to both rules, the compliance date was extendedto May 2004.  All LG&E generatingunits are subject to the May 2004 compliance date under these NOx emissionsreduction 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.  Inaddition, LG&E will incur additional operation and maintenance costs inoperating new NOx controls.  LG&Ebelieves its costs in this regard to be comparable to those of similarlysituated utilities with like generation assets.  LG&E had anticipated that such capital and operating costsare the type of costs that are eligible for recovery from customers under itsenvironmental surcharge mechanism and believed that a significant portion ofsuch costs could be recovered.  In April2001, the Kentucky Commission granted recovery of these costs for LG&E.

 

LG&E is also monitoring several other air quality issues which maypotentially impact coal-fired power plants, including the appeal of the D.C.Circuit’s remand of the EPA’s revised air quality standards for ozone andparticulate matter, measures to implement EPA’s regional haze rule, and EPA’sDecember 2000 determination to regulate mercury emissions from powerplants.  In addition, LG&E is currentlyworking with local regulatory authorities to review the effectiveness ofremedial 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 

 

92

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currently availableinformation, management estimates that it will incur additional costs of$400,000.  Accordingly, an accrual of$400,000 has been recorded in the accompanying financial statements at December31, 2002 and 2001.

 

**PurchasedPower.**LG&E has a contract for purchased power with OVECfor various Mw capacities.  Theestimated future minimum annual payments under purchased power agreements forthe years subsequent to December 31, 2002, are as follows (in thousands of $):

 
| 2003       |   | $       | 10,773  |   |
|------------|--------|---------|---------|--------|
| 2004       |   | 10,116  |    |
| 2005       |   | 10,152  |    |
| 2006       |   | 10,816  |    |
| 2007       |   | 10,816  |    |
| Thereafter |   | 184,544 |    |
| Total      |   | $       | 237,217 |   |

 

**Note 12- Jointly Owned Electric Utility Plant**

 

LG&Eowns a 75% undivided interest in Trimble County Unit 1 which the KentuckyCommission has allowed to be reflected in customer rates.

 

Of the remaining 25% ofthe Unit, IMEA owns a 12.12% undivided interest, and IMPA owns a 12.88%undivided interest.  Each company isresponsible for its proportionate ownership share of fuel cost, operation andmaintenance expenses, and incremental assets.

 

The following data represent shares of thejointly 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                                               |   | $                   | 595,747 |   |   |   |   |   |   |   |
| Accumulated  depreciation                          |   | 182,711             |    |   |   |   |   |   |   |
| Net book value                                     |   | $                   | 413,036 |   |   |   |   |   |   |   |
|                                               |   |                |    |   |   |   |   |   |   |
| Construction  work in progress  (included above)   |   | $                   | 12,867  |   |   |   |   |   |   |   |

 

93

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LG&E and KU jointly own the following combustion turbines (inthousands of $):

 
|                 |   |           |   | **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   |   | 1,711        |   | 1,499  |   | 3,210     |   |
|                 |   | Net book value |   | $            | 32,208 |   | $      | 28,474    |   | $ | 60,682 |   |
|                 |   |           |   |         |   |   |   |      |   |
| E.W. Brown 5         |   | Ownership %    |   | 53           | %      | 47     | %      | 100       | %      |
|                 |   | Mw capacity    |   | 71           |   | 63     |   | 134       |   |
|                 |   | Cost           |   | $            | 23,973 |   | $      | 21,106    |   | $ | 45,079 |   |
|                 |   | Depreciation   |   | 1,206        |   | 1,052  |   | 2,258     |   |
|                 |   | Net book value |   | $            | 22,767 |   | $      | 20,054    |   | $ | 42,821 |   |
|                 |   |           |   |         |   |   |   |      |   |
| E.W. Brown 6         |   | Ownership %    |   | 38           | %      | 62     | %      | 100       | %      |
|                 |   | Mw capacity    |   | 59           |   | 95     |   | 154       |   |
|                 |   | Cost           |   | $            | 23,696 |   | $      | 36,957    |   | $ | 60,653 |   |
|                 |   | Depreciation   |   | 1,770        |   | 4,201  |   | 5,971     |   |
|                 |   | Net book value |   | $            | 21,926 |   | $      | 32,756    |   | $ | 54,682 |   |
|                 |   |           |   |         |   |   |   |      |   |
| E.W. Brown 7         |   | Ownership %    |   | 38           | %      | 62     | %      | 100       | %      |
|                 |   | Mw capacity    |   | 59           |   | 95     |   | 154       |   |
|                 |   | Cost           |   | $            | 23,607 |   | $      | 44,792    |   | $ | 68,399 |   |
|                 |   | Depreciation   |   | 4,054        |   | 4,502  |   | 8,556     |   |
|                 |   | Net book value |   | $            | 19,553 |   | $      | 40,290    |   | $ | 59,843 |   |
|                 |   |           |   |         |   |   |   |      |   |
| Trimble 5            |   | Ownership %    |   | 29           | %      | 71     | %      | 100       | %      |
|                 |   | Mw capacity    |   | 45           |   | 110    |   | 155       |   |
|                 |   | Cost           |   | $            | 15,970 |   | $      | 39,045    |   | $ | 55,015 |   |
|                 |   | Depreciation   |   | 251          |   | 614    |   | 865       |   |
|                 |   | Net book value |   | $            | 15,719 |   | $      | 38,431    |   | $ | 54,150 |   |
|                 |   |           |   |         |   |   |   |      |   |
| Trimble 6            |   | Ownership %    |   | 29           | %      | 71     | %      | 100       | %      |
|                 |   | Mw capacity    |   | 45           |   | 110    |   | 155       |   |
|                 |   | Cost           |   | $            | 15,961 |   | $      | 39,025    |   | $ | 54,986 |   |
|                 |   | Depreciation   |   | 251          |   | 614    |   | 865       |   |
|                 |   | Net book value |   | $            | 15,710 |   | $      | 38,411    |   | $ | 54,121 |   |
|                 |   |           |   |         |   |   |   |      |   |
| Trimble CT  Pipeline |   | Ownership %    |   | 29           | %      | 71     | %      | 100       | %      |
|                 |   | Cost           |   | $            | 1,835  |   | $      | 4,475     |   | $ | 6,310 |   |
|                 |   | Depreciation   |   | 39           |   | 96     |   | 135       |   |
|                 |   | Net book value |   | $            | 1,796  |   | $      | 4,379     |   | $ | 6,175 |   |

 

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

 

**Note 13- Segments of Business and Related Information**

 

Effective December 31, 1998, LG&E adopted SFAS No. 131, *DisclosureAbout Segments of an Enterprise and Related Information*.  LG&Eis a regulated public utility engaged in the generation, transmission,distribution, and sale of electricity and the storage, distribution, and saleof natural gas.  Financial datafor business segments, follow (in thousands of $):

 

94

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|                           |   | **Electric** |    | **Gas**   |   | **Total** |   |
|--------------------------------|--------|--------------|---------|-----------|--------|-----------|--------|
| 2002                           |   |         |    |      |   |      |   |
| Operating  revenues            |   | $            | 758,491 | (a)  | $      | 267,693   |   | $ | 1,026,184 |   |
| Depreciation and  amortization |   | 90,248       |    | 15,658    |   | 105,906   |   |
| Interest income                |   | 381          |    | 76        |   | 457       |   |
| Interest expense               |   | 24,837       |    | 4,968     |   | 29,805    |   |
| Operating income  taxes        |   | 49,010       |    | 6,025     |   | 55,035    |   |
| Net income                     |   | 79,246       |    | 9,683     |   | 88,929    |   |
| Total assets                   |   | 2,105,956    |    | 455,122   |   | 2,561,078 |   |
| Construction  expenditures     |   | 195,662      |    | 24,754    |   | 220,416   |   |
|                           |   |         |    |      |   |      |   |
| 2001                           |   |         |    |      |   |      |   |
| Operating  revenues            |   | $            | 705,925 | (b)  | $      | 290,775   |   | $ | 996,700 |   |
| Depreciation and  amortization |   | 85,572       |    | 14,784    |   | 100,356   |   |
| Interest income                |   | 616          |    | 132       |   | 748       |   |
| Interest expense               |   | 31,295       |    | 6,627     |   | 37,922    |   |
| Operating income  taxes        |   | 55,527       |    | 7,925     |   | 63,452    |   |
| 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   |   |
|                           |   |         |    |      |   |      |   |
| 2000                           |   |         |    |      |   |      |   |
| Operating  revenues            |   | $            | 710,958 | (c)  | $      | 272,489   |   | $ | 983,447 |   |
| Depreciation and  amortization |   | 84,761       |    | 13,530    |   | 98,291    |   |
| Interest income                |   | 2,551        |    | 552       |   | 3,103     |   |
| Interest expense               |   | 35,604       |    | 7,614     |   | 43,218    |   |
| Operating income  taxes        |   | 57,869       |    | 6,556     |   | 64,425    |   |
| Net income                     |   | 100,395      |    | 10,178    |   | 110,573   |   |
| Total assets                   |   | 1,760,305    |    | 465,779   |   | 2,226,084 |   |
| Construction  expenditures     |   | 109,798      |    | 34,418    |   | 144,216   |   |

 

----

(a)                                  Netof provision for rate collections of $12.3 million.

(b)                                 Netof provision for rate refunds of $.7 million.

(c)                                  Netof provision for rate refunds of $2.5 million.

 

95

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**Note 14- Selected Quarterly Data (Unaudited)**

 

Selected financial data for the four quarters of2002 and 2001 are shown below.  Becauseof seasonal fluctuations in temperature and other factors, results for quartersmay fluctuate throughout the year.

 
|                                             |   | **Quarters  Ended**   |    |
|--------------------------------------------------|--------|-----------------------|---------|
|                                             |   | **March**             |    | **June** |   | **September** |   | **December** |   |
|                                             |   | **(Thousands  of $)** |    |
|                                             |   |                  |    |   |   |   |   |   |   |
| 2002                                             |   |                  |    |   |   |   |   |   |   |
| Operating revenues                               |   | $                     | 283,365 |   | $ | 222,751 |   | $ | 245,817 |   | $ | 274,251 |   |
| Net operating  income                            |   | 28,748                |    | 22,410 |   | 41,652 |   | 25,104 |   |
| Net income                                       |   | 20,943                |    | 15,256 |   | 34,204 |   | 18,526 |   |
| Net income  available for common stock           |   | 19,878                |    | 14,207 |   | 33,129 |   | 17,469 |   |
|                                             |   |                  |    |   |   |   |   |   |   |
| 2001                                             |   |                  |    |   |   |   |   |   |   |
| Operating  revenues                              |   | $                     | 313,271 |   | $ | 228,841 |   | $ | 231,885 |   | $ | 222,703 |   |
| Net operating  income (loss)(a)                  |   | (43,732               | )       | 37,624 |   | 49,092 |   | 98,789 |   |
| Net income  (loss)(a)                            |   | (54,115               | )       | 28,467 |   | 40,270 |   | 92,159 |   |
| Net income  (loss) available for common stock(a) |   | (55,413               | )       | 27,247 |   | 39,160 |   | 91,048 |   |

 

----

(a)  Lossresulted from the VDT pre-tax charge of $144.0 million in March 2001, which wasreversed in December 2001.  See Note 3.

 

**Note 15- Subsequent Events**

 

LG&E made a contribution to the pension plan of $83.1 million inJanuary 2003.

 

On March 18, 2003, the Kentucky Commission approved LG&E and KU'sjoint application for the acquisition of four CTs from an unregulatedaffiliate, LG&E Capital Corp.  Thetotal projected construction cost for the turbines, expected to be availablefor June 2004 in-service, is $227.4 million. The requested ownership share of the turbines is 63% for KU and 37% forLG&E.

 

96

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Louisville Gas andElectric CompanyREPORT OF MANAGEMENT

 

Themanagement of Louisville Gas and Electric Company is responsible for thepreparation and integrity of the financial statements and related informationincluded in this Annual Report.  Thesestatements have been prepared in accordance with accounting principlesgenerally accepted in the United States applied on a consistent basis and,necessarily, include amounts that reflect the best estimates and judgment ofmanagement.

 

LG&E’s2002 and 2001 financial statements have been audited by PricewaterhouseCoopersLLP, independent accountants, and the 2000 financial statements were audited byArthur Andersen LLP.  Management madeavailable to PricewaterhouseCoopers LLP and Arthur Andersen LLP (in prioryears) all LG&E’s financial records and related data as well as the minutesof shareholders’ and directors’ meetings.

 

Managementhas established and maintains a system of internal controls that providesreasonable assurance that transactions are completed in accordance withmanagement’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 LG&E’s internal auditors.  Management reviews and modifies its system of internal controlsin light of changes in conditions and operations, as well as in response torecommendations from the internal and external auditors.  These recommendations for the year endedDecember 31, 2002, did not identify any material weaknesses in the design andoperation of LG&E’s internal control structure.

 

Incarrying out its oversight role for the financial reporting and internalcontrols of LG&E, the Board of Directors meets regularly with LG&E’sindependent public accountants, internal auditors and management.  The Board of Directors reviews the resultsof the independent accountants’ audit of the financial statements and theiraudit procedures, and discusses the adequacy of internal accountingcontrols.  The Board of Directors alsoapproves the annual internal auditing program and reviews the activities andresults of the internal auditing function. Both the independent public accountants and the internal auditors haveaccess to the Board of Directors at any time.

 

Louisville Gas and Electric Company maintains andinternally communicates a written code of business conduct that addresses,among other items, potential conflicts of interest, compliance with laws,including those relating to financial disclosure, and the confidentiality ofproprietary information.

 

S. Bradford Rives

Senior Vice President-Finance and Controller

 

Louisville Gas and Electric Company

Louisville, Kentucky

 

97

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Louisville Gas andElectric Company and Subsidiary

REPORT OF INDEPENDENTACCOUNTANTS

 

To the Shareholders of Louisville Gas andElectric Company and Subsidiary:

 

In our opinion, the accompanying consolidatedbalance sheets and the related 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 ElectricCompany and Subsidiary (the “Company”), a wholly-owned subsidiary of LG&EEnergy Corp., at December 31, 2002 and 2001, and the results of theiroperations and their cash flows for each of the two years in the period endedDecember 31, 2002, in conformity with accounting principles generally acceptedin the United States of America.  Thesefinancial statements are the responsibility of the Company’s management; ourresponsibility is to express an opinion on these financial statements based onour audits.  We conducted our audits ofthese statements in accordance with auditing standards generally accepted inthe United States of America, which require that we plan and perform the auditto obtain reasonable assurance about whether the financial statements are freeof material misstatement.  An auditincludes examining, on a test basis, evidence supporting the amounts anddisclosures in the financial statements, assessing the accounting principlesused and significant estimates made by management, and evaluating the overallfinancial statement presentation.  Webelieve that our audits provide a reasonable basis for our opinion.

 
| /s/ PricewaterhouseCoopers LLP         |   |
|----------------------------------------|--------|
| January 21, 2003  Louisville, Kentucky |

 

98

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Louisville Gas andElectric CompanyREPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

 

To the Shareholders of Louisville Gas andElectric Company:

 

Wehave audited the accompanying balance sheet and statement of capitalization ofLouisville Gas and Electric Company (a Kentucky corporation and a wholly-ownedsubsidiary of LG&E Energy Corp.) as of December 31, 2000, and the relatedstatements of income, retained earnings, cash flows and comprehensive incomefor each of the two years in the period ended December 31, 2000.  These financial statements are theresponsibility of the Company’s management. Our responsibility is to express an opinion on these financialstatements based on our audits.

 

Weconducted our audits in accordance with auditing standards generally acceptedin the United States.  Those standardsrequire that we plan and perform the audit to obtain reasonable assurance aboutwhether the financial statements are free of material misstatement.  An audit includes examining, on a testbasis, evidence supporting the amounts and disclosures in the financialstatements.  An audit also includesassessing the accounting principles used and significant estimates made bymanagement, as well as evaluating the overall financial statementpresentation.  We believe that ouraudits provide a reasonable basis for our opinion.

 

In our opinion, the financial statements referredto above present fairly, in all material respects, the financial position ofLouisville Gas and Electric Company as of December 31, 2000, and the results ofits operations and its cash flows for each of the two years in the period endedDecember 31, 2000, in conformity with accounting principles generally acceptedin the United States.

 

Our audits were made for the purpose of forming an opinion on the basicfinancial statements taken as a whole. The schedule listed under Item 14(a)2 ispresented for purposes of complying with the Securities and ExchangeCommission’s rules and is not part of the basic financial statements.  This schedule has been subjected to theauditing procedures applied in the audit of the basic financial statements and,in our opinion, fairly states in all material respects the financial datarequired to be set forth therein in relation to the basic financial statementstaken as a whole.

 

 
| Louisville, Kentucky  January 26, 2001 |   | Arthur Andersen LLP |
|----------------------------------------|--------|---------------------|

 

 

THIS IS A COPY OFA PREVIOUSLY ISSUED REPORT OF ARTHUR ANDERSEN LLP (“ANDERSEN”) RELATING TO APRIOR PERIOD FOR WHICH ANDERSEN WAS ENGAGED AS INDEPENDENT PUBLIC ACCOUNTANTS.THE REPORT HAS NOT BEEN REISSUED BY ANDERSEN.

 

99

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INDEX OF ABBREVIATIONS

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

 

100

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

 

101

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Kentucky UtilitiesCompany and Subsidiary

Consolidated Statementsof Income

(Thousands of $)

 
|                                                                                                                              |   | **Years  Ended December 31** |    |
|-----------------------------------------------------------------------------------------------------------------------------------|--------|------------------------------|---------|
|                                                                                                                              |   | **2002**                     |    | **2001** |   | **2000** |   |
|                                                                                                                              |   |                         |    |   |   |   |   |
| OPERATING  REVENUES:                                                                                                              |   |                         |    |   |   |   |   |
| Electric (Note  1)                                                                                                                |   | $                            | 875,192 |   | $ | 860,426 |   | $ | 851,941 |   |
| Provision for  rate collections (refunds) (Note 3)                                                                                |   | 13,027                       |    | (954 | ) | — |   |
| Total operating  revenues                                                                                                         |   | 888,219                      |    | 859,472 |   | 851,941 |   |
|                                                                                                                              |   |                         |    |   |   |   |   |
| OPERATING  EXPENSES:                                                                                                              |   |                         |    |   |   |   |   |
| Fuel for  electric generation                                                                                                     |   | 250,117                      |    | 236,985 |   | 219,923 |   |
| Power purchased                                                                                                                   |   | 157,955                      |    | 157,161 |   | 166,918 |   |
| Other operation  expenses                                                                                                         |   | 144,118                      |    | 118,359 |   | 108,072 |   |
| Non-recurring  charge (Note 3)                                                                                                    |   | —                       |    | 6,867 |   | — |   |
| Maintenance                                                                                                                       |   | 62,909                       |    | 57,021 |   | 61,643 |   |
| Depreciation and  amortization (Note 1)                                                                                           |   | 95,462                       |    | 90,299 |   | 98,256 |   |
| Federal and state  income taxes (Note 7)                                                                                          |   | 54,032                       |    | 57,482 |   | 51,963 |   |
| Property and  other taxes                                                                                                         |   | 14,983                       |    | 13,928 |   | 17,030 |   |
| Total operating  expenses                                                                                                         |   | 779,576                      |    | 738,102 |   | 723,805 |   |
|                                                                                                                              |   |                         |    |   |   |   |   |
| Net operating  income                                                                                                             |   | 108,643                      |    | 121,370 |   | 128,136 |   |
|                                                                                                                              |   |                         |    |   |   |   |   |
| Other income –  net (Note 8)                                                                                                 |   | 10,429                       |    | 8,932 |   | 6,843 |   |
| Interest charges                                                                                                                  |   | 25,688                       |    | 34,024 |   | 39,455 |   |
|                                                                                                                              |   |                         |    |   |   |   |   |
| Net income  before cumulative effect of a change in accounting principle                                                          |   | 93,384                       |    | 96,278 |   | 95,524 |   |
|                                                                                                                              |   |                         |    |   |   |   |   |
| Cumulative  effect of a change in accounting principle-accounting for   Derivative instruments and hedging activities, net of tax |   | —                       |    | 136 |   | — |   |
|                                                                                                                              |   |                         |    |   |   |   |   |
| Net income                                                                                                                        |   | 93,384                       |    | 96,414 |   | 95,524 |   |
|                                                                                                                              |   |                         |    |   |   |   |   |
| Preferred stock  dividends                                                                                                        |   | 2,256                        |    | 2,256 |   | 2,256 |   |
|                                                                                                                              |   |                         |    |   |   |   |   |
| Net income  available for common stock                                                                                            |   | $                            | 91,128  |   | $ | 94,158 |   | $ | 93,268 |   |

 

Consolidated Statementsof Retained Earnings

(Thousands of $)

 
|                                                  |   | **Years  Ended December 31** |    |
|-------------------------------------------------------|--------|------------------------------|---------|
|                                                  |   | **2002**                     |    | **2001** |   | **2000** |   |
|                                                  |   |                         |    |   |   |   |   |
| Balance January  1                                    |   | $                            | 410,896 |   | $ | 347,238 |   | $ | 329,470 |   |
| Add net income                                        |   | 93,384                       |    | 96,414 |   | 95,524 |   |
|                                                  |   | 504,280                      |    | 443,652 |   | 424,994 |   |
|                                                  |   |                         |    |   |   |   |   |
| 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 |   | 75,500 |   |
|                                                  |   | 2,256                        |    | 32,756 |   | 77,756 |   |
|                                                  |   |                         |    |   |   |   |   |
| Balance December  31                                  |   | $                            | 502,024 |   | $ | 410,896 |   | $ | 347,238 |   |

 

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

 

102

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Kentucky Utilities Companyand Subsidiary

Consolidated Statementsof Comprehensive Income

(Thousands of $)

 
|                                                                                                                      |   | **Years  Ended December 31** |   |
|---------------------------------------------------------------------------------------------------------------------------|--------|------------------------------|--------|
|                                                                                                                      |   | **2002**                     |   | **2001** |   | **2000** |   |
|                                                                                                                      |   |                         |   |   |   |   |   |
| Net income                                                                                                                |   | $                            | 93,384 |   | $ | 96,414 |   | $ | 95,524 |   |
|                                                                                                                      |   |                         |   |   |   |   |   |
| Cumulative  effect of change in accounting principle – Accounting for derivative  instruments and hedging activities |   | —                       |   | 2,647 |   | — |   |
|                                                                                                                      |   |                         |   |   |   |   |   |
| Losses on  derivative instruments and hedging activities                                                                  |   | (2,647                       | )      | — |   | — |   |
|                                                                                                                      |   |                         |   |   |   |   |   |
| Additional  minimum pension liability adjustment (Note 6)                                                                 |   | (17,543                      | )      | — |   | — |   |
|                                                                                                                      |   |                         |   |   |   |   |   |
| Income tax  benefit (expense) related to items of other comprehensive income                                              |   | 8,140                        |   | (1,059 | ) | — |   |
|                                                                                                                      |   |                         |   |   |   |   |   |
| Other  comprehensive (loss) income, net of tax                                                                            |   | (12,050                      | )      | 1,588 |   | — |   |
|                                                                                                                      |   |                         |   |   |   |   |   |
| Comprehensive  income                                                                                                     |   | $                            | 81,334 |   | $ | 98,002 |   | $ | 95,524 |   |

 

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

 

103

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Kentucky UtilitiesCompany and Subsidiary

Consolidated BalanceSheets

(Thousands of $)

 
|                                                                    |   | **December  31** |      |
|-------------------------------------------------------------------------|--------|------------------|-----------|
|                                                                    |   | **2002**         |      | **2001** |   |
|                                                                    |   |             |      |   |   |
| ASSETS:                                                                 |   |             |      |   |   |
| Utility plant,  at original cost (Note 1)                               |   | $                | 3,089,529 |   | $ | 2,960,818 |   |
| Less:  reserve for depreciation                                    |   | 1,536,658        |      | 1,457,754 |   |
|                                                                    |   | 1,552,871        |      | 1,503,064 |   |
| Construction  work in progress                                          |   | 191,233          |      | 103,402 |   |
|                                                                    |   | 1,744,104        |      | 1,606,466 |   |
|                                                                    |   |             |      |   |   |
| Other property  and investments - less reserve of $130 in 2002 and 2001 |   | 14,358           |      | 9,629 |   |
|                                                                    |   |             |      |   |   |
| Current assets:                                                         |   |             |      |   |   |
| Cash and  temporary cash investments (Note 1)                           |   | 5,391            |      | 3,295 |   |
| Accounts  receivable-less reserve of $800 in 2002 and 2001              |   | 49,588           |      | 45,291 |   |
| Materials and  supplies - at average cost:                              |   |             |      |   |   |
| Fuel  (predominantly coal) (Note 1)                                     |   | 46,090           |      | 43,382 |   |
| Other                                                                   |   | 26,408           |      | 26,188 |   |
|                                                                    |   |             |      |   |   |
| Prepayments and  other                                                  |   | 6,584            |      | 4,942 |   |
|                                                                    |   | 134,061          |      | 123,098 |   |
|                                                                    |   |             |      |   |   |
| Deferred debits  and other assets:                                      |   |             |      |   |   |
| Unamortized debt  expense (Note 1)                                      |   | 4,991            |      | 4,316 |   |
| Regulatory  assets (Note 3)                                             |   | 65,404           |      | 66,467 |   |
| Other                                                                   |   | 35,465           |      | 16,926 |   |
|                                                                    |   |             |      |   |   |
|                                                                    |   | 105,860          |      | 87,709 |   |
|                                                                    |   | $                | 1,998,383 |   | $ | 1,826,902 |   |
|                                                                    |   |             |      |   |   |
| CAPITAL AND  LIABILITIES:                                               |   |             |      |   |   |
| Capitalization  (see statements of capitalization):                     |   |             |      |   |   |
| Common equity                                                           |   | $                | 814,107   |   | $ | 735,029 |   |
| Cumulative  preferred stock                                             |   | 40,000           |      | 40,000 |   |
| Long-term debt  (Note 9)                                                |   | 346,562          |      | 434,506 |   |
|                                                                    |   |             |      |   |   |
|                                                                    |   | 1,200,669        |      | 1,209,535 |   |
|                                                                    |   |             |      |   |   |
| Current  liabilities:                                                   |   |             |      |   |   |
| Current portion  of long-term debt (Note 9)                             |   | 153,930          |      | 54,000 |   |
| Notes payable to  parent (Note 10)                                      |   | 119,490          |      | 47,790 |   |
| Accounts payable                                                        |   | 95,374           |      | 85,149 |   |
| Accrued taxes                                                           |   | 4,955            |      | 20,520 |   |
| Other                                                                   |   | 21,442           |      | 22,150 |   |
|                                                                    |   |             |      |   |   |
|                                                                    |   | 395,191          |      | 229,609 |   |
|                                                                    |   |             |      |   |   |
| Deferred credits  and other liabilities:                                |   |             |      |   |   |
| Accumulated  deferred income taxes (Notes 1 and 7)                      |   | 241,184          |      | 239,204 |   |
| Investment tax  credit, in process of amortization                      |   | 8,500            |      | 11,455 |   |
| Accumulated  provision for pensions and related benefits (Note 6)       |   | 110,927          |      | 91,235 |   |
| Regulatory  liabilities (Note 3)                                        |   | 29,876           |      | 33,889 |   |
| Other                                                                   |   | 12,036           |      | 11,975 |   |
|                                                                    |   |             |      |   |   |
|                                                                    |   | 402,523          |      | 387,758 |   |
| Commitments and  contingencies (Note 11)                                |   |             |      |   |   |
|                                                                    |   | $                | 1,998,383 |   | $ | 1,826,902 |   |

 

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

 

104

----

 

Kentucky UtilitiesCompany and SubsidiaryConsolidated Statements of Cash Flows(Thousands of $)

 
|                                                      |   | **Years  Ended December 31** |   |
|-----------------------------------------------------------|--------|------------------------------|--------|
|                                                      |   | **2002**                     |   | **2001** |   | **2000** |   |
|                                                      |   |                         |   |   |   |   |   |
| CASH FLOWS FROM  OPERATING ACTIVITIES:                    |   |                         |   |   |   |   |   |
| Net income                                                |   | $                            | 93,384 |   | $ | 96,414 |   | $ | 95,524 |   |
| Items not  requiring cash currently:                      |   |                         |   |   |   |   |   |
| Depreciation and  amortization                            |   | 95,462                       |   | 90,299 |   | 98,256 |   |
| Deferred income  taxes - net                              |   | (2,038                       | )      | (12,088 | ) | (2,449 | ) |
| Investment tax  credit - net                              |   | (2,955                       | )      | (3,446 | ) | (3,674 | ) |
| Other                                                     |   | (1,267                       | )      | 11,776 |   | (8,136 | ) |
| Change in  certain net current assets:                    |   |                         |   |   |   |   |   |
| Accounts  receivable                                      |   | (8,497                       | )      | 28 |   | (1,870 | ) |
| Materials and  supplies                                   |   | (2,928                       | )      | (31,263 | ) | 18,131 |   |
| Accounts payable                                          |   | 10,225                       |   | 8,810 |   | (60,774 | ) |
| Accrued taxes                                             |   | (15,565                      | )      | 898 |   | 9,120 |   |
| Prepayments and  other                                    |   | (2,350                       | )      | (6,033 | ) | 850 |   |
| Sale of accounts  receivable (Note 1)                     |   | 4,200                        |   | 45,100 |   | — |   |
| Other                                                     |   | 8,086                        |   | (12,364 | ) | 31,272 |   |
|                                                      |   |                         |   |   |   |   |   |
| Net cash flows  from operating activities                 |   | 175,757                      |   | 188,131 |   | 176,250 |   |
|                                                      |   |                         |   |   |   |   |   |
| CASH FLOWS FROM  INVESTING ACTIVITIES:                    |   |                         |   |   |   |   |   |
| Proceeds from  sales of securities                        |   | —                       |   | 3,480 |   | — |   |
| Construction  expenditures                                |   | (237,909                     | )      | (142,425 | ) | (100,328 | ) |
| Net cash flows  from investing activities                 |   | (237,909                     | )      | (138,945 | ) | (100,328 | ) |
|                                                      |   |                         |   |   |   |   |   |
| CASH FLOWS FROM  FINANCING ACTIVITIES:                    |   |                         |   |   |   |   |   |
| Short-term  borrowings and repayments                     |   | 71,700                       |   | (13,449 | ) | 61,239 |   |
| Retirement of  long-term debt                             |   | (133,930                     | )      | — |   | (74,784 | ) |
| Issuance of  long-term debt                               |   | 128,734                      |   | — |   | 12,900 |   |
| Additional  paid-in capital                               |   | —                       |   | — |   | 15,000 |   |
| Payment of  dividends                                     |   | (2,256                       | )      | (32,756 | ) | (96,756 | ) |
| Net cash flows  used for financing activities             |   | 64,248                       |   | (46,205 | ) | (82,401 | ) |
|                                                      |   |                         |   |   |   |   |   |
| Change in cash  and temporary cash investments            |   | 2,096                        |   | 2,981 |   | (6,479 | ) |
|                                                      |   |                         |   |   |   |   |   |
| Cash and  temporary cash investments at beginning of year |   | 3,295                        |   | 314 |   | 6,793 |   |
|                                                      |   |                         |   |   |   |   |   |
| Cash and  temporary cash investments at end of year       |   | $                            | 5,391  |   | $ | 3,295 |   | $ | 314 |   |
|                                                      |   |                         |   |   |   |   |   |
| Supplemental  disclosures of cash flow information:       |   |                         |   |   |   |   |   |
| Cash paid during  the year for:                           |   |                         |   |   |   |   |   |
| Income taxes                                              |   | $                            | 59,580 |   | $ | 72,432 |   | $ | 49,871 |   |
| Interest on  borrowed money                               |   | 37,866                       |   | 39,829 |   | 35,196 |   |

 

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

 

105

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Kentucky UtilitiesCompany and Subsidiary

Consolidated Statementsof Capitalization

(Thousands of $)

 
|                                                                                            |   | **December  31** |    |
|-------------------------------------------------------------------------------------------------|--------|------------------|---------|
|                                                                                            |   | **2002**         |    | **2001** |   |
|                                                                                            |   |             |    |   |   |
| COMMON EQUITY:                                                                                  |   |             |    |   |   |
| Common stock,  without par value -  authorized 80,000,000 shares, outstanding 37,817,878 shares |   | $                | 308,140 |   | $ | 308,140 |   |
| Additional  paid-in-capital                                                                     |   | 15,000           |    | 15,000 |   |
| Accumulated  other comprehensive income                                                         |   | (10,462          | )       | 1,588 |   |
| Other                                                                                           |   | (595             | )       | (595 | ) |
| Retained  earnings                                                                              |   | 502,024          |    | 410,896 |   |
|                                                                                            |   |             |    |   |   |
|                                                                                            |   | 814,107          |    | 735,029 |   |
|                                                                                                 |        |                  |         |  |  |  |  |

 

CUMULATIVE PREFERRED STOCK:

 
|                                                                               |   | **Shares  Outstanding** |   | **Current  Redemption Price** |   |    |      |    |   |
|------------------------------------------------------------------------------------|--------|-------------------------|--------|-------------------------------|--------|---------|-----------|---------|--------|
|                                                                               |   |                    |   |                          |   |    |      |    |   |
| Without par  value, 5,300,000 shares authorized -  4.75% series, $100 stated value |   |                    |   |                          |   |    |      |    |   |
| Redeemable on 30  days notice by KU                                                |   | 200,000                 |   | $                             | 101.00 |    | 20,000    |    | 20,000 |   |
| 6.53% series,  $100 stated value                                                   |   | 200,000                 |   | Not redeemable                |   | 20,000  |      | 20,000  |   |
|                                                                               |   |                    |   |                          |   |    |      |    |   |
|                                                                               |   |                    |   |                          |   | 40,000  |      | 40,000  |   |
|                                                                               |   |                    |   |                          |   |    |      |    |   |
| LONG-TERM DEBT  (Note 9);                                                          |   |                    |   |                          |   |    |      |    |   |
| First mortgage  bonds -  Q due June 15, 2003, 6.32%                                |   |                    |   |                          |   | 62,000  |      | 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  |      | 33,000  |   |
| Pollution  control series:                                                         |   |                    |   |                          |   |    |      |    |   |
| 1B due February  1, 2018, 6.25%                                                    |   |                    |   |                          |   | —  |      | 20,930  |   |
| 2B due February  1, 2018, 6.25%                                                    |   |                    |   |                          |   | —  |      | 2,400   |   |
| 3B due February  1, 2018, 6.25%                                                    |   |                    |   |                          |   | —  |      | 7,200   |   |
| 4B due February  1, 2018, 6.25%                                                    |   |                    |   |                          |   | —  |      | 7,400   |   |
| 8, due September  15, 2016, 7.45%                                                  |   |                    |   |                          |   | —  |      | 96,000  |   |
| 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  |      | —  |   |
| 13, due February  1, 2032, variable%                                               |   |                    |   |                          |   | 2,400   |      | —  |   |
| 14, due February  1, 2032, variable%                                               |   |                    |   |                          |   | 7,400   |      | —  |   |
| 15, due February  1, 2032, variable%                                               |   |                    |   |                          |   | 7,200   |      | —  |   |
| 16, due October  1, 2032, variable%                                                |   |                    |   |                          |   | 96,000  |      | —  |   |
| Long-term debt  marked to market (Note 4)                                          |   |                    |   |                          |   | 15,662  |      | 3,676   |   |
|                                                                               |   |                    |   |                          |   |    |      |    |   |
| Total bonds  outstanding                                                           |   |                    |   |                          |   | 500,492 |      | 488,506 |   |
|                                                                               |   |                    |   |                          |   |    |      |    |   |
| Less current  portion of long-term debt                                            |   |                    |   |                          |   | 153,930 |      | 54,000  |   |
|                                                                               |   |                    |   |                          |   |    |      |    |   |
| Long-term debt                                                                     |   |                    |   |                          |   | 346,562 |      | 434,506 |   |
|                                                                               |   |                    |   |                          |   |    |      |    |   |
| Total capitalization                                                               |   |                    |   |                          |   | $       | 1,200,669 |    | $      | 1,209,535 |   |
|                                                                                    |        |                         |        |                               |        |         |           |         |        |  |  |  |

 

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

 

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Kentucky UtilitiesCompany and SubsidiaryNotes to Consolidated Financial Statements

 

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

 

KU, a subsidiary of LG&E Energy and anindirect subsidiary of Powergen and E.ON, is a regulated public utility engagedin the generation, transmission, distribution, and sale of electricenergy.  LG&E Energy is anexempt public utility holding company with wholly owned subsidiaries includingLG&E, KU, Capital Corp., LEM, and LG&E Services.  All of the KU’s Common Stock is held byLG&E Energy.  KU has one whollyowned consolidated subsidiary, KU R.

 

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 utility holding companiesunder PUHCA.  No costs associated withthese acquisitions nor any of the effects of purchase accounting have beenreflected in the financial statements of KU.

 

Certain reclassification entries have been made to the previous year’sfinancial statements to conform to the 2002 presentation with no impact on thebalance sheet totals or previously reported income.

 

**Utility Plant.**  KU’s utility plant is statedat original 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. KU has not recorded any significant allowance for funds used duringconstruction.

 

The cost of plant retired or disposed of in thenormal course of business is deducted from plant accounts and such cost, plusremoval expense less 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 and Amortization.**  Depreciationis provided on the straight-line method over the estimated service lives ofdepreciable plant. Pursuant to a final order of the Kentucky Commission datedDecember 3, 2001, KU implemented new deprecation rates effective January 1,2001.  The amounts provided wereapproximately 3.1% in 2002, 3.1% in2001 and 3.5% in 2000, of average depreciable plant. Of the amount provided for depreciation at December 31, 2002, 2001 and2000, respectively, approximately 0.7% was related to the retirement, removaland disposal costs of long lived assets.

 

**Cash and Temporary Cash Investments.**  KUconsiders all highly liquid debt instruments purchased with a maturity of threemonths or less to be cash equivalents. Temporary cash investments are carried at cost, which approximates fairvalue.

 

**Fuel Inventories.**  Fuel inventories of $46.1million and $43.4 million at December 31, 2002 and 2001, respectively, areincluded in Fuel in the balance sheet. The inventory is accounted for using the average-cost method.

 

**Financial Instruments.**  KU usesover-the-counter interest-rate swap agreements to hedge its exposure tointerest rates.  Gains and losses oninterest-rate swaps used to hedge interest rate risk are reflected in interestcharges monthly.  See Note 4 - Financial Instruments.

 

107

----

 

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

 

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

 

**Investment Tax Credits.** 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 onservice rendered to customers through month-end.  KU accrues an estimate for unbilled revenues from each meterreading date to the end of the accounting period.  The unbilled revenue estimates included inaccounts receivable were approximately $36.4 million and $33.4 million atDecember 31, 2002, and 2001, respectively. KU recorded electric revenues that resulted from sales to a relatedparty, LG&E, of $34.6 million, $31.1 million and $22.1 million for yearsended December 31, 2002, 2001 and 2000, respectively.  See Note 3, Rates and Regulatory Matters.

 

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

 

**Management’s Use of Estimates.**  Thepreparation of financial statements in conformity with generally acceptedaccounting principles requires management to make estimates and assumptionsthat affect the reported assets and liabilities and disclosure of contingentitems at the date of the financial statements and the reported amounts ofrevenues and expenses during the reporting period.  Actual results could differ from those estimates.  See Note 11, Commitments and Contingencies, for a further discussion.

 

**AccountsReceivable Securitization.**SFAS No. 140, *Accounting for Transfers and Servicingof Financial Assets and Extinguishments of Liabilities*, revises thestandards for accounting for securitizations and other transfers of financialassets and collateral and requires certain disclosures, and provides accountingand reporting standards for transfers and servicing of financial assets andextinguishments of liabilities. SFAS No. 140 was adopted in the first quarterof 2001, when KU entered into an accounts receivable securitizationtransaction.

 

On February 6, 2001, KU implemented an accounts receivable securitizationprogram.  The purpose of this program isto enable KU to accelerate the receipt of cash from the collection of retailaccounts receivable, thereby reducing dependence upon more costly sources ofworking capital. The securitization program allows for a percentage of eligiblereceivables to be sold.  Eligiblereceivables are generally all receivables associated with retail sales thathave standard terms and are not past due. KU is able to terminate this program at any time without penalty. Ifthere is a significant deterioration in the payment record of the receivablesby the retail customers or if KU fails to meet certain covenants regarding theprogram, the program may terminate at the election of the financialinstitutions.  In this case, paymentsfrom retail customers would first be used to repay the financial institutionsparticipating in the program, and would then be available for use by KU.

 

As part of the program, KU sold retail accounts receivables to a whollyowned subsidiary, KU R. Simultaneously, KU R entered into two separatethree-year accounts receivable securitization facilities with two financialinstitutions and their affiliates whereby KU R can sell, on a revolving basis,an undivided interest in certain of its receivables and receive up to $50million from an unrelated third party purchaser.  The effective cost of the receivables programs is comparable toKU’s lowest cost source of capital, and is based on prime rated commercialpaper. KU retains servicing rights of the sold receivables through two separateservicing agreements with the third party purchaser.  KU has obtained an opinion from independent legal counsel 

 

108

----

 

indicating these transactions qualify as a true sale of receivables.  As of December 31, 2002, the outstandingprogram balance was $49.3 million.  KUis considering unwinding its accounts receivable securitization arrangementsinvolving KU R during 2003.

 

The allowance for doubtful accounts associated with the eligiblesecuritized receivables was $520,000 at December 31, 2002.  This allowance is based on historicalexperience of KU. Each securitization facility contains a fully funded reservefor uncollectible receivables.

 

**New Accounting Pronouncements.**  Thefollowing accounting pronouncements were issued that affected KU in 2002:

 

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 is January 1,2003.  Management has calculated theimpact of SFAS No. 143 and the recently released FERC NOPR No. RM02-7, *Accounting,Financial Reporting, and Rate Filing Requirements for Asset RetirementObligations*.  As of January1, 2003, KU recorded asset retirement obligation (ARO) assets in the amount of$8.6 million and liabilities in the amount of $18.5 million.  KU also recorded a cumulative effectadjustment in the amount of $9.9 million to reflect the accumulateddepreciation and accretion of ARO assets at the transition date less theamounts previously accrued under reglatory depreciation. 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 $888,000offsetting removal costs previously accrued under regulatory accounting inexcess of amounts allowed under SFAS No. 143.

 

KU also expects to record ARO accretion expense of approximately $1.2million, ARO depreciation expense of approximately $176,000 and an offsettingregulatory credit in the income statement of approximately $1.4 million in2003, pursuant to regulatory treatment prescribed under SFAS No. 71, *Accountingfor the Effects of Certain Types of Regulation*.  The accretion, depreciation and regulatorycredit will be annual adjustments.  SFASNo. 143 will have no impact on the results of the operation of KU.

 

KU’s asset retirement obligations are primarily related to the finalretirement of generating units.  KUtransmission and distribution lines largely operate under perpetual propertyeasement agreements which do not generally require restoration upon removal ofthe property.  Therefore, under SFAS No.143, no material asset retirement obligations will be recorded for transmissionand distribution assets.

 

KU adopted EITF No. 98-10, *Accounting for Energy Trading and Risk ManagementActivities*, effective January 1, 1999.  This pronouncement required that energy trading contracts bemarked to market on the balance sheet, with the gains and losses shown net inthe income statement.  In October 2002,the Emerging Issues Task Force reached a consensus to rescind EITF 98-10.  The effective date for the full rescissionwill be for fiscal periods beginning after December 15, 2002.  With the recession of EITF No. 98-10, energytrading contracts that do not also meet the definition of a derivative underSFAS No. 133 must be accounted for as executory contracts.  Contracts previously recorded at fair valueunder EITF No. 98-10 that are not also derivatives under SFAS No. 133 must berestated to historical cost through a cumulative effect adjustment.  KU does not expect the rescission of thisstandard to have a material impact on financial position or results ofoperations.

 

In January 2003, the Financial Accounting Standards Board issuedFinancial Accounting Standards Board 

 

109

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Interpretation No. 46, *Consolidation of Variable Interest Entities*,an Interpretation of ARB No. 51 (FIN 46). FIN 46 requires certain variable interest entities to be consolidated 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 is 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 be appliedfor the first interim or annual period beginning after June 15, 2003.  KU does not expect the adoption of thisstandard to have any impact on the financial position or results of operations.

# ** **

# **Note 2 – Mergers and Acquisitions**

 

On July 1, 2002,E.ON completed its acquisition of Powergen, including LG&E Energy, forapproximately £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, KU also became an indirect subsidiary ofE.ON.  KU has continued its separateidentity and serves customers in Kentucky, Virginia and Tennessee under itsexisting names.  The preferred stock anddebt securities of KU were not affected by this transaction and the utilitiescontinue to file SEC reports.  Followingthe acquisition, E.ON became, and Powergen remained, a registered holdingcompany under PUHCA.  KU, as asubsidiary of a registered holding company, is subject to additional regulationsunder PUHCA.  As contemplated 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.

 

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 and Regulatory Matters**

 

Accounting for the regulated utility business conforms with generallyaccepted accounting principles as applied to regulated public utilities and asprescribed by FERC, the Kentucky Commission and the Virginia Commission.  KU is subject to SFAS No. 71, *Accountingfor the Effects of Certain Types of Regulation*, under which certaincosts that would otherwise be charged to expense are deferred as regulatoryassets based on expected recovery from customers in future rates.  Likewise, certain credits that wouldotherwise be reflected as income are deferred as regulatory liabilities basedon expected return to customers in future rates.  KU’s current or expected recovery of deferred costs and expectedreturn of deferred credits is generally based on specific ratemaking decisionsor precedent for each item.  Thefollowing regulatory assets and liabilities were included in KU’s balancesheets as of December 31 (in thousands of $):

 
|                          |   | **2002** |   | **2001** |   |
|-------------------------------|--------|----------|--------|----------|--------|
|                          |   |     |   |     |   |
| VDT costs                     |   | $        | 38,375 |     | $      | 48,811 |   |
| Unamortized loss  on bonds    |   | 9,456    |   | 6,142    |   |
| LG&E/KU  merger costs     |   | 2,046    |   | 6,139    |   |
| One utility  costs            |   | 873      |   | 4,365    |   |
| ESM provision                 |   | 13,500   |   | —   |   |
| Other                         |   | 1,154    |   | 1,010    |   |
| Total regulatory  assets      |   | 65,404   |   | 66,467   |   |
|                          |   |     |   |     |   |
| Deferred income  taxes - net  |   | (28,854  | )      | (32,872  | )      |
| Other                         |   | (1,022   | )      | (1,017   | )      |
| Total regulatory  liabilities |   | (29,876  | )      | (33,889  | )      |
| Regulatory  assets - net      |   | $        | 35,528 |     | $      | 32,578 |   |

 

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**KentuckyCommission Settlement Order - VDT Costs.**During the firstquarter 2001, KU recorded a $64 million charge for a workforce reductionprogram.  Primary components of thecharge were separation benefits, enhanced early retirement benefits, and healthcare benefits.  The result of thisworkforce reduction was the elimination of approximately 300 positions,accomplished primarily through a voluntary enhanced severance program.

 

On June 1, 2001, KU filed an application (VDT case) with the 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 the other casesinvolving depreciation rates and ESM with all intervening parties.  The settlement agreement was approved by theKentucky Commission on December 3, 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 $64 millionrepresented all employees who had accepted a voluntary enhanced severanceprogram.  Some employees rescinded theirparticipation in the voluntary enhanced severance program and, along with thenon-recurring charge of $6.9 million for FERC and Virginia jurisdictions,thereby decreasing the original charge of the regulatory asset from $64 millionto $54 million. The settlement will also reduce revenues approximately $11million through a surcredit on future bills to customers over the same fiveyear period.  The surcredit representsnet savings stipulated by KU.  Theagreement also established KU’s new depreciation rates in effect December 2001,retroactive to January 1, 2001.  The newdepreciation rates decreased depreciation expense by $6.0 million in 2001.

 

**PUHCA.** LG&E Energy was purchased by Powergen on December 11, 2000.  Effective July 1, 2002, Powergen wasacquired by E.ON, which became a registered holding company under PUHCA.  As a result, E.ON, its utility subsidiaries,including KU, and certain of its non-utility subsidiaries are subject toextensive regulation by the SEC under PUHCA with respect to issuances and salesof securities, acquisitions and sales of certain utility properties, andintra-system sales of certain goods and services.  In addition, PUHCA generally limits the ability of registeredholding companies to acquire additional public utility systems and to acquireand retain businesses unrelated to the utility operations of the holdingcompany.  KU believes that it hasadequate authority (including financing authority) under existing SEC ordersand regulations to conduct its business.  KU will seek additional authorization when necessary.

 

**EnvironmentalCost Recovery.**  InJune 2000, the Kentucky Commission approved KU’s application for a CCN toconstruct up to four 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 KU’s proposed plan for construction was “reasonable,cost-effective and will not result in the wasteful duplication of facilities.”  In October 2000, KU filed an applicationwith the Kentucky Commission to amend its Environmental Compliance Plan toreflect the addition of the proposed NOx reduction technology projects and toamend its ECR Tariff to include an overall rate of return on capitalinvestments.  Approval of KU’sapplication in April 2001 allowed KU to begin to recover the costs associatedwith these new projects, subject to Kentucky Commission oversight during normalsix-month and two-year reviews.

 

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In August 2002, KU filed an application with the Kentucky Commission toamend its compliance plan to allow recovery of the cost of a new and additionalenvironmental compliance facility.  Theestimated capital cost of the additional facilities is $17.3 million.  The Kentucky Commission conducted a publichearing on the case on December 20, 2002, final briefs were filed on January15, 2003, and a final order was issued February 11, 2003. The final orderapproved recovery of the new environmental compliance facility totaling $17.3million.  Cost recovery through theenvironmental surcharge of the approved project will begin with bills renderedin April 2003.

 

**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 successiveperiods.  KU made its second ESMfiling on March 1, 2002 for the calendar year 2001 reporting period.  KU is in the process of refunding $1 millionto customers for the 2001 reporting period. KU estimated that the rate of returnwill fall below the lower limit, subject to Kentucky Commission approval, forthe year ended December 31, 2002.   The2002 financial statements include an accrual to reflect the earnings deficiencyof $13.5 million to be recovered from customers commencing in April 2003.

 

On November 27, 2002, KU filed a revised ESM tariff which proposedcontinuance of the existing ESM through December 2005.  The Kentucky Commission issued an ordersuspending the ESM tariff one day making the effective date January 2,2003.  In addition, the KentuckyCommission is conducting a management audit to review the ESM plan and reassessits reasonableness in 2003.  KU andinterested parties will have the opportunity to provide recommendations formodification and continuance of the ESM or other forms of alternative orincentive regulation.

 

# **DSM.**In May 2001, the Kentucky Commission approved a plan that would expandLG&E’s current DSM programs into the service territory served by KU.  The filing included a rate mechanism thatprovided for concurrent recovery of DSM costs, provided an incentive forimplementing DSM programs, and recovered revenues from lost sales associatedwith the DSM program based on program planning engineering estimates andpost-implementation evaluation.

 

**FAC. ** KUemploys a FAC mechanism which allows KU to recover from customers’ fuel costsassociated with retail electric sales.  InJuly 1999, the Kentucky Commission issued a series of orders requiring KU torefund approximately $10.1 million resulting from reviews of the FAC fromNovember 1994 to October 1998.  InAugust 1999, after a rehearing request by KU, the Kentucky Commission issued afinal order that reduced the refund obligation to $6.7 million ($5.8 million ona Kentucky jurisdictional basis) from the original order amount of $10.1million.  KU implemented the refund fromOctober 1999 through September 2000. Both KU and the KIUC appealed the order.   Pending a decision on thisappeal, a comprehensive settlement was reached by all parties and approved bythe Kentucky Commission on May 17, 2002. Thereunder, KU agreed to credit its fuel clause in the amount of$954,000 (refund made in June and July 2002), and the parties agreed on aprospective interpretation of the state’s FAC regulation to ensure consistentand mutually acceptable application on a going-forward basis.

 

In December 2002, the Kentucky Commission initiated a two year reviewof the operation of KU’s FAC for the period November 2000 through October2002.  Testimony in the review case wasfiled on January 20, 2003 and a public hearing was held February 18, 2003.  Issues addressed at that time included theestablishment of the 

 

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current base fuel factor to be included in KU’s base rates,verification of proper treatment of purchased power costs during unit outages,and compliance with fuel procurement policies and practices.

 

**KentuckyCommission Administrative Case for Affiliate Transactions.**InDecember 1997, the Kentucky Commission opened Administrative Case No. 369 toconsider Kentucky Commission policy regarding cost allocations, affiliatetransactions and codes of conduct governing the relationship between utilitiesand their non-utility operations and affiliates.  The Kentucky Commission intended to address two major areas inthe proceedings: the tools and conditions needed to prevent cost shifting andcross-subsidization between regulated and non-utility operations; and whether acode of conduct should be established to assure that non-utility segments ofthe holding company are not engaged in practices that could result in unfaircompetition caused by cost shifting from the non-utility affiliate to the utility.  During the period September 1998 to February2000, the Kentucky Commission issued draft codes of conduct and cost allocationguidelines.  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 Assemblyset forth provisions 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 pursuant theretosince that time.  On February 14, 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.

 

**Kentucky Commission Administrative Case for SystemAdequacy. **On June 19,2001, Kentucky Governor Paul E. Patton issued Executive Order 2001-771, whichdirected the Kentucky Commission to review and study issues relating to theneed for and development of new electric generating capacity in Kentucky.  The issues to be considered included theimpact of new power plants on the electric supply grid, facility citing issues,and economic development matters, with the goal of ensuring a continued,reliable source of supply of electricity for the citizens of Kentucky and thecontinued environmental and economic vitality of Kentucky and its communities.  In response to that Executive Order, in July2001 the Kentucky Commission opened Administrative Case No. 387 to review theadequacy of Kentucky’s generation capacity and transmission system.  Specifically, the items reviewed were theappropriate level of reliance on purchased power, the appropriate reserve marginsto meet existing and future electric demand, the impact of spikes in naturalgas prices on electric utility planning strategies, and the adequacy ofKentucky’s electric transmission facilities. KU, as a party to this proceeding, filed written testimony and respondedto two requests for information.  Publichearings were held October 2001 and KU filed a final brief in the case.  In December 2001, the Kentucky Commission issuedan order in which it noted that KU is responsibly addressing the long-termsupply needs of native load customers and that current reserve margins areappropriate.  However, due to the rapidpace of change in the industry, the order also requires KU to provide an annualassessment of supply resources, future demand, reserve margin, and the need fornew 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, it will not be able to handle thevolume of transactions envisioned by FERC without future upgrades, the costs ofwhich should be borne by those for whom the upgrades are required.

 

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

 

**FERC SMDNOPR. **On July 31,2002, the FERC issued a NOPR in Docket No. RM01-12-000 which would 

 

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substantially alter the regulations governing the nation’s wholesaleelectricity markets by establishing a common set of rules — SMD. The SMD NOPRwould require each public utility that owns, operates, or controls interstatetransmission facilities to become an Independent Transmission Provider (ITP),belong to an RTO that is an ITP, or contract with an ITP for operation of itstransmission assets. It would also establish a standardized congestionmanagement system, real-time and day-ahead energy markets, and a single transmissionservice for network and point-to-point transmission customers. Review of theproposed rulemaking is underway and a final rule is expected during 2003.  While it is expected that the SMD final rulewill affect KU revenues and expenses, the specific impact of the rulemaking isnot known at this time.

 

**MISO. **KU is a member of theMISO, which began commercial operations on February 1, 2002.  MISO now has operational control over KU’shigh-voltage transmission facilities (100 kV and greater), while KU continuesto control and operate the lower voltage transmission subject to the terms andconditions of the MISO OATT.  As atransmission-owning member of MISO, KU also incurs administrative costs of MISOpursuant to Schedule 10 of the MISO OATT.

 

MISO also proposedto implement a congestion management system. FERC directed the MISO to coordinate its efforts with FERC’s Rulemakingon SMD. OnSeptember 24, 2002, the MISO filed new rate schedules designated as Schedules16 and 17, which provide for the collection of costs incurred by the MISO toestablish day-ahead and real-time energy markets. The MISO proposed to recoverthese costs under Schedules 16 and 17 once service commences. If approved byFERC, these schedules will cause KU to incur additional costs.  KU opposes the establishment of Schedules 16and 17.  This effort is still on-goingand the ultimate impact of the two schedules, if approved, is not known at thistime.

 

**ARO.**  In 2003, KU expects to record approximately$11.3 million in regulatory assets and approximately $888,000 in regulatoryliabilities related to SFAS No. 143, *Accounting for Asset Retirement Obligations*.

 

**MergerSurcredit**.  As part ofthe LG&E Energy merger with KU Energy, KU 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, the Kentucky Commission adopted KU’s proposalto reduce its retail customers’ bills based on one-half of the estimatedmerger-related savings, net of deferred and amortized amounts, over a five yearperiod.  The surcredit mechanism providesthat 50% of the net non-fuel cost savings estimated to be achieved from themerger would be provided to ratepayers through a monthly bill credit, and 50%retained by the Companies, over a five-year period.  The surcredit was allocated 53% to KU and 47% to LG&E.  In that same order, the Commission requiredLG&E and KU, after the end of the five-year period, to present a plan forsharing with customers the then-projected non-fuel savings associated with themerger.  The Companies submitted thisfiling on January 13, 2003, proposing to continue to share with customers, on a50%/50% basis, the estimated fifth-year gross level of non-fuel savingsassociated with the merger.  The filingis currently under review.

 

Any fuel cost savings are passed to Kentucky customers through the fueladjustment clauses.  See FAC above.

 

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**Note 4 -Financial Instruments**

 

The cost and estimated fair values of the KU’s non-trading financialinstruments as of December 31, 2002,and 2001 follow (in thousands of $):

 
|                                        |   | **2002** |    | **2001**        |   |
|---------------------------------------------|--------|----------|---------|-----------------|--------|
|                                        |   | **Cost** |    | **Fair  Value** |   | **Cost** |   | **Fair  Value** |   |
|                                        |   |     |    |            |   |   |   |   |   |
| Long-term debt  (including current portion) |   | $        | 484,830 |            | $      | 503,194 |   | $ | 484,830 |   | $ | 499,618 |   |
| Interest-rate  swaps                        |   | —   |    | 16,928          |   | — |   | 6,906 |   |
|                                             |        |          |         |                 |        |  |  |  |  |  |  |  |  |

 

All of the above valuations reflect prices quotedby exchanges except for the swaps.  Thefair values of the swaps reflect price quotes from dealers or amountscalculated using accepted pricing models.

 

**Interest Rate Swaps.**  KU uses interest rate swaps to hedge exposure to marketfluctuations in certain of its debt instruments.  Pursuant to policy, use of these financial instruments isintended to mitigate risk and earnings volatility and is not speculative innature.  Management has designated allof the interest rate swaps as hedge instruments.  Financial instruments designated as fair value hedges areperiodically marked to market with the resulting gains and losses recordeddirectly into net income to correspond with income or expense recognized fromchanges in market value of the items being hedged.

 

As of December 31, 2002 and 2001, KU was party to various interest rateswap agreements with aggregate notional amounts of $153 million in 2002 and2001.  Under these swap agreements, KUpaid variable rates based on either LIBOR or the Bond Market Association’smunicipal swap index averaging 2.36% and 2.54%, and received fixed ratesaveraging 7.13% and 7.13% at December 31, 2002 and 2001, respectively. The swapagreements in effect at December 31, 2002 have been designated as fair valuehedges and mature on dates ranging from 2007 to 2025.  For 2002, the effect of marking these financial instruments andthe underlying debt to market resulted in immaterial pretax gains recorded ininterest expense.

 

Interest rate swaps hedge interest rate risk on the underlying debtunder SFAS 133, in addition to swaps being marked to market, the item beinghedged must also be marked to market, consequently at December 31, 2002, KU’sdebt reflects a $15.7 million mark to market adjustment.

 

# **Energy Trading & Risk Management Activities. **KU conducts energy trading and risk management activities to maximizethe value of power sales from physical assets it owns, in addition to thewholesale sale of excess asset capacity. Certain energy trading activities are accounted for on a mark-to-marketbasis in accordance with EITF 98-10,*Accountingfor Contracts Involved in Energy Trading and Risk Management Activities*, SFAS No. 133,*Accounting for Derivative Instrumentsand Hedging Activities,* and SFASNo. 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 andSFAS No. 138 and are notmarked-to-market.

 

The rescission of EITF 98-10,effective for fiscal years after December 15, 2002, will have no impact on KU’senergy trading and risk management reporting as all contracts marked to marketunder EITF 98-10 are also within the scope of SFAS No. 133.

 

The table belowsummarizes KU’s energy trading and risk management activities for 2002 and 2001(in thousands of $).

 

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|                                                          |   | **2002** |   | **2001** |   |
|---------------------------------------------------------------|--------|----------|--------|----------|--------|
| Fair value of contracts at beginning of period, net liability |   | $        | (186   | )        | $      | (17 | ) |
| Fair value of contracts when entered into during the period   |   | (65      | )      | 3,441    |   |
| Contracts realized or otherwise settled during the period     |   | 448      |   | (2,894   | )      |
| Changes in fair values due to changes in assumptions          |   | (353     | )      | (716     | )      |
| Fair value of contracts at end of period, net liability       |   | $        | (156   | )        | $      | (186 | ) |

 

No changes to valuation techniques for energy tradingand risk management activities occurred during 2002.  Changes in market pricing, interest rate and volatilityassumptions were made during both years. All contracts outstanding at December 31, 2002, have a maturity of lessthan one year and are valued using prices actively quoted for proposed orexecuted 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, 2002, 86% of the trading andrisk management commitments were with counterparties rated BBB- equivalent orbetter.

 

**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 fromdeliveries of electricity to approximately 477,000 customers in over 600communities and adjacent suburban and rural areas in 77 counties in central,southeastern and western Kentucky, to approximately 30,000 customers in five counties in southwesternVirginia and less than ten customers in Tennessee.  For the year ended December 31, 2002, 100%of total utility revenue was derived from electric operations.

 

In August 2001, KU and itsemployees represented by IBEW Local 2100 entered into a two-year collectivebargaining agreement. KU and its employees represented by USWA Local 9447-01entered into a three-year collective bargaining agreement effective August 2002and expiring August 2005.  The employeesrepresented by these two bargaining units comprise approximately 17% of KU’s workforce.

 

**Note 6 -Pension Plans and Retirement Benefits**

 

KU sponsors qualified and non-qualified pension plans and otherpostretirement benefit plans for its employees. The following tables provide areconciliation of the changes in the plans’ benefit obligations and fair valueof assets over the three-year period ending December 31, 2002, and a statementof the funded status as of December 31 for each of the last three years (inthousands of $):

 
|                                            |   | **2002** |    | **2001** |   | **2000** |   |
|-------------------------------------------------|--------|----------|---------|----------|--------|----------|--------|
| Pension Plans:                                  |   |     |    |     |   |     |   |
| Change in benefit obligation                    |   |     |    |     |   |     |   |
| Benefit obligation at beginning of year         |   | $        | 244,472 |     | $      | 233,034  |   | $ | 219,628 |   |
| Service cost                                    |   | 2,637    |    | 2,761    |   | 4,312    |   |
| Interest cost                                   |   | 16,598   |    | 17,534   |   | 17,205   |   |
| Plan amendment                                  |   | 28       |    | 4        |   | 11,757   |   |
| Change due to transfers                         |   | —   |    | (16,827  | )      | —   |   |
| Curtailment loss                                |   | —   |    | 1,400    |   | —   |   |
| Special termination benefits                    |   | —   |    | 24,274   |   | —   |   |
| Benefits paid                                   |   | (23,291  | )       | (29,166  | )      | (16,512  | )      |
| Actuarial (gain) or loss and other              |   | 7,283    |    | 11,458   |   | (3,356   | )      |
| Benefit obligation at end of year               |   | $        | 247,727 |     | $      | 244,472  |   | $ | 233,034 |   |
|                                            |   |     |    |     |   |     |   |
| Change in plan assets                           |   |     |    |     |   |     |   |
| Fair value of plans assets at beginning of year |   | $        | 216,947 |     | $      | 244,677  |   | $ | 274,109 |   |
| Actual return on plan assets                    |   | (13,767  | )       | 18,155   |   | (10,943  | )      |
| Employer contributions and plan transfers       |   | (99      | )       | (15,300  | )      | (994     | )      |
| Benefits paid                                   |   | (23,291  | )       | (29,166  | )      | (16,512  | )      |
| Administrative expenses                         |   | (1,256   | )       | (1,419   | )      | (983     | )      |
| Fair value of plan assets at end of year        |   | $        | 178,534 |     | $      | 216,947  |   | $ | 244,677 |   |
|                                            |   |     |    |     |   |     |   |
| Reconciliation of funded status                 |   |     |    |     |   |     |   |
| Funded status                                   |   | $        | (69,193 | )        | $      | (27,525  | )      | $ | 11,643 |   |
| Unrecognized actuarial  (gain) or loss          |   | 36,233   |    | (20,581  | )      | (36,435  | )      |
| Unrecognized transition (asset) or obligation   |   | (532     | )       | (664     | )      | (847     | )      |
| Unrecognized prior service cost                 |   | 10,106   |    | 11,027   |   | 14,176   |   |
| Net amount recognized at end of year            |   | $        | (23,386 | )        | $      | (37,743  | )      | $ | (11,463 | ) |
|                                            |   |     |    |     |   |     |   |
| Other Benefits:                                 |   |     |    |     |   |     |   |
| Change in benefit obligation                    |   |     |    |     |   |     |   |
| Benefit obligation at beginning of year         |   | $        | 83,223  |     | $      | 64,213   |   | $ | 54,201 |   |
| Service cost                                    |   | 610      |    | 495      |   | 757      |   |
| Interest cost                                   |   | 6,379    |    | 5,433    |   | 4,781    |   |
| Plan amendments                                 |   | —   |    | —   |   | 7,127    |   |
| Curtailment loss                                |   | —   |    | 6,381    |   | —   |   |
| Special termination benefits                    |   | —   |    | 3,824    |   | —   |   |
| Benefits paid net of retiree contributions      |   | (4,640   | )       | (5,446   | )      | (4,318   | )      |
| Actuarial (gain) or loss                        |   | 19,030   |    | 8,323    |   | 1,665    |   |
| Benefit obligation at end of year               |   | $        | 104,602 |     | $      | 83,223   |   | $ | 64,213 |   |
|                                            |   |     |    |     |   |     |   |
| Change in plan assets                           |   |     |    |     |   |     |   |
| Fair value of plan assets at beginning of year  |   | $        | 14,330  |     | $      | 23,762   |   | $ | 28,720 |   |
| Actual return on plan assets                    |   | (2,698   | )       | (4,404   | )      | (1,162   | )      |
| Employer contributions and plan transfers       |   | 1,648    |    | 473      |   | 522      |   |
| Benefits paid net of retiree contributions      |   | (5,337   | )       | (5,501   | )      | (4,318   | )      |
| Fair value of plan assets at end of year        |   | $        | 7,943   |     | $      | 14,330   |   | $ | 23,762 |   |
|                                            |   |     |    |     |   |     |   |
| Reconciliation of funded status                 |   |     |    |     |   |     |   |
| Funded status                                   |   | $        | (96,659 | )        | $      | (68,893  | )      | $ | (40,451 | ) |
| Unrecognized actuarial  (gain) or loss          |   | 22,667   |    | (437     | )      | (23,561  | )      |
| Unrecognized transition (asset) or obligation   |   | 11,209   |    | 12,290   |   | 21,871   |   |
| Unrecognized prior service cost                 |   | 2,891    |    | 3,548    |   | 6,109    |   |
| Net amount recognized at end of year            |   | $        | (59,892 | )        | $      | (53,492  | )      | $ | (36,032 | ) |

 

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There are no plan assets in the non-qualified plan due to the nature ofthe plan.

 

KU made a contribution to the pension plan of $3.5 million in January2003.

 

The following tables provide the amounts recognized in the balancesheet and information for plans with benefit obligations in excess of planassets as of December 31, 2002, 2001 and 2000 (in thousands of $):

 
|                                                                                                           |   | **2002** |    | **2001** |   | **2000** |   |
|----------------------------------------------------------------------------------------------------------------|--------|----------|---------|----------|--------|----------|--------|
|                                                                                                           |   |     |    |     |   |     |   |
| Pension Plans:                                                                                                 |   |     |    |     |   |     |   |
| Amounts recognized in the balance sheet consisted of:                                                          |   |     |    |     |   |     |   |
| Accrued benefit liability                                                                                      |   | $        | (51,035 | )        | $      | (37,743  | )      | $ | (11,463 | ) |
| Intangible asset                                                                                               |   | 10,106   |    | —   |   | —   |   |
| Accumulated other comprehensive income                                                                         |   | 17,543   |    | —   |   | —   |   |
| Net amount recognized at year-end                                                                              |   | $        | (23,386 | )        | $      | (37,743  | )      | $ | (11,463 | ) |
|                                                                                                           |   |     |    |     |   |     |   |
| Additional  year-end information for plans with accumulated benefit obligations in excess  of plan assets (1): |   |     |    |     |   |     |   |
| Projected benefit obligation                                                                                   |   | $        | 247,727 |     | $      | 244,472  |   | $ | 1,505 |   |
| Accumulated benefit obligation                                                                                 |   | 229,569  |    | 224,261  |   | 336      |   |
| Fair value of plan assets                                                                                      |   | 178,534  |    | 216,947  |   | —   |   |

 

----

| (1) 2002 and 2001 includes all plans. 2000 includes SERPs only.                               |   |   |    |   |   |
|-----------------------------------------------------------------------------------------------|--------|--------|---------|--------|--------|
|                                                                                          |   |   |    |   |   |   |   |
| Other Benefits:                                                                               |   |   |    |   |   |   |   |
| Amounts recognized in the balance sheet consisted of:                                         |   |   |    |   |   |   |   |
| Accrued benefit liability                                                                     |   | $      | (59,892 | )      | $      | (53,492 | ) | $ | (36,032 | ) |
|                                                                                          |   |   |    |   |   |   |   |
| Additional year-end information for plans with benefit obligations in  excess of plan assets: |   |   |    |   |   |   |   |
| Projected benefit obligation                                                                  |   | $      | 104,602 |   | $      | 83,223 |   | $ | 64,213 |   |
| Fair value of plan assets                                                                     |   | 7,943  |    | 14,330 |   | 23,762 |   |

 

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The following table provides the components of net periodic benefitcost for the plans for 2002, 2001 and 2000 (in thousands of $):

 
|                                             |   | **2002** |   | **2001** |   | **2000** |   |
|--------------------------------------------------|--------|----------|--------|----------|--------|----------|--------|
|                                             |   |     |   |     |   |     |   |
| Pension Plans:                                   |   |     |   |     |   |     |   |
| Components of net periodic benefit cost          |   |     |   |     |   |     |   |
| Service cost                                     |   | $        | 2,637  |     | $      | 2,761    |   | $ | 4,312 |   |
| Interest cost                                    |   | 16,598   |   | 17,534   |   | 17,205   |   |
| Expected return on plan assets                   |   | (18,406  | )      | (19,829  | )      | (25,170  | )      |
| Amortization of transition (asset) or obligation |   | (133     | )      | (136     | )      | (141     | )      |
| Amortization of prior service cost               |   | 956      |   | 962      |   | 1,145    |   |
| Recognized actuarial (gain) or loss              |   | 1        |   | (120     | )      | (3,410   | )      |
| Net periodic benefit cost                        |   | $        | 1,653  |     | $      | 1,172    |   | $ | (6,059 | ) |
|                                             |   |     |   |     |   |     |   |
| 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                                     |   | $        | 610    |     | $      | 495      |   | $ | 757 |   |
| Interest cost                                    |   | 6,379    |   | 5,433    |   | 4,781    |   |
| Expected return on plan assets                   |   | (1,022   | )      | (1,313   | )      | (1,768   | )      |
| Amortization of prior service cost               |   | 691      |   | 740      |   | 1,018    |   |
| Amortization of transition (asset) or obligation |   | 1,081    |   | 1,193    |   | 1,823    |   |
| Recognized actuarial (gain) or loss              |   | 343      |   | (40      | )      | (820     | )      |
| Net periodic benefit cost                        |   | $        | 8,082  |     | $      | 6,508    |   | $ | 5,791 |   |
|                                             |   |     |   |     |   |     |   |
| 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:

 
|                                             |   | **2002** |   | **2001** |   | **2000** |   |
|--------------------------------------------------|--------|----------|--------|----------|--------|----------|--------|
|                                             |   |     |   |     |   |     |   |
| Weighted-average assumptions as of December 31:  |   |     |   |     |   |     |   |
| Discount rate                                    |   | 6.75     | %      | 7.25     | %      | 7.75     | %      |
| Expected long-term rate of return on plan assets |   | 9.00     | %      | 9.50     | %      | 9.50     | %      |
| Rate of compensation increase                    |   | 3.75     | %      | 4.25     | %      | 4.75     | %      |

 

For measurement purposes, a 12.00% annual increase in the per capitacost of covered health care benefits was assumed for 2003.  The rate was assumed to decrease graduallyto 5.00% for 2014 and remain at that level thereafter.

 

Assumed health care cost trend rates have a significant effect on theamounts reported for the health care plans. A 1% change in assumed health carecost trend rates would have the following effects (in thousands of $):

 

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|                                                             |   | **1% Decrease** |   | **1% Increase** |   |
|------------------------------------------------------------------|--------|-----------------|--------|-----------------|--------|
|                                                             |   |            |   |            |   |
| Effect on total of service and interest cost components for 2002 |   | (422            | )      | 479             |   |
| Effect on year-end 2002 postretirement benefit obligations       |   | (7,010          | )      | 7,972           |   |

 

**ThriftSavings Plans.**  KU has a thrift savings plan under section 401(k) ofthe Internal Revenue Code.  Under theplan, eligible employees may defer and contribute to the plan a portion ofcurrent compensation in order to provide future retirement benefits. KU makescontributions to the plan by matching a portion of the employee contributions.The costs of this matching were approximately $1.5 million for 2002, $1.4 million for 2001 and $2.5million for 2000.

 

**Note 7 -Income Taxes**

 

Components of income tax expense are shown in the table below (inthousands of $):

 
|                                                                                 |   | **2002** |   | **2001** |   | **2000** |   |
|--------------------------------------------------------------------------------------|--------|----------|--------|----------|--------|----------|--------|
| Included in operating expenses:                                                      |   |     |   |     |   |     |   |
| Current            - federal  |   | $        | 38,524 |     | $      | 58,337   |   | $ | 44,927 |   |
| - state                                                                              |   | 10,494   |   | 13,465   |   | 9,333    |   |
| Deferred           - federal – net |   | 3,467    |   | (12,980  | )      | (3,254   | )      |
| - state – net                                                                   |   | 1,547    |   | (1,340   | )      | 957      |   |
| Total                                                                                |   | 54,032   |   | 57,482   |   | 51,963   |   |
|                                                                                 |   |     |   |     |   |     |   |
| Included in  other income - net:                                                     |   |     |   |     |   |     |   |
| Current            - federal  |   | (685     | )      | (948     | )      | 349      |   |
| - state                                                                              |   | 15       |   | (268     | )      | 67       |   |
| Deferred          - federal – net  |   | (195     | )      | 863      |   | (122     | )      |
| - state – net                                                                   |   | (88      | )      | 222      |   | (30      | )      |
| Amortization of  investment tax credit                                               |   | (2,955   | )      | (3,446   | )      | (3,674   | )      |
| Total                                                                                |   | (3,908   | )      | (3,577   | )      | (3,410   | )      |
|                                                                                 |   |     |   |     |   |     |   |
| Total income tax  expense                                                            |   | $        | 50,124 |     | $      | 53,905   |   | $ | 48,553 |   |

 

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

 
|                                                    |   | **2002** |    | **2001** |   |
|---------------------------------------------------------|--------|----------|---------|----------|--------|
| Deferred tax  liabilities:                              |   |     |    |     |   |
| Depreciation and  other plant-related items             |   | $        | 271,792 |     | $      | 269,752 |   |
| Other  liabilities                                      |   | 30,378   |    | 33,376   |   |
|                                                    |   | 302,170  |    | 303,128  |   |
|                                                    |   |     |    |     |   |
| Deferred tax  assets:                                   |   |     |    |     |   |
| Investment tax credit                                   |   | 3,431    |    | 4,623    |   |
| Income taxes due  to customers                          |   | 11,609   |    | 13,263   |   |
| Pensions                                                |   | 15,861   |    | 4,595    |   |
| Accrued  liabilities not currently deductible and other |   | 30,085   |    | 41,443   |   |
|                                                    |   | 60,986   |    | 63,924   |   |
| Net deferred  income tax liability                      |   | $        | 241,184 |     | $      | 239,204 |   |

 

A reconciliation of differences between the statutory U.S. federalincome tax rate and KU’s effective income tax

 

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rate follows:

 
|                                        |   | **2002** |   | **2001** |   | **2000** |   |
|---------------------------------------------|--------|----------|--------|----------|--------|----------|--------|
|                                        |   |     |   |     |   |     |   |
| Statutory  federal income tax rate          |   | 35.0     | %      | 35.0     | %      | 35.0     | %      |
| State income  taxes, net of federal benefit |   | 5.5      |   | 5.4      |   | 4.9      |   |
| Amortization of investment tax credit       |   | (2.4     | )      | (2.3     | )      | (2.6     | )      |
| Other  differences – net               |   | (3.2     | )      | (2.2     | )      | (3.6     | )      |
| Effective income  tax rate                  |   | 34.9     | %      | 35.9     | %      | 33.7     | %      |

 

The change in other differences is due to increased non-taxableearnings from an unconsolidated KU investment.

 

**Note 8 -Other Income - net**

 

Other income – net consisted of the following at December 31 (inthousands of $):

 
|                                     |   | **2002** |   | **2001** |   | **2000** |   |
|------------------------------------------|--------|----------|--------|----------|--------|----------|--------|
|                                     |   |     |   |     |   |     |   |
| Equity in earnings  - subsidiary company |   | $        | 6,697  |     | $      | 1,803    |   | $ | 2,242 |   |
| Interest and  dividend income            |   | 641      |   | 1,368    |   | 1,206    |   |
| Gains on fixed  asset disposals          |   | 157      |   | 1,844    |   | 5        |   |
| Income taxes and  other                  |   | 2,934    |   | 3,917    |   | 3,390    |   |
| Other income –  net                 |   | $        | 10,429 |     | $      | 8,932    |   | $ | 6,843 |   |

 

**Note 9 -First Mortgage Bonds and Pollution Control Bonds**

 

Long-term debt and the current portion of long-term debt, summarizedbelow (in thousands of $), consists primarily of first mortgage bonds andpollution control bonds.  Interest ratesand maturities in the table below are for the amounts outstanding at December31, 2002.

 
|                |   | **Stated  Interest Rates** |   | **Weighted  Average  Interest  Rate** |   | **Maturities** |   | **Principal  Amounts** |    |
|---------------------|--------|----------------------------|--------|---------------------------------------|--------|----------------|--------|------------------------|---------|
|                |   |                       |   |                                  |   |           |   |                   |    |
| Noncurrent  portion |   | Variable - 8.55%           |   | 5.21                                  | %      | 2006-2032      |   | $                      | 346,562 |   |
| Current portion     |   | Variable - 6.32%           |   | 3.58                                  | %      | 2003-2032      |   | $                      | 153,930 |   |

 

Under the provisions for KU’s variable-rate pollution control bondsSeries PCS 10, 12, 13, 14, and 15, the bonds are subject to tender for purchaseat the 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 2002 was 1.58%.

 

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

 

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

 

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February 1, 2018.

 

In May 2000, KU issued the Mercer County Solid Waste Disposal FacilityRevenue Bonds, 2000 Series A variable rate debt, for $12.9 million.  These proceeds were used to redeem $4million PCB Series 7, 7.38% bonds and $8.9 million of PCB Series 7, 7.6%bonds.  In June 2000, $61.5 millionSeries Q, 5.95% First Mortgage Bond matured and was paid in full.

 

KU’s First Mortgage Bond, 6.32% Series Q of $62 million is scheduled tomature in June 2003,  KU’s FirstMortgage Bond, 5.99% Series S of $36 million matures in 2006, and KU’s FirstMortgage Bond, 7.92% Series P of $53 million matures in 2007.  There are no scheduled maturities ofPollution Control Bonds for the five years subsequent to December 31,2002.

 

Substantially all of KU’s utility plant is pledged as security for its FirstMortgage Bonds.

 

**Note 10- Notes Payable to Parent**

 

KU participates in an intercompany money pool agreement whereinLG&E Energy can make funds available to KU at market based rates up to $400million.  The balance of the money poolloan from LG&E Energy was $119.5 million at a  rate of 1.61% and $47.8 million at an average rate of 2.37% atDecember 31, 2002 and 2001, respectively. The remaining money pool availability at December 31, 2002, was $280.5million. LG&E Energy maintains facilities of $450 million with affiliatesto ensure funding availability for the money pool.  The outstanding balance under these facilities as of December 31,2002 was $230 million, and availability of $220 million remained.

 

# **Note 11 - Commitments and Contingencies**

 

**ConstructionProgram.**  KU had approximately $6.2 million of commitments inconnection with its construction program at December 31, 2002.  Constructionexpenditures for the years 2003 and 2004 are estimated to total approximately $550.0 million; although all of this is not currentlycommitted, including the purchase of four jointly owned CTs, $152.0 million,and construction of NOx equipment, $177.0 million.

 

**OperatingLeases.**  KU leasesoffice space, office equipment, and vehicles. KU accounts for these leases as operating leases.  Total lease expense for 2002, 2001, and2000, was $2.6 million, $2.8 million and $2.3 million, respectively.

 

In December 1999, LG&E and KU entered into an 18-year cross-borderlease of its two jointly owned combustion turbines recently installed at KU’sBrown facility (units 6 and 7).  KU’sobligation was defeased upon consummation of the cross-border lease.  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.

 

**Environmental. **The Clean Air Act imposedstringent new SO2 and NOx emission limits on electric generatingunits.  KU met its Phase I SO2 requirementsprimarily through installation of a scrubber on Ghent Unit 1.  KU’s strategy for Phase II SO2 reductions,which commenced January 1, 2000, is to use accumulated emissions allowances todelay additional capital expenditures and may also include fuel switching orthe installation of additional scrubbers. 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

 

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technology.  KU will continue tomonitor these developments to ensure that its environmental obligations are metin the most efficient and cost-effective manner.

 

In September 1998, the EPA announced its final “NOx SIP Call” rulerequiring states to impose significant additional reductions in NOx emissionsby May 2003, in order to mitigate alleged ozone transport impacts on theNortheast region.  The Commonwealth of Kentuckyis currently in the process of revising its SIP to require reductions in NOxemissions from coal-fired generating units to the 0.15 lb./Mmbtu level on asystem-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 the Clean AirAct directing similar NOx reductions from a number of specifically targetedgenerating units including 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 a plan for adding significant additionalNOx controls to its generating units. Installation of additional NOx controls will proceed on a phased basis,with installation of controls commencing in late 2000 and continuing throughthe final compliance date.  In addition,KU will incur additional operation 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 several other air quality issues which maypotentially impact coal-fired power plants, including the appeal of the D.C.Circuit’s remand of the EPA’s revised air quality standards for ozone andparticulate matter, measures to implement EPA’s regional haze rule, and EPA’sDecember 2000 determination to regulate mercury emissions from power plants.

 

KU owns or formerly owned several properties that contained past MGPoperations.  Various contaminants aretypically found at such former MGP sites and environmental remediation measuresare frequently required.  KU hascompleted the cleanup of a site owned by KU. With respect to other former MGP sites no longer owned by KU, KU isunaware of what, if any, additional exposure or liability it may have.

 

In October 1999, approximately 38,000 gallons of diesel fuel leakedfrom a cracked valve in an underground pipeline at KU’s E.W. BrownStation.  Under the oversight of EPA andstate officials, KU commenced immediate spill containment and recovery measureswhich prevented the spill from reaching the Kentucky River.  KU ultimately recovered approximately 34,000gallons of diesel fuel.  In November1999, the Kentucky Division of Water issued a notice of violation for theincident.  KU is currently negotiatingwith the state in an effort to reach a complete resolution of this matter.  KU incurred costs of approximately $1.8million and received insurance reimbursement of $1.2 million.  In December 2002, the Department of Justice(DOJ) sent correspondence to KU regarding a potential per-day fine for failureto timely submit a spill control plan and a per-gallon fine for the amount ofoil discharged.  KU and the DOJ havecommenced settlement discussions using existing DOJ settlement guidelines onthis matter.

 

In April 2002, the EPA sent correspondence to KU regarding potentialexposure in connection with $1.5 million in completed remediation costsassociated with a transformer scrap-yard. KU believes it is one of the more remote among a number of potentiallyresponsible parties and has entered into settlement discussions with the EPA onthis matter.

 

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**PurchasedPower.**  KU haspurchase power arrangements with OMU, EEI and other parties.  Under the OMU agreement, which expires onJanuary 1, 2020, KU purchases all of the output of a 400-Mw generating stationnot required by OMU.  The amount ofpurchased power available to KU during 2003-2007, which is expected to beapproximately 8% of KU’s total kWh native load energy requirements, isdependent upon a number of factors including the units’ availability,maintenance schedules, fuel costs and OMU requirements.  Payments are based on the total costs of thestation allocated per terms of the OMU agreement, which generally followdelivered kWh.  Included in the totalcosts is KU’s proportionate share of debt service requirements on $149.6 millionof OMU bonds outstanding at December 31, 2002. The debt service is allocated to KU based on its annual allocated shareof capacity, which averaged approximately 50% in 2002.

 

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 several other contracts for purchased power of various Mwcapacities.

 

The estimated future minimum annual payments under purchased poweragreements for the years subsequent to December 31, 2002, are as follows (inthousands of $):

 
| 2003       |   | $       | 34,317  |   |
|------------|--------|---------|---------|--------|
| 2004       |   | 39,653  |    |
| 2005       |   | 39,653  |    |
| 2006       |   | 39,884  |    |
| 2007       |   | 39,994  |    |
| Thereafter |   | 643,946 |    |
| Total      |   | $       | 837,447 |   |

# ** **

# **Note 12 – Jointly Owned Electric Utility Plant**

 

LG&E and KU jointly own the following combustion turbines (inthousands of $):

 
|                 |   |           |   | **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   |   | 1,711        |   | 1,499  |   | 3,210     |   |
|                 |   | Net book value |   | $            | 32,208 |   | $      | 28,474    |   | $ | 60,682 |   |
|                 |   |           |   |         |   |   |   |      |   |
| E.W. Brown 5         |   | Ownership%     |   | 53           | %      | 47     | %      | 100       | %      |
|                 |   | Mw capacity    |   | 71           |   | 63     |   | 134       |   |
|                 |   | Cost           |   | $            | 23,973 |   | $      | 21,106    |   | $ | 45,079 |   |
|                 |   | Depreciation   |   | 1,206        |   | 1,052  |   | 2,258     |   |
|                 |   | Net book value |   | $            | 22,767 |   | $      | 20,054    |   | $ | 42,821 |   |
|                 |   |           |   |         |   |   |   |      |   |
| E.W. Brown 6         |   | Ownership%     |   | 38           | %      | 62     | %      | 100       | %      |
|                 |   | Mw capacity    |   | 59           |   | 95     |   | 154       |   |
|                 |   | Cost           |   | $            | 23,696 |   | $      | 36,957    |   | $ | 60,653 |   |
|                 |   | Depreciation   |   | 1,770        |   | 4,201  |   | 5,971     |   |
|                 |   | Net book value |   | $            | 21,926 |   | $      | 32,756    |   | $ | 54,682 |   |
|                 |   |           |   |         |   |   |   |      |   |
| E.W. Brown 7         |   | Ownership%     |   | 38           | %      | 62     | %      | 100       | %      |
|                 |   | Mw capacity    |   | 59           |   | 95     |   | 154       |   |
|                 |   | Cost           |   | $            | 23,607 |   | $      | 44,792    |   | $ | 68,399 |   |
|                 |   | Depreciation   |   | 4,054        |   | 4,502  |   | 8,556     |   |
|                 |   | Net book value |   | $            | 19,553 |   | $      | 40,290    |   | $ | 59,843 |   |
|                 |   |           |   |         |   |   |   |      |   |
| Trimble 5            |   | Ownership%     |   | 29           | %      | 71     | %      | 100       | %      |
|                 |   | Mw capacity    |   | 45           |   | 110    |   | 155       |   |
|                 |   | Cost           |   | $            | 15,970 |   | $      | 39,045    |   | $ | 55,015 |   |
|                 |   | Depreciation   |   | 251          |   | 614    |   | 865       |   |
|                 |   | Net book value |   | $            | 15,719 |   | $      | 38,431    |   | $ | 54,150 |   |
|                 |   |           |   |         |   |   |   |      |   |
| Trimble 6            |   | Ownership%     |   | 29           | %      | 71     | %      | 100       | %      |
|                 |   | Mw capacity    |   | 45           |   | 110    |   | 155       |   |
|                 |   | Cost           |   | $            | 15,961 |   | $      | 39,025    |   | $ | 54,986 |   |
|                 |   | Depreciation   |   | 251          |   | 614    |   | 865       |   |
|                 |   | Net book value |   | $            | 15,710 |   | $      | 38,411    |   | $ | 54,121 |   |
|                 |   |           |   |         |   |   |   |      |   |
| Trimble CT  Pipeline |   | Ownership%     |   | 29           | %      | 71     | %      | 100       | %      |
|                 |   | Cost           |   | $            | 1,835  |   | $      | 4,475     |   | $ | 6,310 |   |
|                 |   | Depreciation   |   | 39           |   | 96     |   | 135       |   |
|                 |   | Net book value |   | $            | 1,796  |   | $      | 4,379     |   | $ | 6,175 |   |

 

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See also Note 11, Construction Program, for KU’s planned purchase offour jointly owned CTs in 2004.

 

**Note 13- Selected Quarterly Data (Unaudited)**

 

Selected financial data for the four quarters of2002 and 2001 are shown below.  Becauseof seasonal fluctuations in temperature and other factors, results for quartersmay fluctuate throughout the year.

 
|                                            |   | **Quarters  Ended**   |    |
|-------------------------------------------------|--------|-----------------------|---------|
|                                            |   | **March**             |    | **June** |   | **September** |   | **December** |   |
|                                            |   | **(Thousands  of $)** |    |
|                                            |   |                  |    |   |   |   |   |   |   |
| 2002                                            |   |                  |    |   |   |   |   |   |   |
| Revenues                                        |   | $                     | 215,168 |   | $ | 203,555 |   | $ | 239,020 |   | $ | 230,476 |   |
| Net operating income                            |   | 28,200                |    | 20,047 |   | 31,028 |   | 29,368 |   |
| Net income                                      |   | 24,357                |    | 12,752 |   | 31,085 |   | 25,190 |   |
| Net income available for common stock           |   | 23,793                |    | 12,188 |   | 30,521 |   | 24,626 |   |
|                                            |   |                  |    |   |   |   |   |   |   |
| 2001                                            |   |                  |    |   |   |   |   |   |   |
| Revenues                                        |   | $                     | 211,793 |   | $ | 219,360 |   | $ | 216,370 |   | $ | 211,949 |   |
| Net operating income (loss)(a)                  |   | (344                  | )       | 28,422 |   | 30,253 |   | 63,039 |   |
| Net income (loss)(a)                            |   | (7,995                | )       | 22,080 |   | 26,340 |   | 55,989 |   |
| Net income (loss) available for common stock(a) |   | (8,559                | )       | 21,516 |   | 25,776 |   | 55,425 |   |

 

----

(a)                                  Lossresulted from the VDT pre-tax charge of $64.0 million in March 2001, which$57.1 million was reversed in

 

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December 2001.  See Note 3.

 

**Note 14 – Subsequent Events**

 

In January 2003, the Kentucky Commission reviewed the FAC of KU for thesix month period ended October 31, 2001. The Kentucky Commission ordered KU toreduce its fuel costs for purposes of calculating its FAC by $673,000. At issuewas the purchase of approximately 102,000 tons of coal from Western KentuckyEnergy Corporation, a non-regulated affiliate, for use at KU’s Ghent Facility.The Kentucky Commission further ordered that an independent audit be conductedto examine operational and management aspects of KU’s fuel procurementfunctions.

 

 On February 15, 2003, KUexperienced a severe ice storm in Lexington, Kentucky, and surrounding servicearea causing over 140,000 customers to lose power.  KU is still in the process of accumulating the costs of the storm.  Costs relate to repair of transmission anddistribution system, property damage, and significant labor costs, includingcontractor costs.  A portion of thecosts may be offset by insurance proceeds.

 

On March 18, 2003, the Kentucky Commission approved LG&E and KU'sjoint application for the acquisition of four CTs from an unregulatedaffiliate, LG&E Capital Corp.  Thetotal projected construction cost for the turbines, expected to be availablefor June 2004 in-service, is $227.4 million. The requested ownership share of the turbines is 63% for KU and 37% forLG&E.

 

 

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Kentucky UtilitiesCompany

REPORT OF MANAGEMENT

 

Themanagement of Kentucky Utilities Company is responsible for the preparation andintegrity of the financial statements and related information included in thisAnnual Report.  These statements havebeen prepared in accordance with accounting principles generally accepted inthe United States applied on a consistent basis and, necessarily, includeamounts that reflect the best estimates and judgment of management.

 

KU’s 2002 and 2001financial statements have been audited by PricewaterhouseCoopers LLP,independent accountants and the 2000 financial statements were audited byArthur Andersen LLP.  Management madeavailable to PricewaterhouseCoopers LLP and to Arthur Andersen LLP (in prioryears) all KU’s financial records and related data as well as the minutes ofshareholders’ and directors’ meetings.

 

Managementhas established and maintains a system of internal controls that providereasonable assurance that transactions are completed in accordance withmanagement’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 to recommendationsfrom the internal and external auditors. These recommendations for the year ended December 31, 2002, did notidentify any material weaknesses in the design and operation of KU’s internalcontrol structure.

 

Incarrying out its oversight role for the financial reporting and internalcontrols of KU, the Board of Directors meets regularly with KU’s independentpublic accountants, internal auditors and management.  The Board of Directors reviews the results of the independentaccountants’ audit of the financial statements and their audit procedures, anddiscusses 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 accountants and the internal auditors have access to theBoard of Directors at any time.

 

KentuckyUtilities Company maintains and internally communicates a written code ofbusiness conduct that addresses, among other items, potential conflicts ofinterest, compliance with laws, including those relating to financialdisclosure, and the confidentiality of proprietary information.

 

S. Bradford Rives

Senior Vice President-Finance and Controller

 

Kentucky Utilities Company

Louisville, Kentucky

 

126

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Kentucky UtilitiesCompany and Subsidiary

REPORT OF INDEPENDENTACCOUNTANTS

 

Tothe Shareholders of Kentucky Utilities Company and Subsidiary:

 

Inour opinion, the accompanying consolidated balance sheets and the relatedconsolidated statements of capitalization, income, retained earnings, cashflows and comprehensive income present fairly, in all material respects, thefinancial position of Kentucky Utilities Company and Subsidiary (the“Company”), a wholly-owned subsidiary of LG&E Energy Corp., at December 31,2002 and 2001, and the results of their operations and their cash flows foreach of the two years in the period ended December 31, 2002, in conformity withaccounting principles generally accepted in the United States of America.  These financial statements are theresponsibility of the Company’s management; our responsibility is to express anopinion on these financial statements based on our audits.  We conducted our audits of these statementsin accordance with auditing standards generally accepted in the United Statesof America, which require that we plan and perform the audits to obtainreasonable assurance about whether the financial statements are free ofmaterial misstatement.  An auditincludes examining, on a test basis, evidence supporting the amounts anddisclosures in the financial statements, assessing the accounting principlesused and significant estimates made by management, and evaluating the overallfinancial statement presentation.  Webelieve that our audits provide a reasonable basis for our opinion.

 
| /s/ PricewaterhouseCoopers LLP |   |
|--------------------------------|--------|
| January 21, 2003               |
| Louisville, Kentucky           |

 

127

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Kentucky UtilitiesCompany

REPORT OF INDEPENDENTPUBLIC ACCOUNTANTS

 

To the Shareholders of Kentucky UtilitiesCompany:

 

Wehave audited the accompanying balance sheet and statement of capitalization ofKentucky Utilities Company (a Kentucky and Virginia corporation and awholly-owned subsidiary of LG&E Energy Corp.) as of December 31, 2000, andthe related statements of income, retained earnings and cash flows for each ofthe two years in the period ended December 31, 2000.  These financial statements are the responsibility of the Company’smanagement.  Our responsibility is toexpress an opinion on these financial statements based on our audits.

 

Weconducted our audits in accordance with auditing standards generally acceptedin the United States.  Those standardsrequire that we plan and perform the audit to obtain reasonable assurance aboutwhether the financial statements are free of material misstatement.  An audit includes examining, on a testbasis, evidence supporting the amounts and disclosures in the financialstatements.  An audit also includesassessing the accounting principles used and significant estimates made bymanagement, as well as evaluating the overall financial statementpresentation.  We believe that ouraudits provide a reasonable basis for our opinion.

 

Inour opinion, the financial statements referred to above present fairly, in allmaterial respects, the financial position of Kentucky Utilities Company as ofDecember 31, 2000, and the results of its operations and its cash flows foreach of the two years in the period ended December 31, 2000, in conformity withaccounting principles generally accepted in the United States.

 

Our audits were made forthe purpose of forming an opinion on the basic financial statements taken as awhole. The schedule listed under Item 14(a)2 is presented for purposes of complyingwith the Securities and Exchange Commission’s rules and is not part of thebasic financial statements.  Thisschedule has been subjected to the auditing procedures applied in the audit ofthe basic financial statements and, in our opinion, fairly states in allmaterial respects the financial data required to be set forth therein inrelation to the basic financial statements taken as a whole.

 

Arthur Andersen LLP

 

Louisville, Kentucky

January 26, 2001

 

 

THIS IS A COPY OF A PREVIOUSLY ISSUED REPORT OF ARTHURANDERSEN LLP (“ANDERSEN”) RELATING TO A PRIOR PERIOD FOR WHICH ANDERSEN WASENGAGED AS INDEPENDENT PUBLIC ACCOUNTANTS. THE REPORT HAS NOT BEEN REISSUED BYANDERSEN.

 

128

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ITEM 9. Changes in and Disagreements with Accountants on Accounting andFinancial Disclosure.

 

Not applicable.

 

PART III

 

ITEMS 10, 11, 12 and 13are omitted pursuant to General Instruction G of Form 10-K.  The information required by ITEMS 10, 11, 12and 13 for LG&E and KU are set forth in Exhibit 99.2 filed herewith andincorporated herein by reference. Additionally, in accordance with General Instruction G, the informationrequired by ITEM 10 relating to executive officers of LG&E and KU has beenincluded in Part I of this Form 10-K.

 

PART IV

 

ITEM 14. Controls and Procedures

 

LG&E and KU maintain asystem of disclosure controls and procedures designed to ensure thatinformation required to be disclosed by the companies in reports they file orsubmit under the Securities Exchange Act of 1934 is recorded, processed,summarized and reported, within the time periods specified in the Securitiesand Exchange Commission rules and forms. During the 90 day period preceding thefiling of this report, LG&E and KU conducted an evaluation of such controlsand procedures under the supervision and the participation of the companies’Management, including the Chairman, President and Chief Executive Officer(“CEO”) and the Chief Financial Officer (“CFO”). Based upon that evaluation,the CEO and CFO are of the conclusion that the companies’ disclosure controlsand procedures are effective. With respect to LG&E’s and KU’s internalcontrols, there have been no significant changes in internal controls or inother factors that could significantly affect these controls subsequent to thedate of their most recent evaluation, including any corrective actions withregard to significant deficiencies and material weaknesses.

 

ITEM 15.  Exhibits, Financial Statement Schedules, andReports 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, 2002 (page 70).                |
|   |   | Consolidated statements of retained earnings for the  three years ended December 31, 2002 (page 70).     |
|   |   | Consolidated statements of comprehensive income for  the three years ended December 31, 2002 (page 71).  |
|   |   | Consolidated balance sheets-December 31, 2002, and  2001 (page 72).                                      |
|   |   | Consolidated statements of cash flows for the three  years ended December 31, 2002 (page 73).            |
|   |   | Consolidated statements of capitalization-December  31, 2002, and 2001 (page 74).                        |
|   |   | Notes to consolidated financial statements (pages 75-96).                                                |
|   |   | Report of management (page 97).                                                                          |
|   |   | Reports of independent accountants (pages 98-99).                                                        |
|   |   |                                                                                                     |
|   |   | KU:                                                                                                      |
|   |   | Consolidated statements of income for the three  years ended December 31, 2002 (page 102).               |
|   |   | Consolidated statements of retained earnings for the  three years ended December 31, 2002 (page 102).    |
|   |   | Consolidated statements of comprehensive income for  the three years ended December 31, 2002 (page 103). |

 

129

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|   |   | Consolidated balance sheets-December 31, 2002, and  2001 (page 104).                                                                                                                                                  |
|--------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   | Consolidated statements of cash flows for the three  years ended December 31, 2002 (page 105).                                                                                                                        |
|   |   | Consolidated statements of capitalization-December  31, 2002, and 2001 (page 106).                                                                                                                                    |
|   |   | Notes to consolidated financial statements (pages 107-125).                                                                                                                                                           |
|   |   | Report of management (page 126).                                                                                                                                                                                      |
|   |   | Reports of independent accountants (pages 127-128).                                                                                                                                                                   |
|   |   |                                                                                                                                                                                                                  |
|   | 2.     | Financial Statement Schedules (included in Part IV):                                                                                                                                                                  |
|   |   |                                                                                                                                                                                                                  |
|   |   | Schedule II                                                                                                                                                                                                           | Valuation and Qualifying Accounts for the three  years ended December 31, 2002, for LG&E (page 150), and KU (page 152). |
|   |   |                                                                                                                                                                                                                  |
|   |   | All other schedules have been omitted as not  applicable or not required or because the information required to be shown is  included in the Financial Statements or the accompanying Notes to Financial  Statements. |

 

3.  Exhibits:

 
| **Exhibit  No.** |   | **Applicable to Form  10-K of** |   | **Description** |
|------------------|--------|---------------------------------|--------|-----------------|
| **LG&E**     |   | **KU**                          |
|             |   |                            |   |            |   |   |
| 2.01             |   | ý                          |   | ý          |   | 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             |   | ý                          |   | ý          |   | 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             |   | ý                          |   | ý          |   | 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             |   | ý                          |   |            |   | 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             |   | ý                          |   |            |   | Copy of By-Laws of LG&E, as amended through June  2, 1999 [Filed as Exhibit 3.02 to LG&E’s Annual Report on Form 10-K for  the year ended |

 

130

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|             |   | **Applicable to Form  10-K of** |   |   |
|------------------|--------|---------------------------------|--------|--------|
| **Exhibit  No.** |   | **LG&E**                    |   | **KU** |   | **Description** |
|             |   |                            |   |   |   |   |
|             |   |                            |   |   |   | December 31, 1999, and incorporated by reference  herein] |
|             |   |                            |   |   |   |   |
| 3.03             |   |                            |   | ý |   | 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] |
|             |   |                            |   |   |   |   |
| 3.04             |   |                            |   | ý |   | Copy of By-Laws of KU, as amended through June 2,  1999. [Filed as Exhibit 3.04 to LG&E’s Annual Report on Form 10-K for the  year ended December 31, 1999, and incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 4.01             |   | ý                          |   |   |   | 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             |   | ý                          |   |   |   | Copy of Supplemental Indenture dated February 1,  1952, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.05 to LG&E’s  Registration Statement 2-9371 and incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 4.03             |   | ý                          |   |   |   | Copy of Supplemental Indenture dated February 1,  1954, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.03 to LG&E’s  Registration Statement 2-11923 and incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 4.04             |   | ý                          |   |   |   | Copy of Supplemental Indenture dated September 1,  1957, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 2.04 to LG&E’s Registration  Statement 2-17047 and incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 4.05             |   | ý                          |   |   |   | Copy of Supplemental Indenture dated October 1,  1960, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 2.05 to LG&E’s  Registration Statement 2-24920 and incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 4.06             |   | ý                          |   |   |   | Copy of Supplemental Indenture dated June 1, 1966,  which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 2.06 to LG&E’s  Registration Statement 2-28865 and incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 4.07             |   | ý                          |   |   |   | Copy of Supplemental Indenture dated June 1, 1968,  which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 2.07 to LG&E’s  Registration Statement 2-37368 and incorporated by reference herein] |

 

131

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|             |   | **Applicable to Form  10-K of** |   |   |
|------------------|--------|---------------------------------|--------|--------|
| **Exhibit  No.** |   | **LG&E**                    |   | **KU** |   | **Description** |
|             |   |                            |   |   |   |   |
| 4.08             |   | ý                          |   |   |   | Copy of Supplemental Indenture dated June 1, 1970,  which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 2.08 to LG&E’s  Registration Statement 2-37368 and incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 4.09             |   | ý                          |   |   |   | Copy of Supplemental Indenture dated August 1, 1971,  which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 2.09 to LG&E’s  Registration Statement 2-44295 and incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 4.10             |   | ý                          |   |   |   | Copy of Supplemental Indenture dated June 1, 1972,  which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 2.10 to LG&E’s  Registration Statement 2-52643 and incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 4.11             |   | ý                          |   |   |   | Copy of Supplemental Indenture dated February 1,  1975, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 2.11 to LG&E’s  Registration Statement 2-57252 and incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 4.12             |   | ý                          |   |   |   | Copy of Supplemental Indenture dated September 1,  1975, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 2.12 to LG&E’s  Registration Statement 2-57252 and incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 4.13             |   | ý                          |   |   |   | Copy of Supplemental Indenture dated September 1,  1976, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 2.13 to LG&E’s  Registration Statement 2-57252 and incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 4.14             |   | ý                          |   |   |   | Copy of Supplemental Indenture dated October 1,  1976, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 2.14 to LG&E’s  Registration Statement 2-65271 and incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 4.15             |   | ý                          |   |   |   | Copy of Supplemental Indenture dated June 1, 1978,  which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 2.15 to LG&E’s  Registration Statement 2-65271 and incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 4.16             |   | ý                          |   |   |   | Copy of Supplemental Indenture dated February 15,  1979, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 2.16 to |

 

132

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|             |   | **Applicable to Form  10-K of** |   |   |
|------------------|--------|---------------------------------|--------|--------|
| **Exhibit  No.** |   | **LG&E**                    |   | **KU** |   | **Description** |
|             |   |                            |   |   |   |   |
|             |   |                            |   |   |   | LG&E’s Registration Statement 2-65271 and  incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 4.17             |   | ý                          |   |   |   | Copy of Supplemental Indenture dated September 1,  1979, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.17 to LG&E’s  Annual Report on Form 10-K for the year ended December 31, 1980, and  incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 4.18             |   | ý                          |   |   |   | Copy of Supplemental Indenture dated September 15,  1979, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.18 to LG&E’s  Annual Report on Form 10-K for the year ended December 31, 1980, and  incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 4.19             |   | ý                          |   |   |   | Copy of Supplemental Indenture dated September 15,  1981, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.19 to LG&E’s  Annual Report on Form 10-K for the year ended December 31, 1981, and  incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 4.20             |   | ý                          |   |   |   | Copy of Supplemental Indenture dated March 1, 1982,  which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.20 to LG&E’s  Annual Report on Form 10-K for the year ended December 31, 1982, and  incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 4.21             |   | ý                          |   |   |   | Copy of Supplemental Indenture dated March 15, 1982,  which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.21 to LG&E’s  Annual Report on Form 10-K for the year ended December 31, 1982, and  incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 4.22             |   | ý                          |   |   |   | Copy of Supplemental Indenture dated September 15,  1982, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.22 to LG&E’s  Annual Report on Form 10-K for the year ended December 31, 1982, and  incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 4.23             |   | ý                          |   |   |   | Copy of Supplemental Indenture dated February 15,  1984, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.23 to LG&E’s  Annual Report on Form 10-K for the year ended December 31, 1984, and  incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 4.24             |   | ý                          |   |   |   | Copy of Supplemental Indenture dated July 1, 1985, which  is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.24 to LG&E’s  Annual Report on Form 10-K for the year ended December 31, 1985, and incorporated  by reference herein] |

 

133

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|             |   | **Applicable to Form  10-K of** |   |   |
|------------------|--------|---------------------------------|--------|--------|
| **Exhibit  No.** |   | **LG&E**                    |   | **KU** |   | **Description** |
|             |   |                            |   |   |   |   |
| 4.25             |   | ý                          |   |   |   | Copy of Supplemental Indenture dated November 15,  1986, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.25 to LG&E’s  Annual Report on Form 10-K for the year ended December 31, 1986, and  incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 4.26             |   | ý                          |   |   |   | Copy of Supplemental Indenture dated November 16,  1986, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.26 to LG&E’s  Annual Report on Form 10-K for the year ended December 31, 1986, and  incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 4.27             |   | ý                          |   |   |   | Copy of Supplemental Indenture dated August 1, 1987,  which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.27 to LG&E’s  Annual Report on Form 10-K for the year ended December 31, 1987, and  incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 4.28             |   | ý                          |   |   |   | Copy of Supplemental Indenture dated February 1,  1989, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.28 to LG&E’s  Annual Report on Form 10-K for the year ended December 31, 1988, and  incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 4.29             |   | ý                          |   |   |   | Copy of Supplemental Indenture dated February 2,  1989, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.29 to LG&E’s  Annual Report on Form 10-K for the year ended December 31, 1988, and  incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 4.30             |   | ý                          |   |   |   | Copy of Supplemental Indenture dated June 15, 1990,  which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.30 to LG&E’s  Annual Report on Form 10-K for the year ended December 31, 1990, and incorporated  by reference herein] |
|             |   |                            |   |   |   |   |
| 4.31             |   | ý                          |   |   |   | Copy of Supplemental Indenture dated November 1,  1990, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.31 to LG&E’s  Annual Report on Form 10-K for the year ended December 31, 1990, and  incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 4.32             |   | ý                          |   |   |   | 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] |
|             |   |                            |   |   |   |   |
| 4.33             |   | ý                          |   |   |   | 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, |

 

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|             |   | **Applicable to Form  10-K of** |   |   |
|------------------|--------|---------------------------------|--------|--------|
| **Exhibit  No.** |   | **LG&E**                    |   | **KU** |   | **Description** |
|             |   |                            |   |   |   |   |
|             |   |                            |   |   |   | 1992, and incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 4.34             |   | ý                          |   |   |   | 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] |
|             |   |                            |   |   |   |   |
| 4.35             |   | ý                          |   |   |   | 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] |
|             |   |                            |   |   |   |   |
| 4.36             |   | ý                          |   |   |   | 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] |
|             |   |                            |   |   |   |   |
| 4.37             |   | ý                          |   |   |   | Copy of Supplemental Indenture dated May 1, 2000,  which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.37 to LG&E’s  Annual Report on Form 10-K/A for the year ended December 31, 2000, and  incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 4.38             |   | ý                          |   |   |   | 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] |
|             |   |                            |   |   |   |   |
| 4.39             |   | ý                          |   |   |   | Copy of Supplemental Indenture  dated March 1, 2002, which is a supplemental instrument to Exhibit 4.01  hereto. |
|             |   |                            |   |   |   |   |
| 4.40             |   | ý                          |   |   |   | Copy of Supplemental Indenture  dated March 15, 2002, which is a supplemental instrument to Exhibit 4.01  hereto. |
|             |   |                            |   |   |   |   |
| 4.41             |   | ý                          |   |   |   | Copy of Supplemental Indenture  dated October 1, 2002, which is a supplemental instrument to Exhibit 4.01  hereto. |
|             |   |                            |   |   |   |   |
| 4.42             |   |                            |   | ý |   | 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 |

 

135

----

 
|             |   | **Applicable to Form  10-K of** |   |   |
|------------------|--------|---------------------------------|--------|--------|
| **Exhibit  No.** |   | **LG&E**                    |   | **KU** |   | **Description** |
|             |   |                            |   |   |   |   |
|             |   |                            |   |   |   | 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 (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] |
|             |   |                            |   |   |   |   |
| 4.43             |   |                            |   | ý |   | 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] |
|             |   |                            |   |   |   |   |
| 4.44             |   |                            |   | ý |   | Copy of Supplemental Indenture dated May 1, 2000,  which is a supplemental instrument to Exhibit 4.42 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] |
|             |   |                            |   |   |   |   |
| 4.45             |   | ý                          |   |   |   | Copy of Supplemental Indenture dated September 1,  2001, which is a supplemental instrument to Exhibit 4.42 hereto. [Filed as  Exhibit 4.42 to |

 

136

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|             |   | **Applicable to Form  10-K of** |   |   |
|------------------|--------|---------------------------------|--------|--------|
| **Exhibit  No.** |   | **LG&E**                    |   | **KU** |   | **Description** |
|             |   |                            |   |   |   |   |
|             |   |                            |   |   |   | KU’s Annual Report on Form 10-K for the year ended  December 31, 2001, and incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 4.46             |   |                            |   | ý |   | 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] |
|             |   |                            |   |   |   |   |
| 4.47             |   |                            |   | ý |   | 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] |
|             |   |                            |   |   |   |   |
| 4.48             |   | ý                          |   |   |   | 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] |
|             |   |                            |   |   |   |   |
| 4.49             |   | ý                          |   |   |   | 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] |
|             |   |                            |   |   |   |   |
| 4.50             |   |                            |   | ý |   | Copy of Supplemental Indenture  dated May 1, 2002, which is a supplemental instrument to Exhibit 4.42 hereto. |
|             |   |                            |   |   |   |   |
| 4.51             |   |                            |   | ý |   | Copy of Supplemental Indenture  dated September 1, 2002, which is a supplemental instrument to Exhibit 4.42  hereto. |
|             |   |                            |   |   |   |   |
| 10.01            |   | ý                          |   |   |   | Copies of Agreement between Sponsoring Companies  re:  Project D of Atomic Energy  Commission, dated May 12, 1952, Memorandums of Understanding between  Sponsoring Companies re:  Project D of  Atomic Energy Commission, dated September 19, 1952 and October 28, 1952, and  Power Agreement between Ohio Valley Electric Corporation and Atomic Energy  Commission, dated October 15, 1952. [Filed as Exhibit 13(y) to LG&E’s  Registration Statement 2-9975 and incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 10.02            |   | ý                          |   |   |   | Copy of Modification No. 1 dated July 23, 1953, to  the Power Agreement |

 

137

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|             |   | **Applicable to Form  10-K of** |   |   |
|------------------|--------|---------------------------------|--------|--------|
| **Exhibit  No.** |   | **LG&E**                    |   | **KU** |   | **Description** |
|             |   |                            |   |   |   |   |
|             |   |                            |   |   |   | between Ohio Valley Electric Corporation and Atomic  Energy Commission.  [Filed as Exhibit  4.03(b) to LG&E’s Regis­tration Statement 2-24920 and incorporated by  reference herein] |
|             |   |                            |   |   |   |   |
| 10.03            |   | ý                          |   |   |   | Copy of Modification No. 2 dated March 15, 1964, to  the Power Agreement between Ohio Valley Electric Corporation and Atomic  Energy Commission.  [Filed as Exhibit  5.02c to LG&E’s Registra­tion Statement 2-61607 and incorporated by  reference herein] |
|             |   |                            |   |   |   |   |
| 10.04            |   | ý                          |   |   |   | Copy of Modification No. 3 and No. 4 dated May 12,  1966 and January 7, 1967, respectively, to the Power Agreement between Ohio  Valley Electric Corporation and Atomic Energy Commission.  [Filed as Exhibits 4(a)(13) and 4(a)(14)  to LG&E’s Registration Statement 2-26063 and incorporated by reference  herein] |
|             |   |                            |   |   |   |   |
| 10.05            |   | ý                          |   |   |   | Copy of Modification No. 5 dated August 15, 1967, to  the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy  Commission.  [Filed as  Exhibit 13(c) to LG&E’s Registra­tion Statement 2-27316 and  incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 10.06            |   | ý                          |   | ý |   | Copies of (i) Inter-Company Power Agreement, dated  July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring  Companies (which Agreement includes as Exhibit A the Power Agree­ment, dated  July 10, 1953, between Ohio Valley Electric Corporation and Indiana-Kentucky  Electric Corporation); (ii) First Supplementary Transmission Agreement, dated  July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring  Companies; (iii) Inter-Company Bond Agreement, dated July 10, 1953, between  Ohio Valley Electric Corporation and Sponsoring Companies; (iv) Inter-Company  Bank Credit Agreement, dated July 10, 1953, between Ohio Valley Electric  Corpo­ration and Sponsoring Companies.   [Filed as Exhibit 5.02f to LG&E’s Registration Statement 2-61607  and incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 10.07            |   | ý                          |   | ý |   | 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] |
|             |   |                            |   |   |   |   |
| 10.08            |   | ý                          |   |   |   | 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] |

 

138

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|             |   | **Applicable to Form  10-K of** |   |   |
|------------------|--------|---------------------------------|--------|--------|
| **Exhibit  No.** |   | **LG&E**                    |   | **KU** |   | **Description** |
|             |   |                            |   |   |   |   |
| 10.09            |   | ý                          |   |   |   | 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] |
|             |   |                            |   |   |   |   |
| 10.10            |   | ý                          |   |   |   | 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] |
|             |   |                            |   |   |   |   |
| 10.11            |   | ý                          |   |   |   | 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] |
|             |   |                            |   |   |   |   |
| 10.12            |   | ý                          |   |   |   | Copy of Modification No. 6 dated November 15, 1967,  to the Power Agreement between Ohio Valley Electric Corporation and Atomic  Energy Commission.  [Filed as Exhibit  4(g) to LG&E’s Registration Statement 2-28524 and incorporated by  reference herein] |
|             |   |                            |   |   |   |   |
| 10.13            |   | ý                          |   | ý |   | 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] |
|             |   |                            |   |   |   |   |
| 10.14            |   | ý                          |   |   |   | Copy of Modification No. 7 dated November 5, 1975,  to the Power Agreement between Ohio Valley Electric Corporation and Atomic  Energy Commission.  [Filed as  Exhibit 5.02n to LG&E’s Registration Statement 2-56357 and  incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 10.15            |   | ý                          |   | ý |   | 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] |
|             |   |                            |   |   |   |   |
| 10.16            |   | ý                          |   |   |   | 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 |

 

139

----

 
|             |   | **Applicable to Form  10-K of** |   |   |
|------------------|--------|---------------------------------|--------|--------|
| **Exhibit  No.** |   | **LG&E**                    |   | **KU** |   | **Description** |
|             |   |                            |   |   |   |   |
|             |   |                            |   |   |   | reference herein] |
|             |   |                            |   |   |   |   |
| 10.17            |   | ý                          |   |   |   | Copy of Modification No. 8 dated June 23, 1977, to  the Power Agreement between Ohio Valley Electric Corporation and Atomic  Energy Commission.  [Filed as Exhibit  5.02q to LG&E’s Registration Statement 2-61607 and incorporated by  reference herein] |
|             |   |                            |   |   |   |   |
| 10.18            |   | ý                          |   |   |   | Copy of Modification No. 9 dated July 1, 1978, to  the Power Agreement between Ohio Valley Electric Corporation and Atomic  Energy Commission.  [Filed as Exhibit  5.02r to LG&E’s Registration Statement 2-63149 and incorporated by  reference herein] |
|             |   |                            |   |   |   |   |
| 10.19            |   | ý                          |   |   |   | Copy of Modification No. 10 dated August 1, 1979, to  the Power Agreement between Ohio Valley Electric Corporation and Atomic  Energy Commission.  [Filed as Exhibit  2 to LG&E’s Annual Report on Form 10-K for the year ended December 31,  1979, and incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 10.20            |   | ý                          |   |   |   | Copy of Modification No. 11 dated September 1, 1979,  to the Power Agreement between Ohio Valley Electric Corporation and Atomic  Energy Commission.  [Filed as Exhibit  3 to LG&E’s Annual Report on Form 10-K for the year ended December 31,  1979, and incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 10.21            |   | ý                          |   | ý |   | 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] |
|             |   |                            |   |   |   |   |
| 10.22            |   | ý                          |   |   |   | Copy of Modification No. 12 dated August 1, 1981, to  the Power Agreement between Ohio Valley Electric Corporation and Atomic  Energy Commission.  [Filed as  Exhibit 10.25 to LG&E’s Annual Report on Form 10-K for the year  ended December 31, 1981, and incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 10.23            |   | ý                          |   | ý |   | 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] |
|             |   |                            |   |   |   |   |
| 10.24            |   | ý                          |   |   |   | *  Copy of  Non-Qualified Savings Plan covering officers of the Company, |

 

140

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|             |   | **Applicable to Form  10-K of** |   |   |
|------------------|--------|---------------------------------|--------|--------|
| **Exhibit  No.** |   | **LG&E**                    |   | **KU** |   | **Description** |
|             |   |                            |   |   |   |   |
|             |   |                            |   |   |   | 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] |
|             |   |                            |   |   |   |   |
| 10.25            |   | ý                          |   |   |   | Copy of Modification No. 13 dated September 1, 1989,  to the Power Agreement between Ohio Valley Electric Corporation and Atomic  Energy Commission.  [Filed as Exhibit  10.42 to LG&E’s Annual Report on Form 10-K for the year ended December  31, 1993, and incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 10.26            |   | ý                          |   |   |   | Copy of Modification No. 14 dated January 15, 1992,  to the Power Agreement between Ohio Valley Electric Corporation and Atomic  Energy Commission.  [Filed as Exhibit  10.43 to LG&E’s Annual Report on Form 10-K for the year ended December  31, 1993, and incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 10.27            |   | ý                          |   | ý |   | 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] |
|             |   |                            |   |   |   |   |
| 10.28            |   | ý                          |   |   |   | Copy of Modification No. 15 dated February 15, 1993,  to the Power Agreement between Ohio Valley Electric Corporation and Atomic  Energy Commission.  [Filed as Exhibit  10.45 to LG&E’s Annual Report on Form 10-K for the year ended December  31, 1993, and incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 10.29            |   | ý                          |   |   |   | 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] |
|             |   |                            |   |   |   |   |
| 10.30            |   | ý                          |   | ý |   | 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] |
|             |   |                            |   |   |   |   |
| 10.31            |   | ý                          |   |   |   | Copy of Amendment dated March 1, 1995, to Firm  No-Notice Transportation Agreements dated November 1, 1993 (2-Year, 5-Year  and 8-Year), |

 

141

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|             |   | **Applicable to Form  10-K of** |   |   |
|------------------|--------|---------------------------------|--------|--------|
| **Exhibit  No.** |   | **LG&E**                    |   | **KU** |   | **Description** |
|             |   |                            |   |   |   |   |
|             |   |                            |   |   |   | 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] |
|             |   |                            |   |   |   |   |
| 10.32            |   | ý                          |   | ý |   | 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] |
|             |   |                            |   |   |   |   |
| 10.34            |   | ý                          |   |   |   | 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] |
|             |   |                            |   |   |   |   |
| 10.35            |   | ý                          |   |   |   | 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] |
|             |   |                            |   |   |   |   |
| 10.36            |   | ý                          |   |   |   | *  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] |
|             |   |                            |   |   |   |   |
| 10.37            |   | ý                          |   |   |   | *  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] |
|             |   |                            |   |   |   |   |
| 10.38            |   | ý                          |   |   |   | *  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] |
|             |   |                            |   |   |   |   |
| 10.39            |   | ý                          |   | ý |   | *  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] |

 

142

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|             |   | **Applicable to Form  10-K of** |   |   |
|------------------|--------|---------------------------------|--------|--------|
| **Exhibit  No.** |   | **LG&E**                    |   | **KU** |   | **Description** |
|             |   |                            |   |   |   |   |
| 10.40            |   | ý                          |   |   |   | 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] |
|             |   |                            |   |   |   |   |
| 10.41            |   | ý                          |   |   |   | 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] |
|             |   |                            |   |   |   |   |
| 10.42            |   | ý                          |   |   |   | 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] |
|             |   |                            |   |   |   |   |
| 10.43            |   | ý                          |   | ý |   | 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] |
|             |   |                            |   |   |   |   |
| 10.44            |   | ý                          |   | ý |   | 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] |
|             |   |                            |   |   |   |   |
| 10.45            |   |                            |   | ý |   | 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] |
|             |   |                            |   |   |   |   |
| 10.46            |   | ý                          |   |   |   | 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] |

 

143

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|             |   | **Applicable to Form  10-K of** |   |   |
|------------------|--------|---------------------------------|--------|--------|
| **Exhibit  No.** |   | **LG&E**                    |   | **KU** |   | **Description** |
|             |   |                            |   |   |   |   |
| 10.47            |   |                            |   | ý |   | 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 August 12, 2001, for the purchase  of coal. [Filed as Exhibit 10.55 to KU’s Annual Report on Form 10-K for the  year ended December 31, 2001, and incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 10.48            |   |                            |   | ý |   | Copy of Purchase Order dated December 26, 2000, by  and between Kentucky Utilities Company and AEI Coal Sales Company, Inc., for  the purchase of coal, commencing January 1, 2001. [Filed as Exhibit 10.56 to  KU’s Annual Report on Form 10-K for the year ended December 31, 2001, and  incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 10.49            |   | ý                          |   |   |   | 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] |
|             |   |                            |   |   |   |   |
| 10.50            |   | ý                          |   |   |   | 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] |
|             |   |                            |   |   |   |   |
| 10.51            |   | ý                          |   |   |   | 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] |
|             |   |                            |   |   |   |   |
| 10.52            |   | ý                          |   |   |   | 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,  2006). [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] |
|             |   |                            |   |   |   |   |
| 10.53            |   | ý                          |   | ý |   | *  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] |

 

144

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|             |   | **Applicable to Form  10-K of** |   |   |
|------------------|--------|---------------------------------|--------|--------|
| **Exhibit  No.** |   | **LG&E**                    |   | **KU** |   | **Description** |
|             |   |                            |   |   |   |   |
| 10.54            |   | ý                          |   | ý |   | * 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. |
|             |   |                            |   |   |   |   |
| 10.55            |   | ý                          |   | ý |   | * 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] |
|             |   |                            |   |   |   |   |
| 10.56            |   | ý                          |   | ý |   | * 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] |
|             |   |                            |   |   |   |   |
| 10.57            |   | ý                          |   | ý |   | Copy of Modification No. 10, dated January 1, 1998,  to the Inter-Company Power Agreement dated July 10, 1953, among Ohio Valley  Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 10.102  to LG&E’s and KU’s Annual Report on Form 10-K for the year ended December  31, 1999, and incorporated by reference herein] |
|             |   |                            |   |   |   |   |
| 10.58            |   | ý                          |   | ý |   | 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] |
|             |   |                            |   |   |   |   |
| 10.59            |   | ý                          |   |   |   | Copy of Letter Amendment,  dated September 15, 1999, to 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] |
|             |   |                            |   |   |   |   |
| 10.60            |   | ý                          |   | ý |   | * 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] |
|             |   |                            |   |   |   |   |
| 10.61            |   | ý                          |   | ý |   | * Copy of two forms of Change-In-Control Agreement  applicable to certain employees of LG&E Energy Corp. and its  subsidiaries. [Filed as |

 

145

----

 
|             |   | **Applicable to Form  10-K of** |   |   |
|------------------|--------|---------------------------------|--------|--------|
| **Exhibit  No.** |   | **LG&E**                    |   | **KU** |   | **Description** |
|             |   |                            |   |   |   |   |
|             |   |                            |   |   |   | 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] |
|             |   |                            |   |   |   |   |
| 10.62            |   | ý                          |   | ý |   | * 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] |
|             |   |                            |   |   |   |   |
| 10.63            |   | ý                          |   | ý |   | * 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. |
|             |   |                            |   |   |   |   |
| 10.64            |   | ý                          |   |   |   | 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). |
|             |   |                            |   |   |   |   |
| 10.65            |   | ý                          |   |   |   | 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). |
|             |   |                            |   |   |   |   |
| 10.66            |   | ý                          |   |   |   | Copy of Amendment No. 1 dated  January 1, 2001, to Coal Supply Agreement dated July 1, 1997,  between LG&E and Kindill Mining, Inc. |
|             |   |                            |   |   |   |   |
| 10.67            |   | ý                          |   |   |   | Copy of Amendment No. 2 dated  January 1, 2002, to Coal Supply Agreement dated July 1, 1997,  between LG&E and Kindill Mining, Inc. |
|             |   |                            |   |   |   |   |
| 10.68            |   | ý                          |   | ý |   | 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. |
|             |   |                            |   |   |   |   |
| 10.69            |   | ý                          |   |   |   | Copy of Coal Supply Agreement  dated January 1, 2003, between LG&E and Peabody Coalsales Company. |
|             |   |                            |   |   |   |   |
| 10.70            |   | ý                          |   |   |   | Copy of Coal Supply Agreement  dated January 1, 2002, between LG&E and Peabody Coalsales Company. |

 

146

----

 
|             |   | **Applicable to Form  10-K of** |   |   |
|------------------|--------|---------------------------------|--------|--------|
| **Exhibit  No.** |   | **LG&E**                    |   | **KU** |   | **Description** |
|             |   |                            |   |   |   |   |
| 10.71            |   | ý                          |   |   |   | Copy of  Amendment No. 1 dated June 1, 2002, to  Coal Supply Agreement dated January 1, 2002, between LG&E and Peabody  Coalsales Company. |
|             |   |                            |   |   |   |   |
| 10.72            |   | ý                          |   |   |   | Copy of  Amendment No. 2 dated January 1, 2003, to  Coal Supply Agreement dated January 1, 2002, between LG&E and Peabody  Coalsales Company. |
|             |   |                            |   |   |   |   |
| 10.73            |   |                            |   | ý |   | Copy of Coal Supply Agreement  dated January 1, 2002, between KU and Massey Coal Sales Company, Inc. |
|             |   |                            |   |   |   |   |
| 10.74            |   | ý                          |   | ý |   | *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. |
|             |   |                            |   |   |   |   |
| 10.75            |   | ý                          |   | ý |   | *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. |
|             |   |                            |   |   |   |   |
| 10.76            |   | ý                          |   | ý |   | *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. |
|             |   |                            |   |   |   |   |
| 10.77            |   | ý                          |   | ý |   | *Copies of Contract of  Employment, dated June 22, 1999, Terms of Condition of Assignment, dated  December 19, 2000, and Amendment to the Terms and Conditions of Assignment,  dated June 27, 2002, by and among, as applicable, Powergen UK plc, Powergen  plc, LG&E Energy Corp. and an executive officer of the Companies. |
|             |   |                            |   |   |   |   |
| 10.78            |   | ý                          |   | ý |   | *Copy of Powergen UK Long Term  Incentive Plan, November 2002, applicable to certain executive officers of  the Companies. |
|             |   |                            |   |   |   |   |
| 10.79            |   | ý                          |   | ý |   | *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. |
|             |   |                            |   |   |   |   |
| 12               |   | ý                          |   | ý |   | Computation of Ratio of Earnings to Fixed Charges  for LG&E and KU. |
|             |   |                            |   |   |   |   |
| 21               |   | ý                          |   | ý |   | Subsidiaries of the Registrants. |
|             |   |                            |   |   |   |   |
| 23.01            |   | ý                          |   |   |   | Consents of Independent Accountants for LG&E. |
|             |   |                            |   |   |   |   |
| 23.02            |   |                            |   | ý |   | Consents of Independent Accountants for KU. |
|             |   |                            |   |   |   |   |
| 24               |   | ý                          |   | ý |   | Powers of Attorney. |
|             |   |                            |   |   |   |   |
| 99.01            |   | ý                          |   | ý |   | Cautionary Statement for purposes of the “Safe  Harbor” provisions of the Private Securities Litigation Reform Act of 1995. |
|             |   |                            |   |   |   |   |
| 99.02            |   | ý                          |   | ý |   | LG&E and KU Director and Officer Information. |

 

(b)                                 ExecutiveCompensation Plans and Arrangements:

 

Exhibits preceded by an asterisk (“*”) above aremanagement contracts, compensation plans or arrangements required to be filedas an exhibit pursuant to Item 14(c) of Form 10-K.

 

(c)                                  Reportson Form 8-K:

 

147

----

 

On November 14, 2002, LG&E and KU filed a currentreport on Form 8-K, submitting certifications of the Chairman, President, andChief Executive Officer and the Chief Financial Officer of each company,respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002regarding the companies’ Quarterly Reports on Form 10-Q for the period ended September30, 2002.

 

(d)                                 Thefollowing instruments defining the rights of holders of certain long- term debtof KU have not been filed with the Securities and Exchange Commission but willbe furnished to the Commission upon request.

 

1.                                       LoanAgreement dated as of May 1, 1990, between KU and the County of Mercer,Kentucky, in connection with $12,900,000 County of Mercer, Kentucky,Collateralized Solid Waste Disposal Facility Revenue Bonds (KU Project) 1990Series A, due May 1, 2010 and May 1, 2020.

 

2.                                       LoanAgreement dated as of May 1, 1991, between KU and the County of Carroll,Kentucky, in connection with $96,000,000 County of Carroll, Kentucky,Collateralized Pollution Control Revenue Bonds (KU  Project) 1992 Series A, due September 15, 2016.

 

3.                                       LoanAgreement dated as of August 1, 1992, between KU and the County of Carroll,Kentucky, in connection with $2,400,000 County of Carroll, Kentucky,Collateralized Pollution Control Revenue Bonds (KU Project) 1992 Series C, dueFebruary 1, 2018.

 

4.                                       LoanAgreement 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 Revenue Bonds (KU Project) 1992 Series A, dueFebruary 1, 2018.

 

5.                                       LoanAgreement dated as of August 1, 1992, between KU and the County of Mercer,Kentucky, in connection with $7,400,000 County of Mercer, Kentucky,Collateralized Pollution Control Revenue Bonds (KU  Project) 1992 Series A, due February 1, 2018.

 

6.                                       LoanAgreement dated as of August 1, 1992, between KU and the County of Carroll,Kentucky, in connection with $20,930,000 County of Carroll, Kentucky,Collateralized Pollution Control Revenue Bonds (KU Project) 1992 Series B, dueFebruary 1, 2018.

 

7.                                       LoanAgreement dated as of December 1, 1993, between KU and the County of Carroll,Kentucky, in connection with $50,000,000 County  of Carroll, Kentucky, Collateralized Solid Waste DisposalFacilities Revenue Bonds (KU Project) 1993 Series A, due December 1, 2023.

 

8.                                       LoanAgreement dated as of November 1, 1994, between KU and the County of Carroll,Kentucky, in connection with $54,000,000 County of Carroll, Kentucky,Collateralized Solid Waste Disposal Facilities Revenue Bonds (KU Project) 1994Series A, due November 1,  2024.

 

148

----

 

Report of IndependentAccountantson Financial Statement Schedules

 

To the Shareholders ofLouisville Gas and Electric Company and Subsidiary:

 

Our audits of the consolidated financial statements of Louisville Gasand Electric Company and Subsidiary as of December 31, 2002 and for each of thetwo years in the period ended December 31, 2002, referred to in our reportdated January 21, 2003 also included an audit of the financial statementschedule listed in Item 14(a)2 of this Form 10-K.  In our opinion, this financial statement schedule presentsfairly, in all material respects, the information set forth therein as ofDecember 31, 2002 and for the year then ended when read in conjunction with therelated consolidated financial statements.

 

/s/ PricewaterhouseCoopers LLP

January 21, 2003

Louisville, Kentucky

 

149

----

 

Schedule II

 

Louisville Gas andElectric CompanySchedule II - Valuation and Qualifying AccountsFor the Three Years Ended December 31, 2002(Thousands of $)

 
|                                                   |   | **Other  Property  and  Investments** |   | **Accounts  Receivable  (Uncollectible  Accounts)** |   |
|--------------------------------------------------------|--------|---------------------------------------|--------|-----------------------------------------------------|--------|
|                                                   |   |                                  |   |                                                |   |
| Balance December  31, 1999                             |   | $                                     | 63     |                                                | $      | 1,233 |   |
|                                                   |   |                                  |   |                                                |   |
| Additions:                                             |   |                                  |   |                                                |   |
| Charged to costs  and expenses                         |   | —                                |   | 2,803                                               |   |
| Deductions:                                            |   |                                  |   |                                                |   |
| Net charges of  nature for which reserves were created |   | —                                |   | 2,750                                               |   |
|                                                   |   |                                  |   |                                                |   |
| 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 |   |

 

150

----

 

### Report of Independent Accountantson Financial Statement Schedules

 

To the Shareholders ofKentucky Utilities Company and Subsidiary:

 

Our audits of the consolidated financial statements of KentuckyUtilities Company and Subsidiary as of December 31, 2002 and for each of thetwo years in the period ended December 31, 2002, referred to in our reportdated January 21, 2003 also included an audit of the financial statementschedule listed in Item 14(a)2 of this Form 10-K.  In our opinion, this financial statement schedule presentsfairly, in all material respects, the information set forth therein as ofDecember 31, 2002 and for the year then ended when read in conjunctionwith the related consolidated financial statements.

 

/s/ PricewaterhouseCoopers LLP

January 21, 2003

Louisville, Kentucky

 

151

----

 

Schedule II

 

Kentucky UtilitiesCompanySchedule II - Valuation and Qualifying AccountsFor the Three Years Ended December 31, 2002(Thousands of $)

 
|                                                   |   | **Other  Property  and  Investments** |   | **Accounts  Receivable  (Uncollectible  Accounts)** |   |
|--------------------------------------------------------|--------|---------------------------------------|--------|-----------------------------------------------------|--------|
|                                                   |   |                                  |   |                                                |   |
| Balance December  31, 1999                             |   | $                                     | 687    |                                                | $      | 800 |   |
|                                                   |   |                                  |   |                                                |   |
| Additions:                                             |   |                                  |   |                                                |   |
| Charged to costs  and expenses                         |   | 64                                    |   | 1,430                                               |   |
| Deductions:                                            |   |                                  |   |                                                |   |
| Net charges of  nature for which reserves were created |   | —                                |   | 1,430                                               |   |
|                                                   |   |                                  |   |                                                |   |
| 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 |   |

 

152

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SIGNATURES – LOUISVILLE GAS ANDELECTRIC COMPANY

 

Pursuant to the requirements of Section 13 or 15(d) of the SecuritiesExchange Act of 1934, the registrant has duly caused this report to be signedon its behalf by the undersigned, thereunto duly authorized.

 
|           | LOUISVILLE GAS AND ELECTRIC COMPANY |
|----------------|-------------------------------------|
|           | Registrant                          |
|           |                                |
|           |                                |
| March 25, 2003 | /s/ S. Bradford Rives               |   |
| (Date)         |                                |

 

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); |   |     |
|                  |                  |                                                                                          |   |     |
| Richard Aitken-Davies |                  | Chief Financial Officer  (Principal Financial Officer);                                       |   |     |
|                  |                  |                                                                                          |   |     |
| S. Bradford Rives     |                  | Senior Vice President –  Finance and Controller  (Principal Accounting Officer);         |   |     |
|                  |                  |                                                                                          |   |     |
| Michael Söhlke   |                  | Director;                                                                                     |   |     |
|                  |                  |                                                                                          |   |     |
| Edmund A. Wallis      |                  | Director.                                                                                     |   |     |
|                  |                  |                                                                                          |   |     |
|                  |                  |                                                                                          |   |     |
| By                    | /s/ S. Bradford Rives |                                                                                          |   |     |   | March 25, 2003 |
|                  |                  |                                                                                          |   |     |   |
|                  | (Attorney-In-Fact)    |                                                                                          |   |     |   |
|                       |                       |                                                                                               |        |          |  |  |

 

153

----

 

 

SIGNATURES – KENTUCKYUTILITIES COMPANY

 

Pursuant to the requirements of Section 13 or 15(d) of the SecuritiesExchange Act of 1934, the registrant has duly caused this report to be signedon its behalf by the undersigned, thereunto duly authorized.

 
|           | KENTUCKY UTILITIES COMPANY |
|----------------|----------------------------|
|           | Registrant                 |
|           |                       |
|           |                       |
| March 25, 2003 | /s/ S. Bradford Rives      |   |
| (Date)         |                       |

 

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); |   |     |
|                  |                  |                                                                                          |   |     |
| Richard Aitken-Davies |                  | Chief Financial Officer  (Principal Financial Officer);                                       |   |     |
|                  |                  |                                                                                          |   |     |
| S. Bradford Rives     |                  | Senior Vice President –  Finance and Controller  (Principal Accounting Officer);         |   |     |
|                  |                  |                                                                                          |   |     |
| Michael Söhlke   |                  | Director;                                                                                     |   |     |
|                  |                  |                                                                                          |   |     |
| Edmund A. Wallis      |                  | Director.                                                                                     |   |     |
|                  |                  |                                                                                          |   |     |
| By                    | /s/ S. Bradford Rives |                                                                                          |   |     |   | March 25, 2003 |
|                  |                  |                                                                                          |   |     |   |
|                  | (Attorney-In-Fact)    |                                                                                          |   |     |   |
|                       |                       |                                                                                               |        |          |  |  |

 

154

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# **CERTIFICATIONS**

 

## Louisville Gas andElectric Company

 

I, Victor A. Staffieri, Chairman of the Board, President and ChiefExecutive Officer, certify that:

 

1. I have reviewed this annual report on Form 10-K of Louisville Gasand Electric Company;

 

2. Based on my knowledge, this annual report does not contain anyuntrue statement of a material fact or omit to state a material fact necessaryto make the statements made, in light of the circumstances under which suchstatements were made, not misleading with respect to the period covered by thisannual report;

 

3. Based on my knowledge, the financial statements, and other financialinformation included in this annual report, fairly present in all materialrespects the financial condition, results of operations and cash flows of theregistrant as of, and for, the periods presented in this annual report;

 

4. The registrant’s other certifying officers and I are responsible forestablishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-14 and 15d-14) for the registrant and have:

 

a) designed such disclosure controls and procedures to ensure thatmaterial information relating to the registrant, including its consolidatedsubsidiaries, is made known to us by others within those entities, particularlyduring the period in which this annual report is being prepared;

 

b) evaluated the effectiveness of the registrant’s disclosure controlsand procedures as of a date within 90 days prior to the filing date of thisannual report (the “Evaluation Date”); and

 

c) presented in this annual report our conclusions about theeffectiveness of the disclosure controls and procedures based on our evaluationas of the Evaluation Date;

 

5. The registrant’s other certifying officers and I have disclosed,based on our most recent evaluation, to the registrant’s auditors and the auditcommittee of registrant’s board of directors (or persons performing theequivalent functions):

 

a) all significant deficiencies in the design or operation of internalcontrols which could adversely affect the registrant’s ability to record,process, summarize and report financial data and have identified for theregistrant’s auditors any material weaknesses in internal controls; and

 

b) any fraud, whether or not material, that involves management orother employees who have a significant role in the registrant’s internalcontrols; and

 

6. The registrant’s other certifying officers and I have indicated inthis annual report whether there were significant changes in internal controlsor in other factors that could significantly affect internal controlssubsequent to the date of our most recent evaluation, including any correctiveactions with regard to significant deficiencies and material weaknesses.

 
| Date:  March  25, 2003                                   |
|---------------------------------------------------------------|
| /s/  Victor  A. Staffieri                                |   |
| Victor A. Staffieri                                           |
| Chairman of the Board, President and Chief Executive  Officer |

 

155

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## Louisville Gas and Electric Company

 

I, Richard Aitken-Davies, Chief Financial Officer, certify that:

 

1. I have reviewed this annual report on Form 10-K of Louisville Gasand Electric Company;

 

2. Based on my knowledge, this annual report does not contain anyuntrue statement of a material fact or omit to state a material fact necessaryto make the statements made, in light of the circumstances under which suchstatements were made, not misleading with respect to the period covered by thisannual report;

 

3. Based on my knowledge, the financial statements, and other financialinformation included in this annual report, fairly present in all materialrespects the financial condition, results of operations and cash flows of theregistrant as of, and for, the periods presented in this annual report;

 

4. The registrant’s other certifying officers and I are responsible forestablishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-14 and 15d-14) for the registrant and have:

 

a) designed such disclosure controls and procedures to ensure thatmaterial information relating to the registrant, including its consolidatedsubsidiaries, is made known to us by others within those entities, particularlyduring the period in which this annual report is being prepared;

 

b) evaluated the effectiveness of the registrant’s disclosure controlsand procedures as of a date within 90 days prior to the filing date of thisannual report (the “Evaluation Date”); and

 

c) presented in this annual report our conclusions about theeffectiveness of the disclosure controls and procedures based on our evaluationas of the Evaluation Date;

 

5. The registrant’s other certifying officers and I have disclosed,based on our most recent evaluation, to the registrant’s auditors and the auditcommittee of registrant’s board of directors (or persons performing theequivalent functions):

 

a) all significant deficiencies in the design or operation of internalcontrols which could adversely affect the registrant’s ability to record,process, summarize and report financial data and have identified for theregistrant’s auditors any material weaknesses in internal controls; and

 

b) any fraud, whether or not material, that involves management orother employees who have a significant role in the registrant’s internalcontrols; and

 

6. The registrant’s other certifying officers and I have indicated inthis annual report whether there were significant changes in internal controlsor in other factors that could significantly affect internal controlssubsequent to the date of our most recent evaluation, including any correctiveactions with regard to significant deficiencies and material weaknesses.

 

Date:  March 25, 2003

 
| /s/  Richard  Aitken-Davies |   |
|----------------------------------|--------|
| Richard Aitken-Davies            |
| Chief Financial Officer          |

 

156

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## Kentucky Utilities Company

 

I, Victor A. Staffieri, Chairman of the Board, President and ChiefExecutive Officer, certify that:

 

1. I have reviewed this annual report on Form 10-K of KentuckyUtilities Company;

 

2. Based on my knowledge, this annual report does not contain anyuntrue statement of a material fact or omit to state a material fact necessaryto make the statements made, in light of the circumstances under which suchstatements were made, not misleading with respect to the period covered by thisannual report;

 

3. Based on my knowledge, the financial statements, and other financialinformation included in this annual report, fairly present in all materialrespects the financial condition, results of operations and cash flows of theregistrant as of, and for, the periods presented in this annual report;

 

4. The registrant’s other certifying officers and I are responsible forestablishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-14 and 15d-14) for the registrant and have:

 

a) designed such disclosure controls and procedures to ensure thatmaterial information relating to the registrant, including its consolidatedsubsidiaries, is made known to us by others within those entities, particularlyduring the period in which this annual report is being prepared;

 

b) evaluated the effectiveness of the registrant’s disclosure controlsand procedures as of a date within 90 days prior to the filing date of thisannual report (the “Evaluation Date”); and

 

c) presented in this annual report our conclusions about theeffectiveness of the disclosure controls and procedures based on our evaluationas of the Evaluation Date;

 

5. The registrant’s other certifying officers and I have disclosed,based on our most recent evaluation, to the registrant’s auditors and the auditcommittee of registrant’s board of directors (or persons performing theequivalent functions):

 

a) all significant deficiencies in the design or operation of internalcontrols which could adversely affect the registrant’s ability to record,process, summarize and report financial data and have identified for theregistrant’s auditors any material weaknesses in internal controls; and

 

b) any fraud, whether or not material, that involves management orother employees who have a significant role in the registrant’s internalcontrols; and

 

6. The registrant’s other certifying officers and I have indicated inthis annual report whether there were significant changes in internal controlsor in other factors that could significantly affect internal controlssubsequent to the date of our most recent evaluation, including any correctiveactions with regard to significant deficiencies and material weaknesses.

 

Date:  March 25, 2003

 
| /s/  Victor  A. Staffieri                                |   |
|---------------------------------------------------------------|--------|
| Victor A. Staffieri                                           |
| Chairman of the Board, President and Chief Executive  Officer |

 

157

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## Kentucky Utilities Company

 

I, Richard Aitken-Davies, Chief Financial Officer, certify that:

 

1. I have reviewed this annual report on Form 10-K of KentuckyUtilities Company;

 

2. Based on my knowledge, this annual report does not contain anyuntrue statement of a material fact or omit to state a material fact necessaryto make the statements made, in light of the circumstances under which suchstatements were made, not misleading with respect to the period covered by thisannual report;

 

3. Based on my knowledge, the financial statements, and other financialinformation included in this annual report, fairly present in all materialrespects the financial condition, results of operations and cash flows of theregistrant as of, and for, the periods presented in this annual report;

 

4. The registrant’s other certifying officers and I are responsible forestablishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-14 and 15d-14) for the registrant and have:

 

a) designed such disclosure controls and procedures to ensure thatmaterial information relating to the registrant, including its consolidatedsubsidiaries, is made known to us by others within those entities, particularlyduring the period in which this annual report is being prepared;

 

b) evaluated the effectiveness of the registrant’s disclosure controlsand procedures as of a date within 90 days prior to the filing date of thisannual report (the “Evaluation Date”); and

 

c) presented in this annual report our conclusions about theeffectiveness of the disclosure controls and procedures based on our evaluationas of the Evaluation Date;

 

5. The registrant’s other certifying officers and I have disclosed,based on our most recent evaluation, to the registrant’s auditors and the auditcommittee of registrant’s board of directors (or persons performing theequivalent functions):

 

a) all significant deficiencies in the design or operation of internalcontrols which could adversely affect the registrant’s ability to record,process, summarize and report financial data and have identified for theregistrant’s auditors any material weaknesses in internal controls; and

 

b) any fraud, whether or not material, that involves management orother employees who have a significant role in the registrant’s internalcontrols; and

 

6. The registrant’s other certifying officers and I have indicated in thisannual report whether there were significant changes in internal controls or inother factors that could significantly affect internal controls subsequent tothe date of our most recent evaluation, including any corrective actions withregard to significant deficiencies and material weaknesses.

 

Date:  March 25, 2003

 
| /s/  Richard  Aitken-Davies |   |
|----------------------------------|--------|
| Richard Aitken-Davies            |
| Chief Financial Officer          |

 

158

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