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UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWashington, D. C. 20549

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FORM 10-K/A

(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, 2001

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(A Kentucky Corporation)
220 West Main Street
P. O. Box 32010
Louisville, Kentucky 40232
(502) 627-2000 |  | 61-0264150                        
|1-3464                 |  | Kentucky Utilities Company(A Kentucky and Virginia Corporation)
One Quality Street
Lexington, Kentucky 40507-1428
(859) 255-2100           |  | 61-0247570                        

Securities registered pursuant to section 12(b) of the Act:

Kentucky Utilities Company

Title of each class

Name of each exchange on which registeredPreferred Stock, 4.75% cumulative,
stated value $100 per share

Philadelphia Stock Exchange


Securities registered pursuant to section 12(g) of the Act:

Louisville Gas and Electric Company5% 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 CompanyPreferred Stock, cumulative, stated value $100 per share (Title of class)

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

Indicate
by check mark if disclosure of delinquent filers pursuant to Item 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 information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form
10-K. ý

As
of February 28, 2002, 860,287 shares of voting preferred stock of Louisville Gas and Electric Company, with an aggregate market value of $16,027,000, were outstanding and held by
non-affiliates. Additionally, Louisville Gas and Electric Company had 21,294,223 shares of common stock outstanding, all held by LG&E Energy Corp. Kentucky Utilities Company had 37,817,878 shares of
common stock outstanding, all held by LG&E Energy Corp.

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

DOCUMENTS INCORPORATED BY REFERENCE

Proxy statements for Louisville Gas and Electric Company and Kentucky Utilities Company, currently anticipated to be prepared and filed with the Commission during
April 2002, are incorporated by reference into Part III of this Form 10-K.

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TABLE OF CONTENTS

PART I

|Item 1. |  | Business                                            |  | 7 
|------- |  | --------------------------------------------------- |  | --
|        |  | Louisville Gas and Electric Company                 |  |   
|        |  | General                                             |  | 7 
|        |  | Electric Operations                                 |  | 8 
|        |  | Gas Operations                                      |  | 10
|        |  | Rates and Regulation                                |  | 11
|        |  | Construction Program and Financing                  |  | 12
|        |  | Coal Supply                                         |  | 12
|        |  | Gas Supply                                          |  | 13
|        |  | Environmental Matters                               |  | 14
|        |  | Competition                                         |  | 14
|        |  | Kentucky Utilities Company                          |  |   
|        |  | General                                             |  | 15
|        |  | Electric Operations                                 |  | 15
|        |  | Rates and Regulation                                |  | 17
|        |  | Construction Program and Financing                  |  | 18
|        |  | Coal Supply                                         |  | 18
|        |  | Environmental Matters                               |  | 19
|        |  | Competition                                         |  | 19
|        |  | Employees and Labor Relations                       |  | 20
|        |  | Executive Officers of the Companies                 |  | 20
|Item 2. |  | Properties                                          |  | 22
|Item 3. |  | Legal Proceedings                                   |  | 24
|Item 4. |  | Submission of Matters to a Vote of Security Holders |  | 26

PART II

|Item 5.  |  | Market for the Registrant's Common Equity and Related Stockholder Matters             |  | 28 
|-------- |  | ------------------------------------------------------------------------------------- |  | ---
|Item 6.  |  | Selected Financial Data                                                               |  | 29 
|Item 7.  |  | Management's Discussion and Analysis of Financial Condition and Results of Operation: |  |    
|         |  | Louisville Gas and Electric Company                                                   |  | 31 
|         |  | Kentucky Utilities Company                                                            |  | 46 
|Item 7A. |  | Quantitative and Qualitative Disclosures About Market Risk                            |  | 59 
|Item 8.  |  | Financial Statements and Supplementary Data:                                          |  |    
|         |  | Louisville Gas and Electric Company                                                   |  | 60 
|         |  | Kentucky Utilities Company                                                            |  | 93 
|Item 9.  |  | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure  |  | 121

PART III

|Item 10. |  | Directors and Executive Officers of the Registrant (a)             |  | 121
|-------- |  | ------------------------------------------------------------------ |  | ---
|Item 11. |  | Executive Compensation (a)                                         |  | 121
|Item 12. |  | Security Ownership of Certain Beneficial Owners and Management (a) |  | 121
|Item 13. |  | Certain Relationships and Related Transactions (a)                 |  | 121

PART IV

|Item 14.   |  | Exhibits, Financial Statement Schedules, and Reports on Form 8-K |  | 121
|---------- |  | ---------------------------------------------------------------- |  | ---
|Signatures |  |                                                                  |  | 141

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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               
|EPA                 |  | U.S. Environmental Protection Agency           
|ESM                 |  | Earnings Sharing Mechanism                     
|FAC                 |  | Fuel Adjustment Clause                         
|FERC                |  | Federal Energy Regulatory Commission           
|FPA                 |  | Federal Power Act                              
|FT and FT-A         |  | Firm Transportation                            
|GSC                 |  | Gas Supply Clause                              
|Holding Company Act |  | Public Utility Holding Company Act of 1935     
|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                             
|Kva                 |  | Kilovolt-ampere                                
|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                            
|Merger Agreement    |  | Agreement and Plan of Merger dated May 20, 1997
|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                              
|NOx                 |  | Nitrogen Oxide                                 
|OMU                 |  | Owensboro Municipal Utilities                  
|OVEC                |  | Ohio Valley Electric Corporation               

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|PBR                 |  | Performance-Based Ratemaking               
|------------------- |  | -------------------------------------------
|Powergen            |  | Powergen plc                               
|PUHCA               |  | Public Utility Holding Company Act of 1935 
|S&P                 |  | Standard & Poor's Rating Services          
|SCR                 |  | Selective Catalytic Reduction              
|SEC                 |  | Securities And Exchange Commission         
|SERP                |  | Supplemental Employee Retirement Plan      
|SFAS                |  | Statement of Financial Accounting Standards
|SIP                 |  | State Implementation Plan                  
|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 Commission Staff                  

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PART I.

Item 1. Business.

On December 11, 2000, LG&E Energy Corp. was acquired by Powergen plc. for cash of approximately $3.2 billion or $24.85 per share and the assumption of all of LG&E
Energy's debt. As a result of the acquisition, among other things, LG&E Energy became a wholly owned subsidiary of Powergen and, as a result, LG&E and KU became indirect subsidiaries of Powergen. The
utility operations (LG&E and KU) of LG&E Energy have continued their separate identities and continue to serve customers in Kentucky and Virginia under their existing names. The preferred stock and
debt securities of the utility operations were not affected by this transaction resulting in the utility operations' obligations to continue to file SEC reports. Following the acquistion, Powergen
became a registered holding company under PUHCA, and LG&E and KU, as subsidiaries of a registered holding company, became subject to additional regulation under PUHCA.

As
a result of the Powergen acquisition and in order to comply with the Public Utility Holding Company Act of 1935, LG&E Services was formed as a subsidiary of LG&E Energy and became
effective on January 1, 2001. LG&E Services provides certain services to affiliated entities, including LG&E and KU, at cost as required under the Holding Company Act. On January 1, 2001,
approximately 1,000 employees, mainly from LG&E Energy, LG&E and KU, were moved to LG&E Services.

On
April 9, 2001, a German power company, E.ON AG, announced a preconditional cash offer of £5.1 billion ($7.3 billion) for Powergen. The offer is subject to a number of
conditions, including the receipt of certain European and United States regulatory approvals. The Kentucky Public Service Commission, the Federal Energy Regulatory Commission, the Virginia State
Corporation Commission, and the Tennessee Regulatory Authority have all approved the acquisition of Powergen and LG&E Energy by E.ON. The parties expect to obtain the remaining regulatory approvals
and to complete the transaction in the first half of 2002. See Powergen's schedule 14D-9, and associated schedules to such filings, filed with the SEC on April 9, 2001.

LOUISVILLE GAS AND ELECTRIC COMPANY

General

Incorporated on July 2, 1913, LG&E is a regulated public utility that supplies natural gas to approximately 305,000 customers and electricity to approximately
378,000 customers in Louisville and adjacent areas in Kentucky. LG&E's service area covers approximately 700 square miles in 17 counties and has an estimated population of one million. Included in
this area is the Fort Knox Military Reservation, to which LG&E transports gas and provides electric service, but which maintains its own distribution systems. LG&E also provides gas service in limited
additional areas. LG&E's coal-fired electric generating plants, which are all equipped with systems to reduce sulfur dioxide emissions, produce most of LG&E's electricity. The remainder is generated
by a hydroelectric power plant and combustion turbines. Underground natural gas storage fields help LG&E provide economical and reliable gas service to customers. See Item 2, Properties.

LG&E
has one wholly owned consolidated subsidiary, LG&E R. LG&E R is a special purpose entity formed in September 2000 to enter into accounts receivable securitization transactions with
LG&E. LG&E R started operations in 2001.

7

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For
the year ended December 31, 2001, 71% of total operating revenues were derived from electric operations and 29% from gas operations. Electric and gas operating revenues and the
percentages by classes of service on a combined basis for this period were as follows:

Electric

Gas

Combined

% Combined(Thousands of $)Residential

$
205,926

$
177,387

$
383,313

47
%Commercial


171,540


70,296


241,836

30Industrial


104,438


15,750


120,188

15Public authorities


53,725


13,223


66,948

8Total retail


535,629


276,656


812,285

100
%Wholesale sales


159,406


5,702


165,108Gas transportednet





6,042


6,042Provision for rate refunds


(720
)




(720
)Miscellaneous


11,610


2,375


13,985Total

$
705,925

$
290,775

$
996,700


See
Note of LG&E's Notes to Financial Statements under Item 8 for financial information concerning segments of business for the three years ended December 31, 2001.

Electric Operations

The sources of LG&E's electric operating revenues and the volumes of sales for the three years ended December 31, 2001, were as follows:

2001

2000

1999ELECTRIC OPERATING REVENUES(Thousands of $):Residential

$
205,926

$
205,105

$
214,733Commercial


171,540


171,414


176,457Industrial


104,438


104,738


111,889Public authorities


53,725


54,270


55,968Total retail


535,629


535,527


559,047Wholesale sales


159,406


165,080


221,336Provision for rate refunds


(720
)

(2,500
)

(1,735
)Miscellaneous


11,610


12,851


12,022Total

$
705,925

$
710,958

$
790,670ELECTRIC SALES (Thousands of Mwh):Residential


3,782


3,722


3,680Commercial


3,395


3,350


3,290Industrial


2,976


3,043


3,047Public authorities


1,224


1,214


1,187Total retail


11,377


11,329


11,204Wholesale sales


6,957


6,834


8,428Total


18,334


18,163


19,632


LG&E
uses efficient coal-fired boilers, fully equipped with sulfur dioxide removal systems, to generate most of its electricity. LG&E's weighted-average system-wide emission rate for
sulfur dioxide

8

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in 2001 was approximately 0.54 lbs./Mmbtu of heat input, with every unit below its emission limit established by the Kentucky Division for Air Quality.

The
2001 maximum local peak load of 2,522 Mw occurred on Wednesday, August 8, 2001. The record local peak load of 2,612 Mw occurred on Friday, July 30, 1999, when the temperature was 106
degrees F.

The
electric utility business is affected by seasonal weather patterns. As a result, operating revenues (and associated operating expenses) are not generated evenly throughout the year.
See LG&E's Results of Operations under Item 7.

LG&E
currently maintains an 11-14% reserve margin range. At December 31, 2001, LG&E owned steam and combustion turbine generating facilities with a capacity of 2,791 Mw and an 80 Mw
hydroelectric facility on the Ohio River. At December 31, 2001, LG&E's system capability, including purchases from others and excluding the hydroelectric facility, was 2,883 Mw. See Item 2,
Properties.

LG&E
is a participating owner with 14 other electric utilities of Ohio Valley Electric Corporation located in Piketon, Ohio. LG&E has direct interconnections with 11 utility companies in
the area and has agreements with each interconnected utility for the purchase and sale of capacity and energy. LG&E also has agreements with an increasing number of entities throughout the United
States for the purchase and/or sale of capacity and energy and for the utilization of their bulk transmission system.

LG&E
(along with KU) is a founding member of the MISO, such membership obtained in 1998 in response to and consistent with federal policy initiatives. As a MISO member, LG&E filed for
and received authorization from the FERC to transfer control of its transmission facilities (100 kV and above) to the MISO, the first step in allowing the latter to assume responsibility for all
tariff-related transmission functions (e.g.,scheduling through and on LG&E's transmission system) as well as non-tariff related regional transmission
activities (e.g.,operations planning, maintenance coordination, long-term regional planning and market monitoring). The FERC approved the MISO as the
nation's first Regional Transmission Organization on December 19, 2001, after which LG&E submitted a filing at FERC to cancel all services under its Open Access Transmission Tariff except those that
will not be provided by the MISO (certain ancillary services). The MISO became operational on February 1, 2002.

In
October 2001, the FERC issued an order requiring that the bundled retail 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, including start-up capital (debt) costs. LG&E, along with several other transmission owners, opposed
the FERC's ruling in this regard, which opposition the FERC rejected in an order on rehearing issued in 2002. As of the end of 2001, negotiations were continuing between MISO, its transmission owners
and other interested industry segments regarding the level of cost responsibility properly borne by bundled and grandfathered load under these FERC rulings. Absent settlement, this issue is expected
to go to hearing in 2002.

At
the end of 2001, in response to an earlier FERC ruling, MISO and its transmission owning members (including LG&E) filed to increase MISO's rate of return on equity from 10.5% (a
stipulated
percentage agreed to in 1998) to 13.0%, to compensate MISO's transmission owners for the inherent risks and uncertainties associated with transferring control of their facilities to the MISO. This
issue is expected to go to hearing in 2002.

9

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Gas Operations

The sources of LG&E's gas operating revenues and the volumes of sales for the three years ended December 31, 2001, were as follows:

2001

2000

1999GAS OPERATING REVENUES(Thousands of $):Residential

$
177,387

$
159,670

$
103,655Commercial


70,296


61,888


38,627Industrial


15,750


15,898


10,401Public authorities


13,223


9,193


9,013Total retail


276,656


246,649


161,696Wholesale sales


5,702


17,344


8,118Gas transportednet


6,042


6,922


6,350Miscellaneous


2,375


1,574


1,415Total

$
290,775

$
272,489

$
177,579GAS SALES (Millions of cu. ft.):Residential


20,429


24,274


21,565Commercial


8,587


10,132


9,033Industrial


2,160


3,089


2,781Public authorities


1,681


1,576


2,228Total retail


32,857


39,071


35,607Wholesale sales


1,882


5,115


3,881Gas transported


13,108


14,729


14,014Total


47,847


58,915


53,502


The
gas utility business is affected by seasonal weather patterns. As a result, operating revenues (and associated operating expenses) are not generated evenly throughout the year. See
LG&E's Results of Operations under Item 7.

LG&E
has five underground natural gas storage fields that help provide economical and reliable gas service to ultimate consumers. By using gas storage facilities, LG&E avoids the costs
associated with typically more expensive pipeline transportation capacity to serve peak winter space-heating loads. LG&E stores gas in the summer season for withdrawal in the subsequent winter heating
season. Without its on-system storage capacity, LG&E would be forced to buy additional gas and pipeline transportation services when customer demand increases, which may be when the price for those
items are at their highest. Currently, LG&E buys competitively priced gas from several large suppliers under contracts of varying duration. LG&E's underground storage facilities, in combination with
its purchasing practices, enable it to offer gas sales service at rates which are among the lowest in the nation.

A
number of industrial customers purchase their natural gas requirements directly from alternate suppliers for delivery through LG&E's distribution system. These large industrial
customers account for about one-fourth of LG&E's annual throughput.

The
all-time maximum day gas sendout of 545,000 Mcf occurred on Sunday, January 20, 1985, when the average temperature for the day was -11 degrees F. During 2001, maximum day gas sendout
was 423,000 Mcf, occurring on January 2, when the average temperature for the day was 17 degrees F. Supply on that day consisted of 287,000 Mcf from purchases, 66,000 Mcf delivered from underground

10

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storage, and 70,000 Mcf transported for industrial customers. For a further discussion, see Gas Supply under Item 1.

Rates and Regulation

Following the purchase of LG&E Energy by Powergen, Powergen became a registered holding company under PUHCA. As a result, Powergen, its utility subsidiaries,
including LG&E, and certain of its non-utility subsidiaries are subject to extensive regulation by the SEC under PUHCA with respect to issuances and sales of securities, acquisitions and sales of
certain utility properties, and intra-system sales of certain goods and services. In addition, PUHCA generally limits the ability of registered holding companies to acquire additional public utility
systems and to acquire and retain businesses unrelated to the utility operations of the holding company. Powergen believes that it has adequate authority (including financing authority) under existing
SEC orders and regulations for it and its subsidiaries to conduct their businesses and will seek additional authorization when necessary.

The
Kentucky Commission has regulatory jurisdiction over the rates and service of LG&E and over the issuance of certain of its securities. The Kentucky Commission has the ability to
examine the rates LG&E charges its retail customers at any time. LG&E is a "public utility" as defined in the FPA, and is subject to the jurisdiction of the Department of Energy and FERC with respect
to the matters covered in the FPA, including the sale of electric energy at wholesale in interstate commerce. In addition, FERC has sole jurisdiction over the issuance by LG&E of short-term
securities.

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

LG&E's
electric rates contain a FAC, whereby increases and decreases in the cost of fuel for electric generation are reflected in the rates charged to all electric customers. The
Kentucky Commission requires public hearings at six-month intervals to examine past fuel adjustments, and at two-year intervals to review past operations of the fuel clause and transfer of the then
current fuel adjustment charge or credit to the base charges. The Kentucky Commission also requires that electric utilities, including LG&E, file certain documents relating to fuel procurement and the
purchase of power and energy from other utilities.

LG&E's
electric rates are subject to an ESM. The ESM, in place for three years beginning in 2000, sets an upper and lower point for rate of return on equity, whereby if LG&E's rate of
return for the calendar year falls within the range of 10.5% to 12.5%, no action is necessary. If earnings are above the upper limit, then excess earnings are shared 40% with ratepayers and 60% with
shareholders; if earnings are below the lower limit, then earnings deficiency is recovered 40% from ratepayers and 60% from shareholders. The first ESM filing was made on March 1, 2001, for year ended
December 31, 2000. By order of the Kentucky Commission, rate changes prompted by the ESM filing go into effect in April of each year. At December 31, 2001, LG&E estimated the rate of return to fall
within the 10.5% to 12.5% range, subject to Kentucky Commission approval; therefore no adjustment to the financial statements was made.

LG&E's
rates contain an ECR surcharge which recovers certain costs incurred by LG&E that are required to comply with the Clean Air Act and other environmental regulations. See Note 3 of
LG&E's Notes to Financial Statements under Item 8.

LG&E's
gas rates contain a GSC, whereby increases or decreases in the cost of gas supply are reflected in LG&E's rates, subject to approval by the Kentucky Commission. The GSC procedure
prescribed by order of the Kentucky Commission provides for quarterly rate adjustments to reflect the expected cost of gas supply in that quarter. In addition, the GSC contains a mechanism whereby any
over- or under-recoveries of gas supply cost from prior quarters will be refunded to or recovered from customers through the adjustment factor determined for subsequent quarters. In February 2001, the

11

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Kentucky Commission in response to unusually high gas prices ordered LG&E to make monthly GSC filings. In July 2001, the Kentucky Commission ordered LG&E to return to making quarterly GSC filings.

Integrated
resource planning regulations in Kentucky require LG&E and the other major utilities to make triennial filings with the Kentucky Commission of various historical and
forecasted information
relating to load, capacity margins and demand-side management techniques. LG&E filed its last integrated resource plan in 1999, and anticipates filing a new plan in October 2002.

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

Construction Program and Financing

LG&E's construction program is designed to ensure that there will be adequate capacity and reliability to meet the electric and gas needs of its service area.
These needs are continually being reassessed and appropriate revisions are made, when necessary, in construction schedules. LG&E's estimates of its construction expenditures can vary substantially due
to numerous items beyond LG&E's control, such as changes in rates, economic conditions, construction costs, and new environmental or other governmental laws and regulations.

During
the five years ended December 31, 2001, gross property additions amounted to $841 million. Internally generated funds and external financings for the five-year period were
sufficient to provide for all of these gross additions. The gross additions during this period amounted to approximately 25% of total utility plant at December 31, 2001, and consisted of $683 million
for electric properties and $158 million for gas properties. Gross retirements during the same period were $103 million, consisting of $73 million for electric properties and $30 million for gas
properties.

Coal Supply

Coal-fired generating units provided approximately 98% of LG&E's net kilowatt-hour generation for 2001. The remainder of 2001 net generation was made up of a
hydroelectric plant and natural gas and oil fueled combustion turbine peaking units. Coal will be the predominant fuel used by LG&E in the foreseeable future, with natural gas and oil being used for
peaking capacity and flame stabilization in coal-fired boilers or in emergencies. LG&E has no nuclear generating units and has no plans to build any in the foreseeable future. LG&E has entered into
coal supply agreements with various suppliers for coal deliveries for 2002 and beyond. LG&E normally augments its coal supply agreements with spot market purchases. LG&E has a coal inventory policy
which it believes provides adequate protection under most contingencies. LG&E had a coal inventory of approximately 1,042,864 tons, or a 53-day supply, on hand at December 31, 2001.

LG&E
expects to continue purchasing most of its coal, which has a 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 to enable LG&E to continue to provide adequate electric service in compliance with existing environmental laws and regulations.

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

12

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The
historical average delivered costs of coal purchased by LG&E were as follows:

2001

2000

1999Per ton

$
21.27

$
20.96

$
21.49Per Mmbtu

$
.93

$
.92

$
.95Spot purchases as % of all sources


3
%

1
%

5
%


The
delivered cost of coal is expected to increase during 2002 due to the replacement of contracts that expired in 2001 at higher current market prices.

Gas Supply

LG&E purchases natural gas supplies from multiple sources under contracts for varying periods of time, while transportation services are purchased from Texas Gas
Transmission Corporation and Tennessee Gas Pipeline Company.

During
2000, Texas Gas filed with FERC for a change in its rates as required under the settlement in its last rate case. After a series of settlement conferences during 2001, the
intervening parties reached a settlement that is supported or not opposed by essentially all of Texas Gas' local distribution company customers and the state commissions that regulate them. Texas Gas
filed a Stipulation and Agreement with FERC on August 14, 2001. The settlement will resolve all issues set for hearing in these proceedings. It provides significant benefits to consumers in the form
of lower rates, refunds with interest, and a three-year rate increase moratorium that will provide a measure of rate certainty to the Texas Gas system. As a result, FERC should be in a position to
approve the settlement in 2002. LG&E will receive a refund from Texas Gas if FERC approves the Stipulation and Agreement in Docket No. RP00-260. LG&E participates in that and other proceedings, as
appropriate.

LG&E
transports on the Texas Gas system under NNS and FT rate schedules. During the winter months, LG&E has 184,900 Mmbtu/day in NNS and 18,000 Mmbtu/day in FT. LG&E's summer NNS levels
are 60,000 Mmbtu/day and its summer FT levels are 54,000 Mmbtu/day. Each of these NNS and FT agreements with Texas Gas are subject to termination by LG&E in equal portions during 2005, 2006, and 2008.
LG&E also transports on the Tennessee Gas system under Tennessee's Gas FT-A rate schedule. LG&E's contract levels with Tennessee Gas are 51,000 Mmbtu/ day throughout the year. The FT-A agreement with
Tennessee Gas is subject to termination by LG&E during 2002.

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

LG&E
owns and operates five underground gas storage fields with a current working gas capacity of about 15.1 million Mcf. Gas is purchased and injected into storage during the summer
season and is then withdrawn to supplement pipeline supplies to meet the gas-system load requirements during the winter heating season. See Gas Supply under Item 1.

The
estimated maximum deliverability from storage during the early part of the 2000-2001 heating season was approximately 373,000 Mcf/day. Deliverability decreases during the latter
portion of the heating season as the storage inventory is reduced by seasonal withdrawals.

The
average cost per Mcf of natural gas purchased by LG&E was $5.27 in 2001, $5.08 in 2000 and $2.99 in 1999. Although natural gas prices in the unregulated wholesale market increased
significantly throughout 2000 and early 2001, these prices have decreased dramatically since then. Decreasing natural gas prices have been brought about by increased natural gas exploration activity,
excess gas in national storage inventories, decreased demand associated with a less robust economy, and warmer than normal winter weather.

13

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Environmental Matters

Protection of the environment is a major priority for LG&E. Federal, state, and local regulatory agencies have issued LG&E permits for various activities subject
to air quality, water quality, and waste management laws and regulations. For the five-year period ending with 2001, expenditures for pollution control facilities represented $186 million or 22% of
total construction expenditures. LG&E estimates that construction expenditures for the installation of NOx control equipment from 2002 through 2004 will be approximately $84 million. For a discussion
of environmental matters, see Rates and Regulation for LG&E under Item 7 and Note 12 of LG&E's Notes to Financial Statements under Item 8.

Competition

In the last several years, LG&E has taken many 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 deferred expenses; an increase in focus on commercial, industrial and residential customers; an increase in employee involvement and
training; a major realignment and formation of new business units, and continuous modifications of its organizational structure. LG&E will continue to take additional steps to better position itself
for competition in the future. See Note 16 of LG&E's Notes to Financial Statements under Item 8.

14

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KENTUCKY UTILITIES COMPANY

General

KU,
incorporated in Kentucky in 1912 and incorporated in Virginia in 1991, is a regulated public utility engaged in producing, transmitting and selling electric energy. KU provides
electric service to approximately 469,000 customers in over 600 communities and adjacent suburban and rural areas in 77 counties in central, southeastern and western Kentucky, and to approximately
30,000 customers in 5 counties in southwestern Virginia. In Virginia, KU operates under the name Old Dominion Power Company. KU operates under appropriate franchises in substantially all of the 160
Kentucky incorporated municipalities served. No franchises are required in unincorporated Kentucky or Virginia communities. The lack of franchises is not expected to have a material adverse effect on
KU's operations.KU also sells wholesale electric energy to 12 municipalities.

KU
has one wholly owned consolidated subsidiary, KU R. KU R is a special purpose entity formed in September 2000 to enter into accounts receivable securitization transactions with KU. KU
R began operations in 2001.

Electric Operations

The
sources of KU's electric operating revenues and the volumes of sales for the three years ended December 31, 2001, were as follows:

|                                              |              | 2001 |         | 2000    |   | 1999    |        
|--------------------------------------------- | ------------ | ---- | ------- | ------- | - | ------- | -------
|ELECTRIC OPERATING REVENUES (Thousands of $): |              |      |         |         |   |         |        
|Residential                                   |              | $    | 244,004 |         | $ | 241,783 |        
|Commercial                                    |              |      | 165,389 |         |   | 161,291 |        
|Industrial                                    |              |      | 146,968 |         |   | 153,017 |        
|Mine Power                                    |              |      | 28,196  |         |   | 27,089  |        
|Public authorities                            |              |      | 58,770  |         |   | 57,979  |        
|                                              |              |      |         |         |   |         |        
|                                              | Total retail |      |         | 643,327 |   |         | 641,159
|Wholesale sales                               |              |      | 203,181 |         |   | 198,073 |        
|Provision for rate refunds                    |              |      | (954    | )       |   |        |        
|Miscellaneous                                 |              |      | 13,918  |         |   | 12,709  |        
|                                              |              |      |         |         |   |         |        
|                                              | Total        |      | $       | 859,472 |   | $       | 851,941
|                                              |              |      |         |         |   |         |        
|ELECTRIC SALES (Thousands of Mwh):            |              |      |         |         |   |         |        
|Residential                                   |              |      | 5,678   |         |   | 5,714   |        
|Commercial                                    |              |      | 3,990   |         |   | 3,954   |        
|Industrial                                    |              |      | 4,716   |         |   | 5,044   |        
|Mine Power                                    |              |      | 771     |         |   | 767     |        
|Public authorities                            |              |      | 1,481   |         |   | 1,495   |        
|                                              |              |      |         |         |   |         |        
|                                              | Total retail |      |         | 16,636  |   |         | 16,974 
|Wholesale sales                               |              |      | 7,713   |         |   | 7,573   |        
|                                              |              |      |         |         |   |         |        
|                                              | Total        |      |         | 24,349  |   |         | 24,547 
|                                              |              |      |         |         |   |         |        

The
electric utility business is affected by seasonal weather patterns. As a result, operating revenues (and associated operating expenses) are not generated evenly
throughout the year. See KU's Results of Operations under Item 7.

KU's
weighted-average system-wide emission rate for sulfur dioxide in 2001 was approximately 1.3 lbs./Mmbtu of heat input, with every unit below its emission limit established by the
Kentucky Division for Air Quality.

KU
currently maintains an 11-14% reserve margin range. At December 31, 2001, KU owned steam and combustion turbine generating facilities with a capacity of 3,968 Mw and a 24 Mw
hydroelectric

15

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facility. See Item 2, Properties. KU obtains power from other utilities under bulk power purchase and interchange contracts. At December 31, 2001, KU's system capability, including purchases from
others and excluding the hydroelectric facility, was 4,458 Mw. The 2001 maximum local peak load of 3,699 Mw occurred on Wednesday, August 8, 2001. The record local peak load of 3,775 Mw occurred on
August 9, 2000.

Under
a contract expiring in 2020 with OMU, KU has agreed to purchase from OMU the surplus output of the 150-Mw and 250-Mw generating units at OMU's Elmer Smith station. Purchases under
the contract are made under a contractual formula which has resulted in costs which were and are expected to be comparable to the cost of other power purchased or generated by KU. Such power
constituted about 7% of KU's net system output during 2001. See Note 11 of KU's Notes to Financial Statements under Item 8.

KU
owns 20% of the common stock of EEI, which owns and operates a 1,000-Mw generating station in southern Illinois. KU is entitled to take 20% of the available capacity of the station.
Purchases from EEI are made under a contractual formula which has resulted in costs which were and are expected to be comparable to the cost of other power purchased or generated by KU. Such power
constituted about 6% of KU's net system output in 2001. See Note 11 of KU's Notes to Financial Statements under Item 8.

KU
is a participating owner with 14 other electric utilities of Ohio Valley Electric Corporation located in Piketon, Ohio.

KU
(along with LG&E) is a founding member of MISO, such membership obtained in 1998 in response to and consistent with federal policy initiatives. As a MISO member, KU filed for and
received authorization from FERC to transfer control of its transmission facilities (100 kV and above) to the MISO, the first step in allowing the latter to assume responsibility for all
tariff-related transmission functions (e.g.,scheduling through and on KU's transmission system) as well as non-tariff related regional transmission
activities (e.g.,operations planning, maintenance coordination, long-term regional planning and market monitoring). The FERC approved the MISO as the
nation's first Regional Transmission Organization on December 19, 2001, after which KU submitted a filing at FERC to cancel all services under its Open Access Transmission Tariff except those that
will not be provided by the MISO (certain ancillary services). The MISO became operational on February 1, 2002.

In
October 2001, the FERC issued an order requiring that the bundled retail load and grandfathered wholesale load of each member transmission owner (including KU) be included in the
current calculation of MISO's "cost-adder," a charge designed to recover MISO's costs of operation, including start-up capital (debt) costs. KU, along with several other transmission owners, opposed
the FERC's ruling in this regard, which opposition the FERC rejected in an order on rehearing issued in 2002. As of the end of 2001, negotiations were continuing between MISO, its transmission owners
and other interested industry segments regarding the level of cost responsibility properly borne by bundled and grandfathered load under these FERC rulings. Absent settlement, this issue is expected
to go to hearing in 2002.

At
the end of 2001, in response to an earlier FERC ruling, MISO and its transmission owning members (including KU) filed to increase MISO's rate of return on equity from 10.5% (a
stipulated percentage agreed to in 1998) to 13.0%, to compensate MISO's transmission owners for the inherent risks and uncertainties associated with transferring control of their facilities to the
MISO. This issue is expected to go to hearing in 2002.

16

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Rates and Regulation

Following
the purchase of LG&E Energy by Powergen, Powergen became a registered holding company under PUHCA. As a result, Powergen, its utility subsidiaries, including KU, and certain of
its non-utility subsidiaries are subject to extensive regulation by the SEC under PUHCA with respect to issuances and sales of securities, acquisitions and sales of certain utility properties, and
intra-system sales of certain goods and services. In addition, PUHCA generally limits the ability of registered holding companies to acquire additional public utility systems and to acquire and retain
businesses unrelated to the utility operations of the holding company. Powergen believes that it has adequate authority (including financing authority) under existing SEC orders and regulations for it
and its subsidiaries to conduct their businesses and will seek additional authorization when necessary.

The
Kentucky Commission and the Virginia Commission have regulatory jurisdiction over KU's retail rates and service, and over the issuance of certain of its securities. By reason of
owning and operating a small amount of electric utility property in one county in Tennessee (having a gross book value of approximately $225,000) from which KU serves five customers, 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 utility facilities and operations,
wholesale sale of power and related transactions and accounting practices of KU, and in certain other respects as provided in the FPA. In addition, the FERC has sole jurisdiction over the issuance by
KU of short-term securities.

For
a discussion of current regulatory matters, see Rates and Regulation for KU under Item 7 and Note 3 of KU's Notes to the Financial Statements under Item 8.

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

KU's
Kentucky retail electric rates are subject to an ESM. The ESM, in place for three years beginning 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 of 10.5% to 12.5%, no action is necessary. If earnings are above the upper limit, then excess earnings are shared 40% with ratepayers
and 60% with shareholders; if earnings are below the lower limit, then earnings deficiency is recovered 40% from ratepayers and 60% from shareholders.The first ESM filing was made on March 1, 2001, for year ended December 31,
2000. By order of the Kentucky Commission, rate changes prompted by the ESM filing go into effect in April of each year. At December 31, 2001, KU estimated the rate of return to fall within the range,
subject to Kentucky Commission approval; therefore no adjustment was made to the financial statements.

KU's
Kentucky rates contain an ECR surcharge which recovers certain costs incurred by KU that are required to comply with the Clean Air Act and other environmental regulations. See Note
3 of KU's Notes to Financial Statements under Item 8.

Integrated
resource planning regulations in Kentucky require KU and the other major utilities to make triennial filings with the Kentucky Commission of various historical and forecasted
information relating to load, capacity margins and demand-side management techniques. KU filed its last integrated resource plan in 1999, and anticipates filing a new plan in October 2002.

17

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

The
state of Virginia passed the Virginia Electric Utility Restructuring Act in 1999. This act gives Virginia customers a choice for energy services. The change will be phased in
gradually between January 2002 and January 2004. KU customers will have retail choice beginning January 1, 2004. KU filed unbundled rates that became effective January 1, 2002. Rates are capped at
current levels through June 2007. The Virginia Commission will continue to require each Virginia utility to make annual filings of either a base rate change or an Annual Informational Filing
consisting of a set of standard financial schedules. The Virginia Staff will issue a Staff Report regarding the individual utility's financial performance during the historic 12-month period. The
Staff Report can lead to an adjustment in rates, but through June 2007 will be limited to decreases. Because KU has a small number of customers in Virginia, all of which are served at competitive
rates, KU shall seek an exemption from the Virginia Commission Rules Governing Retail Access to Competitive Energy Services by applying for a waiver to exempt KU from modifying the current billing
infrastructure.

Construction Program and Financing

KU's
construction program is designed to ensure that there will be adequate capacity and reliability to meet the electric needs of its service area. These needs are continually being
reassessed and appropriate revisions are made, when necessary, in construction schedules. KU's estimates of its construction expenditures can vary substantially due to numerous items beyond KU's
control, such as changes in rates, economic conditions, construction costs, and new environmental or other governmental laws and regulations.

During
the five years ended December 31, 2001, gross property additions amounted to $610 million. Internally generated funds and external financings for the five-year period were
sufficient to provide for all of these gross additions. The gross additions during this period amounted to approximately 20% of total utility plant at December 31, 2001. Gross retirements during the
same period were $90 million.

Coal Supply

Coal-fired
generating units provided approximately 99% of KU's net kilowatt-hour generation for 2001. The remainder of KU's net generation for 2001 was provided by oil and natural gas
burning units and hydroelectric plants. The historical average delivered cost of coal purchased and the percentage of spot coal purchases were as follows:

2001

2000

1999Per ton

$
27.84

$
25.63

$
26.65Per Mmbtu

$
1.20

$
1.07

$
1.11Spot purchases as % of all sources


44
%

51
%

53
%


KU's
historical average cost of coal purchased is higher than LG&E's due to the lower sulfur content of the coal KU purchases for use at its Ghent plant and higher cost to transport coal
to the E.W. Brown plant. The delivered cost of coal is expected to increase during 2002.

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

18

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KU
believes there are adequate reserves available to supply its existing base-load generating units with the quantity and quality of coal required for those units throughout their useful
lives. KU intends to meet a portion of its coal requirements with three-year or shorter contracts. As part of this strategy, KU will continue to negotiate replacement contracts as contracts expire. KU
does not anticipate any problems negotiating new contracts for future coal needs. The balance of coal requirements will be met through spot purchases. KU had a coal inventory of approximately
1,361,781 tons, or a 60-day supply, on hand at December 31, 2001.

KU
expects to continue purchasing most of its coal, which has a sulfur content in the .7%3.5% range, from western and eastern Kentucky, West Virginia, southwest Indiana,
Wyoming and Pennsylvania for the foreseeable future.

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

Environmental Matters

Protection
of the environment is a major priority for KU. Federal, state, and local regulatory agencies have issued KU permits for various activities subject to air quality, water
quality, and waste management laws and regulations. For the five-year period ending with 2001, expenditures for pollution control facilities represented $24 million or 4% of total construction
expenditures. KU estimates that construction expenditures for the installation of nitrogen oxide control equipment from 2002 through
2004 will be approximately $181 million. See Note 11 of KU's Notes to Financial Statements under Item 8.

Competition

KU
has taken many steps to prepare for the expected increase in competition in its industry, including a reduction in the number of employees; aggressive cost cutting; an increase in
focus on not only commercial and industrial customers, but residential customers as well; an increase in employee involvement and training; and continuous modifications of its organizational
structure. KU will continue to take additional steps to better position itself for competition in the future. See Note 14 of KU's Notes to Financial Statements under Item 8.

19

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EMPLOYEES AND LABOR RELATIONS

LG&E had 907 full-time employees and KU had 1,008 full-time employees at December 31, 2001. Of the LG&E total, 647 operating, maintenance, and construction
employees were members of IBEW Local 2100. LG&E and IBEW Local 2100 signed a four-year contract in November 2001. Of the KU total, 171 operating, maintenance and construction employees were members of
IBEW Local 2100 and USWA Local 9447-01. In August 2001, KU and employees represented by IBEW Local 2100 entered into a two-year collective bargaining agreement. KU and employees represented by USWA
entered into a two-year collective bargaining agreement effective August 2000 and expiring July 31, 2002. In July 2001, KU and employees represented by USWA entered into a wage reopener whereby higher
wages were negotiated.

As
a result of the Powergen acquisition and in order to comply with the Public Utility Holding Company Act of 1935, LG&E Services was formed and became effective on January 1, 2001. LG&E
Services provides certain services to affiliated entities, including LG&E and KU, at cost as required under the Holding Company Act. On January 1, 2001, approximately 1,000 employees, mainly from LG&E
Energy, LG&E and KU, were moved to LG&E Services.

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

Executive
Officers of LG&E and KU at December 31, 2001:

|Name                    |  | Age |  | Position                                                          |  | Effective Date of
Election to Present
Position
|----------------------- |  | --- |  | ----------------------------------------------------------------- |  | ----------------------------------------------
|Victor A. Staffieri     |  | 46  |  | Chairman of the Board, President and Chief Executive Officer      |  | May 1, 2001                                   
|Richard Aitken-Davies   |  | 52  |  | Chief Financial Officer                                           |  | January 31, 2001                              
|John R. McCall          |  | 58  |  | Executive Vice President, General Counsel and Corporate Secretary |  | July 1, 1994                                  
|Frederick J. Newton III |  | 46  |  | Senior Vice President and Chief Administrative Officer            |  | January 2, 1999                               
|S. Bradford Rives       |  | 43  |  | Senior Vice PresidentFinance and Controller                      |  | December 11, 2000                             
|Paul W. Thompson        |  | 45  |  | Senior Vice PresidentEnergy Services                             |  | June 7, 2000                                  
|Chris Hermann           |  | 54  |  | Senior Vice PresidentDistribution Operations                     |  | December 11, 2000                             
|Wendy C. Welsh          |  | 48  |  | Senior Vice PresidentInformation Technology                      |  | December 11, 2000                             
|Martyn Gallus           |  | 37  |  | Senior Vice PresidentEnergy Marketing                            |  | December 11, 2000                             
|Roger A. Smith          |  | 49  |  | Senior Vice President Project Engineering                         |  | December 11, 2000                             
|David A. Vogel          |  | 36  |  | Vice PresidentRetail Services                                    |  | December 11, 2000                             
|Daniel K. Arbough       |  | 40  |  | Treasurer                                                         |  | December 11, 2000                             
|Bruce Hamilton          |  | 46  |  | Vice President Power Operations                                   |  | December 11, 2000                             
|Robert E. Henriques     |  | 60  |  | Vice President Plant Operations                                   |  | December 11, 2000                             
|Michael S. Beer         |  | 43  |  | Vice PresidentRates and Regulatory                               |  | February 1, 2001                              
|George R. Siemens       |  | 52  |  | Vice PresidentExternal Affairs                                   |  | January 11, 2001                              

The present term of office of each of the above executive officers extends to the meeting of the Board of Directors following the 2002 Annual
Meeting of Shareholders.

There
are no family relationships between or among executive officers of LG&E and KU. The above tables indicate officers serving as executive officers of both LG&E and KU at December 31,
2001. Each of the above officers serves in the same capacity for LG&E and KU.

Before
he was elected to his current positions, Mr. Staffieri was President of LG&E from January 1994 to May 1997; President-Distribution Services of LG&E Energy Corp. from December 1995
to May 1997; Chief Financial Officer of LG&E Energy Corp. and LG&E from May 1997 to February

20

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2000; Chief Financial Officer of KU from May 1998 to February 2000; and President and Chief Operating Officer of LG&E Energy Corp., LG&E and KU from June 2000 to May 2001.

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

Before
he was elected to his current positions, Mr. McCall was Executive Vice President, General Counsel and Corporate Secretary of LG&E Energy Corp. and LG&E from July 1994 to the
present. He became Executive Vice President, General Counsel and Corporate Secretary of KU on May 4, 1998.

Before
he was elected to his current positions, Mr. Newton was Director of Human Resources, Manufacturing and Engineering at Unilever from October 1993 to July 1995; Senior Director,
Human Resources, Supply Chain, at Unilever from August 1995 to July 1996; Vice President, Human Resources, at Venator Group from August 1996 to July 1997; Senior Vice President, Human Resources, at
Venator Group's Champs Sports Division from August 1997 to April 1998; and Senior Vice PresidentHuman Resources and Administration of LG&E Energy Corp., LG&E and KU from May 1998 to
January 1999.

Before
he was elected to his current positions, Mr. Rives was Vice President and Treasurer of LG&E Power Inc. from June 1994 to March 1995; Vice President, Controller and Treasurer of
LG&E Power Inc. from March 1995 to December 1995; Vice PresidentFinance, Non-Utility Businesses of LG&E Energy Corp. from January 1996 to March 1996; Vice PresidentFinance
and Controller of LG&E Energy Corp. from March 1996 to February 1999; and Senior Vice PresidentFinance and Business Development from February 1999 to December 2000.

Before
he was elected to his current positions, Mr. Thompson was Vice PresidentBusiness Development for LG&E Energy Corp. from July 1994 to September 1996; Vice President,
Retail Electric Business for LG&E from September 1996 to June 1998; Group Vice President for LG&E Energy Marketing, Inc. from June 1998 to August 1999; Vice President, Retail Electric Business for
LG&E from December 1998 to August 1999; and Senior Vice PresidentEnergy Services for LG&E Energy Corp. since August 1999.

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

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

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

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

21

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Before
he was elected to his current positions, Mr. Vogel served in management positions within the Distribution Department of LG&E and KU during the five prior years to this report. In
his position prior to his current role he was responsible for statewide outage management and restoration of distribution network.

Before
he was elected to his current position, Mr. Arbough was Manager, Corporate Finance of LG&E Energy Corp., and LG&E from August 1996 to May 1998; Director, Corporate Finance of LG&E
Energy Corp., LG&E and KU from May 1998 to present.

Before
he was elected to his current position, Mr. Hamilton was Venture Manager from May 1992 to 1994; Senior Venture Manager from 1994 to 1996, Vice President, Asset Management from
1996 to 2000 and Vice President, Independent Power Operations, January 2001 to present.

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

Before
he was elected to his current position in February of 2001, Mr. Beer was Senior Counsel Specialist, Regulatory from February 2000 to February 2001; and Senior Corporate Attorney
from February 1998 to February 2000. Prior to joining LG&E Energy Corp., Mr. Beer was Director, Federal Regulatory Affairs, for Illinois Power Company in Decatur, Illinois, from February of 1997 to
January of 1998.

Before
he was elected to his current position as Vice President of External Affairs for LG&E Energy, which he has held since January 2001, Mr. Siemens held the position of Director of
External Affairs for LG&E from August 1982 to December 2000.

ITEM 2.    Properties.

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

Capability
Rating (Kw)Steam Stations:Mill CreekKosmosdale, KYUnit 1

303,000Unit 2

301,000Unit 3

386,000Unit 4

480,000Total Mill Creek

1,470,000Cane Runnear Louisville, KYUnit 4

155,000Unit 5

168,000Unit 6

240,000Total Cane Run

563,000Trimble CountyBedford, KY (a)Unit 1

371,000Combustion Turbine Generators (Peaking capability):Zorn

16,000Paddy's Run (b)

127,000Cane Run

16,000Waterside

33,000E.W. Brown (c)

195,000Total combustion turbine generators

387,000Total capability rating

2,791,000


22

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---

LG&E also owns an 80 Mw hydroelectric generating station located in Louisville, operated under license issued by the FERC.

At
December 31, 2001, LG&E's electric transmission system included 21 substations with a total capacity of approximately 11,519,700 Kva and approximately 656 structure miles of lines.
The electric distribution system included 84 substations with a total capacity of approximately 3,448,730 Kva, 3,718 structure miles of overhead lines, 379 miles of underground conduit, and 5,827
miles of underground conductors.

LG&E's
gas transmission system includes 212 miles of transmission mains, and the gas distribution system includes 3,914 miles of distribution mains.

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

In
1990, LG&E entered into an operating lease for its corporate office building located in downtown Louisville, Kentucky. The lease is for a period of 15 years and is scheduled to expire
June 2005.

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

The
trust indenture securing LG&E's First Mortgage Bonds constitutes a direct first mortgage lien upon much of the property owned by LG&E.

KU's
power generating system consists of the coal-fired units operated at its five steam generating stations. Combustion turbines supplement the system during peak or emergency periods.
KU owns and operates the following electric generating stations:

|                                 |        | Capability
Rating (Kw)
|-------------------------------- | ------ | ----------------------
|Steam Stations:                  |        |                       
|TyroneTyrone, KY                |        |                       
|                                 | Unit 1 |                       
|                                 | Unit 2 |                       
|                                 | Unit 3 |                       
|                                 |        |                       
|                                 |        | Total Tyrone          
|Green RiverSouth Carrollton, KY |        |                       
|                                 | Unit 1 |                       
|                                 | Unit 2 |                       
|                                 | Unit 3 |                       
|                                 | Unit 4 |                       
|                                 |        |                       
|                                 |        | Total Green River     

23

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|E.W. BrownBurgin, KY                               |        |                                    
|--------------------------------------------------- | ------ | -----------------------------------
|                                                    | Unit 1 |                                    
|                                                    | Unit 2 |                                    
|                                                    | Unit 3 |                                    
|                                                    |        |                                    
|                                                    |        | Total E.W. Brown                   
|PinevilleFour Mile, KY. (a)                        |        |                                    
|                                                    | Unit 3 |                                    
|GhentGhent, KY.                                    |        |                                    
|                                                    | Unit 1 |                                    
|                                                    | Unit 2 |                                    
|                                                    | Unit 3 |                                    
|                                                    | Unit 4 |                                    
|                                                    |        |                                    
|                                                    |        | Total Ghent                        
|Combustion Turbine Generators (Peaking capability): |        |                                    
|E.W. BrownBurgin, KY. (Units 6-11) (b)             |        | 786,000                            
|HaeflingLexington, KY.                             |        | 45,000                             
|Paddys RunLouisville, KY (c)                       |        | 74,000                             
|                                                    |        |                                    
|                                                    |        | Total combustion turbine generators
|                                                    |        |                                    
|Total capability rating                             |        | 3,968,000                          
|                                                    |        |                                    

---

Substantially all properties are subject to the lien of KU's Mortgage Indenture.

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, 2001, KU's electric transmission system included 112 substations with a total capacity of approximately 14,855,396 Kva and approximately 4,409 structure miles of lines.
The electric distribution system included 438 substations with a total capacity of approximately 5,046,307 Kva and 14,924 structure miles of lines.

ITEM 3.    Legal Proceedings.

Rates and Regulatory Matters

For a discussion of current regulatory matters, including, among others, a discussion of settlement agreements with the Kentucky Commission regarding rate matters
related to LG&E's and KU's environmental cost recovery surcharge refunds, fuel adjustment clause proceedings and regulatory assets, depreciation and amortization matters, see Rates and Regulation
under Item 7 and Note 3 of LG&E's Notes to Financial Statements and Note 3 of KU's Notes to Financial Statements under Item 8.

24

---

Alternative Ratemaking

In October 1998, LG&E and KU filed applications with the Kentucky Commission for approval of the PBR proposal for determining electric rates. In January 2000, the
Kentucky Commission issued orders requiring LG&E and KU to reduce annual base rates, effective March 1, 2000. The orders also eliminated the temporary effectiveness of the PBR proposal, reinstated the
FAC mechanism and offered the utilities a three year ESM program whereby incremental annual earnings above or below a range of 10.5% to 12.5% would be shared 60% with shareholders and 40% with
ratepayers. In February 2000, LG&E and KU filed tariffs incorporating the ESM. In June 2000, the Kentucky Commission issued orders reducing the original January 2000 base rate reductions to now
require reductions in base rates of approximately $26.3 million at LG&E and $30.4 million at KU, effective June 1, 2000. The orders implemented LG&E's and KU's ESM tariffs, with certain modifications,
for a three year term. No parties filed appeals from the Kentucky Commission's orders within the time allowed by statute. See Rates and Regulations under Item 7 and Note 3 to LG&E's Notes to Financial
Statements and Note 3 to KU's Notes to Financial Statements under Item 8.

Fuel Adjustment Clause Proceedings

Pursuant to Kentucky statute, LG&E and KU operate under six-month and two-year reviews by the Kentucky Commission of the fuel cost incurred to serve their
customers. Both LG&E and KU have participated in proceedings in front of the Kentucky Commission concerning the recovery of fuel costs associated with wholesale sales and recovery of purchased power
energy costs. As a result of these proceedings, the Kentucky Commission issued an order in July 1999 requiring KU to refund a total of $10.1 million to ratepayers. The amount was reduced to $6.7
million in August 1999, which amount was refunded over the 12-month period beginning October 1999; the period covered by the order was November 1994 through October 1998. The Kentucky Commission
issued an order in February 1999 requiring LG&E to refund $3.9 million to ratepayers, of which $1.9 million was refunded in April 1999. As a result of a rehearing, the Kentucky Commission ordered a
refund totaling $800,000 for the period November 1996 through April 1998. This refund was paid in January 2000. The PSC orders from February 1999 (LG&E) and August 1999 (KU) were each appealed by KU
and LG&E and the intervenor group in 2000. Pending a decision on these appeals, a comprehensive settlement was reached by all parties, which settlement was filed with the Kentucky Commission on
December 21, 2001. Under that settlement, LG&E and KU agreed to credit their respective fuel clauses in the amount of $720,000 and $954,000, respectively (such credit provided over the course of two
monthly billing periods), and the parties agreed on a prospective interpretation of Kentucky's fuel adjustment clause regulation to ensure consistent and mutually acceptable application on a
going-forward basis. All pending FAC proceedings before the court were resolved by the parties to the agreement and all parties requested the Court of Appeals remand the case to the Kentucky
Commission for final approval. The Kentucky Commission is expected to approve the settlement in 2002. See also Note 3 to LG&E's Notes to Financial Statements and Note 3 to KU's Notes to Financial
Statements under Item 8.

Environmental

For a discussion of environmental matters concerning (a) currently proposed reductions in NOx emission limits, (b) issues at LG&E's Mill Creek generating plant
and LG&E's and KU's manufactured gas plant sites, and (c) other environmental items affecting LG&E and KU, see Environmental Matters under Item 7 and Note 12 of LG&E's Notes to Financial Statements
and Note 11 of KU's Notes to Financial Statements under Item 8, respectively.

E.ONPowergen Transaction

In April 2001, E.ON AG announced a conditional offer to purchase all the common shares of Powergen plc, the indirect corporate parent of LG&E and KU. The
transaction is subject to a number

25

---

of conditions precedent, including the receipt of regulatory approvals from European and United States governmental bodies, in form satisfactory to the parties. Regulatory orders approving the E.ON
transaction were received from the Kentucky Commission in August 2001 and from the Virginia State Corporation Commission, the Federal Energy Regulatory Commission and the TRA, respectively, in
October 2001. The parties anticipate that remaining approvals may be received in the near future to permit completion of the transaction during the first half of 2002. However, there can be no
assurance that such approvals will be obtained in form or timing sufficient for such dates. For further discussion also see Business under Item 1.

Preferred Stock

In October 2001, the Boards of Directors of LG&E and KU authorized the delisting of LG&E's 5% Preferred Stock, par value $25 per share, from the NASDAQ Small
Capitalization Market and KU's 4.75% Preferred Stock, stated value $100 per share, from the Philadelphia Stock Exchange, respectively. The delistings could occur following applications to the relevant
exchanges and applicable regulatory agencies, if any. Delisting does not constitute a change in the terms and conditions of the respective preferred stock series nor the rights and privileges of their
shareholders. The delistings are proposed in order to enable LG&E and KU to realize certain administrative and corporate governance efficiencies.

Other

In
the normal course of business, other lawsuits, claims, environmental actions, and other governmental proceedings arise against LG&E and KU. To the extent that damages are assessed in
any of these lawsuits, LG&E and KU believe that their insurance coverage is adequate. Management, after consultation with legal counsel, does not anticipate that liabilities arising out of other
currently pending or threatened lawsuits and claims will have a material adverse effect on LG&E's or KU's consolidated financial position or results of operations, respectively.

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





26

---



2.    KU





27

---



PART II.

ITEM 5. Market for the Registrant's Common Equity and Related Stockholder Matters.

LG&E:

All
LG&E common stock, 21,294,223 shares, is held by LG&E Energy. Therefore, there is no public market for LG&E's common stock.

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

2001

2000First quarter

$
0

$
23,000Second quarter


0


16,500Third quarter


0


16,500Fourth quarter


23,000


17,000


KU:

All
KU common stock, 37,817,878 shares, is held by LG&E Energy. Therefore, there is no public market for KU's common stock.

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

2001

2000First quarter

$
0

$
19,000Second quarter


0


25,000Third quarter


0


25,000Fourth quarter


30,500


25,500


28

---

ITEM 6. Selected Financial Data.

|                                                              |                          | Years Ended December 31
(Thousands of $)
|------------------------------------------------------------- | ------------------------ | ----------------------------------------
|
|LG&E:                                                         |                          |                                         
|Operating revenues:                                           |                          |                                         
|Revenues                                                      |                          | $                                       
|Provision for rate refunds                                    |                          |                                         
|                                                              |                          |                                         
|                                                              | Total operating revenues |                                         
|                                                              |                          |                                         
|Net operating income                                          |                          |                                         
|                                                              |                          |                                         
|Net income:                                                   |                          |                                         
|Before unusual items                                          |                          |                                         
|Merger costs                                                  |                          |                                         
|                                                              |                          |                                         
|Net income                                                    |                          |                                         
|                                                              |                          |                                         
|Net income available for common stock                         |                          |                                         
|                                                              |                          |                                         
|Total assets                                                  |                          |                                         
|                                                              |                          |                                         
|Long-term obligations (including amounts due within one year) |                          | $                                       
|                                                              |                          |                                         

29

---

LG&E's
Management's Discussion and Analysis of Financial Condition and Results of Operation and LG&E's Notes to Financial Statements should be read in conjunction with the above
information.

|                                                              |                          | Years Ended December 31
(Thousands of $)
|------------------------------------------------------------- | ------------------------ | ----------------------------------------
|
|KU:                                                           |                          |                                         
|Operating revenues:                                           |                          |                                         
|Revenues                                                      |                          | $                                       
|Provision for rate refunds                                    |                          |                                         
|                                                              |                          |                                         
|                                                              | Total operating revenues |                                         
|                                                              |                          |                                         
|Net operating income:                                         |                          |                                         
|Before unusual items                                          |                          |                                         
|Non-recurring charge                                          |                          |                                         
|                                                              |                          |                                         
|                                                              | Net operating income     |                                         
|                                                              |                          |                                         
|Net income:                                                   |                          |                                         
|Before unusual items                                          |                          |                                         
|Non-recurring charge                                          |                          |                                         
|Merger costs                                                  |                          |                                         
|                                                              |                          |                                         
|                                                              |                          | Net income                              
|                                                              |                          |                                         
|Net income available for common stock                         |                          |                                         
|                                                              |                          |                                         
|Total assets                                                  |                          |                                         
|                                                              |                          |                                         
|Long-term obligations (including amounts due within one year) |                          | $                                       
|                                                              |                          |                                         

KU's
Management's Discussion and Analysis of Financial Condition and Results of Operation and KU's Notes to Financial Statements should be read in conjunction with the above information.

30

---

ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operation.

LG&E:

GENERAL

The following discussion and analysis by management focuses on those factors that had a material effect on LG&E's financial results of operations and financial
condition during 2001, 2000, and 1999 and should be read in connection with the financial statements and notes thereto.

Some
of the following discussion may contain forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to
be identified in this document by the words "anticipate," "expect," "estimate," "objective," "possible," "potential" and similar expressions. Actual results may vary materially. Factors that could
cause actual results to differ materially include; general economic conditions; business and competitive conditions in the energy industry; changes in federal or state legislation; unusual weather;
actions by state or federal regulatory agencies; and other factors described from time to time in LG&E's reports to the Securities and Exchange Commission, including Exhibit No. 99.01 to this report
on Form 10-K.

MERGERS and ACQUISITIONS

On April 9, 2001, a German power company, E.ON AG, announced a preconditional cash offer of £5.1 billion ($7.3 billion) for Powergen. The offer is
subject to a number of conditions, including the receipt of certain European and United States regulatory approvals. The Kentucky Public Service Commission, the Federal Energy Regulatory Commission,
the Virginia State Corporation Commission, and the Tennessee Regulatory Authority have all approved the acquisition of Powergen and LG&E Energy by
E.ON. The parties expect to obtain the remaining regulatory approvals and to complete the transaction in the first half of 2002. See Powergen's schedule 14D-9, and associated schedules to such
filings, filed with the SEC on April 9, 2001.

On
December 11, 2000, LG&E Energy Corp. was acquired by Powergen plc. for cash of approximately $3.2 billion or $24.85 per share and the assumption of all of LG&E Energy's debt. As a
result of the acquisition, LG&E Energy became a wholly owned subsidiary of Powergen and, as a result, LG&E became an indirect subsidiary of Powergen. LG&E has continued its separate identity and
serves customers in Kentucky under its existing name. The preferred stock and debt securities of LG&E were not affected by this transaction and LG&E continues to file SEC reports. Following the
acquisition, Powergen became a registered holding company under PUHCA, and LG&E, as a subsidiary of a registered holding company, became subject to additional regulation under PUHCA. See "Rates and
Regulation" under Item 1.

RESULTS OF OPERATIONS

Net Income

LG&E's net income decreased $3.8 million for 2001, as compared to 2000. This decrease is mainly due to higher pension related expenses and amortization of
regulatory assets, partially offset by increased electric and gas net revenues (operating revenues less fuel for electric generation, power purchased and gas supply expenses) and decreased interest
expenses.

LG&E's
net income increased $4.3 million for 2000, as compared to 1999. This increase is mainly due to higher gas sales resulting from the colder winter weather experienced in 2000,
lower administrative costs and operating expenses at the electric generating stations, partially offset by decreased electric revenues due to a rate reduction ordered by the Kentucky Commission,
higher maintenance and interest expenses.

31

---

Revenues

A comparison of operating revenues for the years 2001 and 2000, excluding the provisions recorded for refunds in 2001 and in 2000, 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 PeriodElectric Revenues

Gas RevenuesCause2001

2000

2001

2000Retail sales:Fuel and gas supply adjustments, etc.

$
(394
)
$
(9,027
)
$
79,627

$
57,156LG&E/KU Merger surcredit


(2,456
)

(2,331
)




ESM/Performance based rate


1,962


4,114





Environmental cost recovery surcharge


1,246


(1,308
)




Electric rate reduction


(3,671
)

(20,727
)




VDT surcredit


(1,014
)




(68
)

Gas rate increase








15,265


4,221Variation in sales volumes, etc.


4,429


5,759


(64,817
)

23,576Total retail sales


102


(23,520
)

30,007


84,953Wholesale sales


(5,674
)

(56,256
)

(11,642
)

9,226Gas transportationnet








(880
)

572Other


(1,241
)

829


801


159Total

$
(6,813
)
$
(78,947
)
$
18,286

$
94,910


Electric
revenues decreased in 2001 primarily due to a decrease in brokered activity in the wholesale electric sales market, an electric rate reduction ordered by the Kentucky Commission
and the effects of the LG&E/KU merger surcredit (See Note 2 of LG&E's Notes to Financial Statements under Item 8) partially offset by an increase in electric retail sales. In January 2000, the
Kentucky Commission ordered an electric rate reduction and the termination of LG&E's proposed electric PBR mechanism. Gas revenues in 2001 increased primarily as a result of higher gas supply costs
billed to customers through the gas supply clause and the effects of a gas rate increase ordered by the Kentucky Commission in September 2000. The gas revenue increase was partially offset by a
decrease in retail and wholesale gas sales in 2001 due to warmer weather; heating degree days decreased 10.2% as compared to 2000.

Electric
revenues decreased in 2000 primarily due to a decrease in brokered activity in the wholesale electric sales market and the electric rate reduction ordered by the Kentucky
Commission. In January 2000, the Kentucky Commission ordered an electric rate reduction and the termination of LG&E's proposed electric PBR mechanism. Gas revenues increased in 2000 primarily as a
result of higher gas supply costs billed to customers through the gas supply clause, coupled with increased gas sales in 2000 due to colder weather, as heating degree days increased 15% over 1999.
Increased wholesale gas sales, and the effects of a gas rate increase ordered by the Kentucky Commission in September 2000 also contributed to increased gas revenues.

Expenses

Fuel for electric generation and gas supply expenses comprises a large component of LG&E's total operating costs. LG&E's electric rates contain a FAC and gas
rates contain a GSC, whereby increases
or decreases in the cost of fuel and gas supply are reflected in the FAC and GSC factors, subject to approval by the Kentucky Commission. In July 1999, the Kentucky Commission implemented rates
proposed in LG&E's PBR filing resulting in the discontinuance of the FAC. In January 2000, the Kentucky Commission rescinded the PBR rates and ordered the reinstatement of the FAC. See Note 3

32

---

of LG&E's Notes to Financial Statements under Item 8 for a further discussion of the PBR and the FAC.

Fuel
for electric generation decreased $.2 million (.1%) in 2001 primarily due to decreased generation as a result of decreased electric sales ($2.2 million) partially offset by a higher
cost of coal burned ($2.0 million). Fuel for electric generation increased $.3 million (.2%) in 2000 because of an increase in generation to support increased electric sales ($7.6 million), offset
partially by a lower cost of coal burned ($7.3 million). The average delivered cost per ton of coal purchased was $21.27 in 2001, $20.96 in 2000, and $21.49 in 1999.

Power
purchased decreased $15.4 million (15.9%) in 2001 primarily due to decreased brokered sales activity in the wholesale electric market and a lower unit cost of the purchases
partially offset by an increase in purchases to meet requirements for native load and off-system sales. Power purchased decreased $72.7 million (42.9%) in 2000 primarily due to decreased brokered
sales activity in the wholesale electric market.

Gas
supply expenses increased $9.3 million (4.7%) in 2001 primarily due to an increase in cost of net gas supply ($36.2 million), partially offset by a decrease in the volume of gas
delivered to the distribution system ($26.9 million). Gas supply expenses increased $82.2 million (71.6%) in 2000 primarily due to an increase in cost of net gas supply ($70.4 million), and due to an
increase in the volume of gas delivered to the distribution system ($11.8 million). The average unit cost per Mcf of purchased gas was $5.26 in 2001, $5.08 in 2000, and $2.99 in 1999.

Other
operation expenses increased $31.9 million (23.4%) in 2001 primarily due to amortization of a regulatory asset resulting from workforce reduction costs associated with LG&E's Value
Delivery initiative ($13 million), an increase in pension expense ($10.3 million) and an increase in outside services ($8.5 million). Outside services increased in part due to the reclassification of
expenses as a result of the formation of LG&E Services, as required by the SEC to comply with PUHCA. Operation expenses decreased $18.7 million (12.1%) in 2000 primarily due to lower administrative
costs, $13.8 million, (due to decreases in pension expense, $5.4 million, year 2000 Information Technology expenses, $4.0 million, and decreased salaries due to fewer employees in 2000, $2.0 million)
and a decrease in steam production costs primarily at the Mill Creek generating station ($5.0 million).

Maintenance
expenses for 2001 decreased $5.0 million (7.9%) primarily due to decreases in scheduled outages ($2.8 million), and a decrease in software and communication equipment
maintenance ($2.8 million). Maintenance expenses for 2000 increased $5.6 million (9.6%) primarily due to an increase in
software maintenance agreements ($3.9 million), and maintenance of communications equipment ($1.5 million).

Depreciation
and amortization increased $2.1 million (2.1%) in 2001 and increased $1.1 million (1.1%) in 2000 because of additional utility plant in service in both years. The 2001
increase was offset by a decrease in depreciation rates resulting from a settlement order in December 2001 from the Kentucky Commission. Depreciation expenses decreased by $5.6 million as a result of
the settlement order.

Property
and other taxes decreased $1.2 million (6.5%) in 2001 primarily due to a reduction in payroll taxes related to fewer employees as a result of workforce reductions and transfers
to LG&E Services. Property and other taxes increased $2.1 million (12.1%) in 2000 primarily due to increased payroll and property taxes.

Other
incomenet decreased $2.0 million (40.5%) in 2001 primarily due to lower interest and dividend income. Other incomenet increased $.8 million (18.9%) in
2000 primarily due to increased tax benefits recorded associated with increased non-debt related interest expenses.

33

---

Interest
charges for 2001 decreased $5.3 million (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) and an increase in interest associated with LG&E's accounts receivable securitization program ($2.5 million).
Interest charges for 2000 increased $5.3 million (13.9%) due to having short-term borrowings for entire 2000 as compared to two months in 1999 ($7.1 million), partially offset by a decrease in
interest on debt to associated companies ($1.0 million) and lower interest rates on variable rate debt ($1.0 million). See Note 10 of LG&E's Notes to Financial Statements under Item 8.

LG&E's
weighted average cost of long-term debt was 4.17% at December 31, 2001. See Note 10 of LG&E's Notes to Financial Statements under Item 8.

Variations
in income tax expenses are largely attributable to changes in pre-tax income. The increase in LG&E's 2001 effective income tax rate to 36.5% from the 35.8% rate in 2000 was
largely the result of lost tax benefits attributable to LG&E's Employee Stock Ownership Plan. These benefits ceased as a result of the December 2000 acquisition of LG&E Energy Corp. by Powergen.

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

CRITICAL ACCOUNTING POLICIES

Preparation of financial statements and related disclosures in compliance with generally accepted accounting principles (GAAP) requires the application of
appropriate technical accounting rules and guidance, as well as the use of estimates. The application of these policies necessarily involves judgments regarding future events, including the likelihood
of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments, in and of themselves, could materially impact the financial statements and
disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment also may have a significant effect, not only on the operation of the
business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies
applied has not changed. The following list represents accounting policies that are most significant to LG&E's financial condition and results, and that require management judgments. Each of these has
a higher likelihood of resulting in materially different

34

---

reported amounts under different conditions or using different assumptions. See also Note 1 of LG&E's Notes to Financial Statements under Item 8.

|Accounting Policy                |  | Judgment/Uncertainties                                                                                                                                   |  | See Also
Under Item 8
|-------------------------------- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ---------------------
|Unbilled Revenue                 |  | Projecting customer electric
    and gas usage
Estimating impact of weather                                                                              |  | Note 1               
|Benefit Plan Accounting          |  | Future rate of returns on pension plan assets
Interest rates used in valuing benefit obligation
Health care cost trend rates
Other actuarial assumptions |  | Note 7               
|Derivative Financial Instruments |  | Market conditions in energy industry
Price volatility                                                                                                    |  | Note 4               
|Income Tax                       |  | Application of tax statutes and regulations to
    transactions
Future decisions of tax authorities                                                      |  | Note 8               
|Regulatory Mechanisms            |  | Future regulatory decisions
Impact of deregulation and competition on
    ratemaking process
External regulator decisions                                |  | Note 3               

NEW ACCOUNTING PRONOUNCEMENTS

During 2001 and 2000, the following accounting pronouncements were issued that affect LG&E:

SFAS
No. 133,Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138, Accounting for
Certain Derivative Instruments and Certain Hedging Activities,establishes accounting and reporting standards requiring that every derivative instrument (including certain
derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or a liability measured at its fair value. SFAS No. 133 requires that changes in the
derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset
related results on the hedged item in the income statement, and requires that LG&E must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. SFAS
No. 133 could increase the volatility in earnings and other comprehensive income. SFAS No. 137,Accounting for Derivative Instruments and Hedging
ActivitiesDeferral of the Effective Date of SFAS No. 133, deferred the effective date of SFAS No. 133 until January 1, 2001. LG&E adopted SFAS No. 133 and SFAS No.
138 on January 1, 2001. The effect of adopting these statements resulted in a $3.6 million decrease in other comprehensive income from a cumulative effect of change in accounting principle (net of tax
of $2.4 million).

The
Financial Accounting Standards Board created the Derivatives Implementation Group (DIG) to provide guidance for implementation of SFAS No. 133. DIG Issue C15,
Normal Purchases and Normal Sales Exception for Option Type Contracts and Forward Contracts in Electricitywas adopted in 2001 and had no impact on results of operations and
financial positions. DIG Issue C16,Applying the Normal Purchases and Normal Sales Exception to Contracts that Combine a Forward Contract and a Purchased Option
Contract, was cleared in 2001 and stated that option contracts do not meet the

35

---

normal purchases and normal sales exception and should follow SFAS No. 133. DIG C16 will be effective in the second quarter of 2002. LG&E has not determined the impact this issue will have on its
results of operations and financial position.

SFAS
No. 140,Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, revises the standards for
accounting for securitizations and other transfers of financial assets and collateral and requires certain disclosures, and provides accounting and reporting standards for transfers and servicing of
financial assets and extinguishments of liabilities. SFAS No. 140 was adopted in the first quarter of 2001, when LG&E entered into an accounts receivable securitization transaction.

SFAS
No. 141,Business Combinationsand SFAS No. 142,Goodwill and Other Intangible Assetswere issued in 2001. SFAS No. 141 requires all business combinations initiated after June 30, 2001, to be accounted for using the purchase method. SFAS No. 142 requires goodwill to be recorded, but
not amortized. Further, goodwill will now be subject to a periodic assessment for impairment. The provisions of these new pronouncements were effective July 1, 2001, for LG&E. The adoption of these
standards did not have a material impact on the results of operations or financial position of LG&E.

SFAS
No. 143,Accounting for Asset Retirement Obligationsand SFAS No. 144,Accounting for the Impairment or
Disposal of Long-Lived Assets, were issued 2001. SFAS No. 143 establishes accounting and reporting standards for obligations associated with the retirement of tangible
long-lived assets and the associated asset retirement costs. SFAS No. 144 supersedes SFAS No. 121,Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Ofand the accounting and reporting provisions of APB Opinion No. 30,Reporting the Results of
OperationsReporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions.SFAS No.
144, among other provisions, eliminates the requirement of SFAS No. 121 to allocate goodwill to long-lived assets to be tested for impairment. The effective implementation date for SFAS No. 144 is
2002 and SFAS No. 143 is 2003. Based on current regulatory accounting practices, management does not expect SFAS No. 143 or SFAS No. 144 to have a material impact on results of
operations or financial position of LG&E.

LIQUIDITY AND CAPITAL RESOURCES

LG&E uses net cash generated from its operations and external financing to fund construction of plant and equipment and the payment of dividends. LG&E believes
that such sources of funds will be sufficient to meet the needs of its business in the foreseeable future.

Operating Activities

Cash provided by operations was $287 million, $156 million and $180 million in 2001, 2000, and 1999, respectively. The 2001 increase resulted primarily from the
change in accounts receivable including the sale of accounts receivable through the accounts receivable securitization program. See Note 1 of LG&E's Notes to Financial Statements under Item 8. The
2000 decrease resulted primarily from an increase in accounts receivable, and a decrease in accrued taxes. 1999 showed a lower level of non-cash
income statement items and a net decrease in net current assets, primarily resulting from decreases in accounts payable and accrued taxes.

Investing Activities

LG&E's primary use of funds for investing activities continues to be for capital expenditures. Capital expenditures were $253 million, $144 million and $195
million in 2001, 2000, and 1999, respectively. LG&E expects its capital expenditures for 2002 and 2003 to total approximately $334 million, which consists primarily of construction estimates
associated with installation of NOx equipment as described in the section titled "Environmental Matters," purchase of two jointly owned CTs with KU and on-going construction for the distribution
systems.

36

---

Net
cash used for investment activities increased $108 million in 2001 as compared to 2000, and decreased by $43 million in 2000 as compared to 1999, primarily due to the level of
construction expenditures. NOx expenditures in 2001 were approximately $75 million.

Financing Activities

Net cash outflows for financing activities were $39 million and $68 million in 2001 and 2000, respectively. Net cash inflow from financing activities in 1999 was
$26.7 million. During 2001, LG&E issued $10.1 million of pollution control bonds resulting in net proceeds of $9.7 million after issuance costs. Dividend payments also decreased in 2001. In 2000,
total debt was reduced by $20 million to $606.8 million. LG&E also refinanced $108.3 million ($106.5 million net of issuance costs) of its pollution control bonds in 2000. LG&E received $40 million in
contributed capital from its parent company in December 2000.

LG&E
participates in an intercompany money pool agreement whereby LG&E Energy can make funds available to LG&E at market based rates up to $200 million. At December 31, 2001, the balance
of the money pool loan from LG&E Energy was $64.2 million at an average rate of 2.37%, and LG&E had outstanding commercial paper of $30 million at an average rate of 2.54%. The resulting remaining
money pool availability at December 31, 2001, was $105.8 million. LG&E Energy maintains a facility of $200 million with an affiliate to ensure funding availability for the money pool. There was no
outstanding balance under this facility as of December 31, 2001, and availability of $170 million remains after considering the $30 million of commercial paper outstanding at LG&E.

At
December 31, 2000, the money pool loan balance was $114.6 million at an average rate of 6.84% and LG&E had no commercial paper outstanding.

Under
the provisions for LG&E's variable-rate pollution control bonds totaling $242.6 million, the bonds are subject to tender for purchase at the option of the holder and to mandatory
tender for purchase upon the occurrence of certain events, causing the bonds to be classified as current portion of long-term debt.

On
March 6, 2002, LG&E refinanced its $22.5 million and $27.5 million 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 unsecured pollution control bonds due November 1, 2027. The replacement variable rate bonds are secured by first mortgage bonds and
will mature November 1, 2027.

Future Capital Requirements

Future capital requirements may be affected in varying degrees by factors such as load growth, changes in construction expenditure levels, rate actions by
regulatory agencies, new legislation, market entry of competing electric power generators, changes in environmental regulations and other regulatory requirements. LG&E anticipates funding future
capital requirements through operating cash flow, debt, and/or infusions of capital from its parent.

LG&E's
debt ratings as of January 31, 2002, were:

Moody's

S&P

FitchFirst mortgage bonds

A1

A-

A+Unsecured debt

A2

BBB

APreferred stock

a2

BBB-

A-Commercial paper

P-1

A-2

F-1


37

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The
S&P ratings are on Credit Watch with positive implications. The Fitch ratings are on Credit WatchEvolving status. These ratings reflect the views of Moody's, S & P and
Fitch. A security rating is not a recommendation to buy, sell or hold securities and is subject to revision or withdrawal at any time by the rating agency.

Contractual Obligations

The following is provided to summarize LG&E's contractual cash obligations for periods after December 31, 2001 (in thousands of $):

|                                      |  | Payments Due by Period
|------------------------------------- |  | ----------------------
|
|Long-term debt(a)                     |  | $                     
|Operating leases                      |  |                       
|Unconditional purchase obligations(b) |  |                       
|Other long-term obligations(c)        |  |                       
|                                      |  |                       
|Total contractual cash obligations    |  | $                     
|                                      |  |                       

---

Market Risks

LG&E is exposed to market risks from changes in interest rates and commodity prices. To mitigate changes in cash flows attributable to these exposures, LG&E uses
various financial instruments including derivatives. Derivative positions are monitored using techniques that include market value and sensitivity analysis. See Note 1 and 4 of LG&E's Notes to
Financial Statements under Item 8.

Interest Rate Sensitivity

LG&E has short-term and long-term variable rate debt obligations outstanding. At December 31, 2001, the potential change in interest expense associated with a 1%
change in base interest rates of LG&E's unhedged debt was estimated at $2.8 million.

Interest
rate swaps are used to hedge LG&E's underlying variable-rate debt obligations. These swaps hedge specific debt issuance and, consistent with management's designation, are
accorded hedge accounting treatment.

As
of December 31, 2001, LG&E had swaps with a combined notional value of $117.3 million. The swaps exchange floating-rate interest payments for fixed interest payments to reduce the
impact of interest rate changes on LG&E's Pollution Control Bonds. As of December 31, 2001, 30% of the outstanding variable interest rate borrowings were converted to fixed interest rates through
swaps. The potential loss in fair value resulting from a hypothetical 1% adverse movement in base interest rates is estimated at $9.1 million as of December 31, 2001.This
estimate is derived from third party valuations.Changes in the market value of these swaps if held to maturity, as LG&E intends to do, are not expected to have any effect on
LG&E's net income or cash flow. See Note 4 of LG&E's Notes to Financial Statements under Item 8.

38

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Energy Trading & Risk Management Activities

LG&E conducts energy trading and risk management activities to maximize the value of power sales from physical assets it owns, in addition to the wholesale sale
of excess asset capacity. Certain energy trading activities are accounted for on a mark-to-market basis in accordance withEITF 98-10 Accounting for Contracts Involved in
Energy Trading and Risk Management Activities, SFAS No. 133 Accounting for Derivative Instruments and Hedging Activities,andSFAS No. 138 Accounting
for Certain Derivative Instruments and Certain Hedging Activities. Wholesale sales of excess asset capacity and wholesale purchases are treated as normal sales and purchases
underSFAS No. 133andSFAS No. 138and are not marked to market.

The
table below summarizes LG&E's energy trading and risk management activities in 2001 (in thousands of $).

Fair value of contracts at 12/31/00, net liability

$
(17
)Fair value of contracts when entered into during 2001


3,441Contracts realized or otherwise settled during 2001


(2,894
)Changes in fair values due to changes in assumptions


(716
)Fair value of contracts at 12/31/01, net liability

$
(186
)


No
changes to valuation techniques for energy trading and risk management activities occurred during 2001. All contracts outstanding at December 31, 2001 have a maturity of less than one
year and are valued using prices actively quoted for proposed or executed transactions or quoted by brokers.

LG&E
maintains policies intended to minimize credit risk and revalues credit exposures daily to monitor compliance with those policies. As December 31, 2001, 100% of the trading and risk
management commitments were with counterparties rated BBB equivalent or better.

Commodity Price Sensitivity

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

Accounts Receivable Securitization

On February 6, 2001, LG&E implemented an accounts receivable securitization program. The purpose of this program is to enable LG&E to accelerate the receipt of
cash from the collection of retail accounts receivable, thereby reducing dependence upon more costly sources of working capital. The securitization program allows for a percentage of eligible
receivables to be sold. Eligible receivables are generally all receivables associated with retail sales that have standard terms and are not past due. LG&E is able to terminate these programs at any
time without penalty. If there is a significant deterioration in the payment record of the receivables by the retail customers or if LG&E fails to meet certain covenants regarding the program, the
program may terminateat the election of the financial institutions. In this case, payments from retail customers would first be used to repay the
financial institutions participating in the program, and would then be available for use by LG&E.

39

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As part of the program, LG&E sold retail accounts receivables to a wholly owned subsidiary, LG&E R. Simultaneously, LG&E R entered into two separate three-year accounts receivable
securitization facilities with two financial institutions and their affiliates whereby LG&E R can sell, on a revolving basis, an undivided interest in certain of their receivables and receive up to
$75 million from an unrelated third party purchaser. The effective cost of the receivables programs is comparable to LG&E's lowest cost source of capital, and is based on prime rated commercial paper.
LG&E retains servicing rights of the sold receivables through two separate servicing agreements with the third party purchaser. LG&E has obtained an opinion from independent legal counsel indicating
these transactions qualify as true sale of receivables. As of December 31, 2001, the outstanding program balance was $42 million.

Management
expects to renew these facilities when they expire.

The
allowance for doubtful accounts associated with the eligible securitized receivables was $1.3 million at December 31, 2001. This allowance is based on historical experience of LG&E.
Each securitization facility contains a fully funded reserve for uncollectible receivables.

Rates and Regulation

Following the purchase of LG&E Energy by Powergen, Powergen became a registered holding company under PUHCA. As a result, Powergen, its utility subsidiaries,
including LG&E, and certain of its non-utility subsidiaries are subject to extensive regulation by the SEC under PUHCA with respect to issuances and sales of securities, acquisitions and sales of
certain utility properties, and intra-system sales of certain goods and services. In addition, PUHCA generally limits the ability of registered holding companies to acquire additional public utility
systems and to acquire and retain businesses unrelated to the utility operations of the holding company. Powergen believes that it has adequate authority (including financing authority) under existing
SEC orders and regulations for it and its subsidiaries to conduct their businesses and will seek additional authorization when necessary.

LG&E
is subject to the jurisdiction of the Kentucky Commission in virtually all matters related to electric and gas utility regulation, and as such, their accounting is subject to SFAS
No. 71,Accounting for the Effects of Certain Types of Regulation. Given LG&E's competitive position in the marketplace and the status of regulation in
the state of Kentucky, LG&E has no plans or intentions to discontinue its application of SFAS No. 71. See Note 3 of LG&E's Notes to Financial Statements under Item 8.



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

On
June 1, 2001, LG&E filed an application (VDT case) with the Kentucky Commission to create a regulatory asset relating to these first quarter 2001 charges. The application requested
permission to amortize these costs over a four-year period. The Kentucky Commission also opened a case to review the new depreciation study and resulting depreciation rates implemented in 2001.

LG&E
reached a settlement in the VDT case as well as the other cases involving depreciation rates and ESM with all intervening parties. The settlement agreement was approved by the
Kentucky Commission on December 3, 2001.

The
Kentucky Commission December 3, 2001, order allowed LG&E to set up a regulatory asset of $141 million for the workforce reduction costs and begin amortizing these costs over a five
year period starting in April 2001. The first quarter charge of $144 million represented all employees who had accepted a voluntary enhanced severance program. Some employees rescinded their
participation in the

40

---

voluntary enhanced severance program, thereby decreasing the original charge from $144 million to $141 million. The settlement will also reduce revenues approximately $26 million through a surcredit
on future bills to customers over the same five year period. The surcredit represents stipulated net savings LG&E is expected to realize from implementation of best practices through the value
delivery process. The agreement also established LG&E's new depreciation rates in effect December 2001, retroactive to January 1, 2001. The new depreciation rates decreased depreciation expense by
$5.6 million in 2001.



In August 1999, a final order of the Kentucky Commission approved LG&E's settlement agreement concerning the refund of the recovery of costs associated with
pre-1993 environmental projects. LG&E began applying the refund to customers' bills in October 1999, and completed the refund process in November 2000. All aspects of the original litigation of this
issue have now been resolved.

In
June 2000, the Kentucky Commission approved LG&E's application for a CCN to construct up to three SCR NOx reduction facilities. The construction and subsequent operation of the SCRs
is intended to reduce NOx emission levels to meet the EPA's mandated NOx emission level of 0.15 lbs./ Mmbtu by May 2004. In its order, the Kentucky Commission ruled that LG&E's proposed plan for
construction was "reasonable, cost-effective and will not result in the wasteful duplication of facilities." In October 2000, LG&E filed an application with the Kentucky Commission to amend its
Environmental Compliance Plan to reflect the addition of the proposed NOx reduction technology projects and to amend its Environmental Cost Recovery Tariff to include an overall rate of return on
capital investments. Following the completion of hearings in March 2001, a ruling was issued in April 2001 granting LG&E's application. Such approval has allowed LG&E to begin to recover the costs
associated with these new projects, subject to Kentucky Commission oversight during normal six-month and two-year reviews.



LG&E's electric rates are subject to an ESM. The ESM, in place for three years beginning in 2000, sets an upper and lower point for rate of return on equity,
whereby if LG&E's rate of return for the calendar year falls within the range of 10.5% to 12.5%, no action is necessary. If earnings are above the upper limit, then excess earnings are shared 40% with
ratepayers and 60% with shareholders; if earnings are below the lower limit, then earnings deficiency is recovered 40% from ratepayers and 60% from shareholders. The first ESM filing was made on March
1, 2001, for year ended December 31, 2000, which resulted in a refund to customers of $618,000. By order of the Kentucky Commission, rate changes prompted by the ESM filing go into effect in April of
each year. LG&E estimated that the rate of return will fall within the deadband range, subject to Kentucky Commission approval, for the year ended December 31, 2001; therefore, no adjustment to the
financial statements was made.



LG&E's rates contain a DSM provision. The provision includes a rate mechanism that provides concurrent recovery of DSM costs and provides an incentive for
implementing DSM programs. This program had allowed LG&E to recover revenues from lost sales associated with the DSM program. In May 2001, the Kentucky Commission approved LG&E's plan to continue DSM
programs. This filing called for the expansion of the DSM programs into the service territory served by KU and proposes a mechanism to recover revenues from lost sales associated with DSM programs
based on program planning engineering estimates and post-implementation evaluation.

41

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Since November 1, 1997, LG&E has operated under an experimental performance-based ratemaking mechanism related to its gas procurement activities. For each of the
last four years, LG&E's rates have been adjusted to recover its portion of the savings (or expenses) incurred during each of the four 12-month periods beginning November 1 and ending October 31. Since
its implementation on November 1, 1997, through October 31, 2001, LG&E has achieved $32.1 million in savings. Of the total savings, LG&E has retained $15.0 million, and the remaining portion of $17.1
million has been distributed to customers. In December 2000, LG&E filed an Application reporting on the operation of the experimental PBR and requested the Kentucky Commission to extend the PBR as a
result of the benefits provided to both LG&E and its customers during the experimental period. Following the discovery and hearing process, the Kentucky Commission issued an order effective November
1, 2001, extending the experimental PBR program for an additional four years, and making other modifications, including changes to the sharing levels applicable to savings or expenses incurred under
the PBR. Specifically, the Kentucky Commission modified the sharing mechanism to a 25%/75% Company/Customer sharing for all savings (and expenses) up to 4.5% of the benchmarked gas costs. Savings (and
expenses) in excess of 4.5% of the benchmarked gas costs are shared at the 50%/50% level.



Prior to implementation of the PBR in July 1999, and following its termination in March 2000, LG&E employed an FAC mechanism, which under Kentucky law allowed
LG&E to recover from customers the actual fuel costs associated with retail electric sales. In February 1999, LG&E received orders from the Kentucky Commission requiring a refund to retail electric
customers of approximately $3.9 million resulting from reviews of the FAC from November 1994, through April 1998, of which $1.9 million was refunded in April 1999, for the period beginning November
1994, and ending October 1996. The orders changed LG&E's method of computing fuel costs associated with electric line losses on wholesale sales appropriate for recovery through the FAC. Following
rehearing in December 1999, the Kentucky Commission agreed with LG&E's position on the appropriate loss factor to use in the FAC computation and issued an order reducing the refund level for the
18-month period under review to approximately $800,000. LG&E enacted the refund with billings in the month of January 2000. LG&E and KIUC each filed separate appeals from the Kentucky Commission's
February 1999 orders with the Franklin County, Kentucky Circuit Court and in May 2000, the Court affirmed the Kentucky Commission's orders regarding the amounts disallowed and ordered the case
remanded as to the Kentucky Commission's denial of interest, directing the Kentucky Commission to determine whether interest should be awarded to LG&E's ratepayers. In June 2000, LG&E appealed the
Circuit Court's decision to the Kentucky Court of Appeals. Pending a decision on this appeal, a comprehensive settlement was reached by all parties, which settlement was filed with the Kentucky
Commission on December 21, 2001. Thereunder, LG&E agreed to credit its fuel clause in the amount of $720,000 (such credit provided over the course of two monthly billing periods), and the parties
agreed on a prospective interpretation of the state's fuel adjustment clause regulation to ensure consistent and mutually acceptable application on a going-forward basis. All pending FAC proceedings
before the court were resolved by the parties to the agreement and all parties requested the Court of Appeals remand the case to the Kentucky Commission. The Kentucky Commission is expected to approve
the settlement in 2002.



In March 2000, LG&E filed an application with the Kentucky Commission requesting an adjustment in LG&E's gas rates. In September 2000, the Kentucky Commission
granted LG&E an annual increase in its base gas revenues of $20.2 million effective September 28, 2000. The Kentucky

42

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Commission authorized a return on equity of 11.25%. The Kentucky Commission approved LG&E's proposal for a weather normalization billing adjustment mechanism that will normalize the effect of weather
on revenues from gas sales.



On September 12, 2000, the Kentucky Commission issued an order establishing Administrative Case No. 384"An Investigation of Increasing Wholesale
Natural Gas Prices and the Impacts of such Increase on the Retail Customers Served by Kentucky's Jurisdictional Natural Gas Distribution Companies". The impetus for this administrative proceeding was
the escalation of wholesale natural gas prices during the summer of 2000.

The
Kentucky Commission directed Kentucky's natural gas distribution companies, including LG&E, to file selected information regarding the individual companies' natural gas purchasing
practices, expectations for the then-approaching winter heating season of 2000-2001, and potential actions which these companies might take to mitigate price volatility. On July 17, 2001, the Kentucky
Commission issued an order encouraging the natural gas distribution companies in Kentucky to take various actions, among them to propose a natural gas hedge plan, consider performance-based ratemaking
mechanisms, and to increase the use of storage.

On
August 12, 2001, LG&E submitted a natural gas hedge plan in Case No. 2001-253. However, due to significantly decreased wholesale natural gas prices during the Summer of 2001, the
Kentucky Commission ultimately rejected LG&E's proposed gas hedging plan as "untimely" in its Order dated October 5, 2001. The Kentucky Commission encouraged LG&E to file another hedge plan for its
consideration in 2002.

Another
result from that Administrative Case was the Kentucky Commission's decision to engage a consultant to conduct a forward-looking audit of the gas procurement and supply procedures
in order to assist both the Kentucky Commission and each of Kentucky's largest natural gas distribution companies. This audit is underway.



In December 1997, the Kentucky Commission opened Administrative Case No. 369 to consider Kentucky Commission policy regarding cost allocations, affiliate
transactions and codes of conduct governing the relationship between utilities and their non-utility operations and affiliates. The Kentucky Commission intended to address two major areas in the
proceedings: the tools and conditions needed to prevent cost shifting and cross-subsidization between regulated and non-utility operations; and whether a code of conduct should be established to
assure that non-utility segments of the holding company are not engaged in practices that could result in unfair competition caused by cost shifting from the non-utility affiliate to the utility.
During the period September 1998 to February 2000, the Kentucky Commission issued draft codes 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 utilities who provide nonregulated activities to keep separate accounts and allocate costs in accordance with
procedures established by the Kentucky Commission. In the same Bill, the General Assembly set forth provisions to govern a utilities activities related to the sharing of information, databases, and
resources between its employees or an affiliate involved in the marketing or the provision of nonregulated activities and its employees or an affiliate involved in the provision of regulated services.
The legislation became law in July 2000 and LG&E has been operating pursuant thereto since that time. On February 14, 2001, the Kentucky Commission published notice of their intent to promulgate new
administrative regulations under the auspices of the new law. This effort is still on going.

43

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On June 19, 2001, Kentucky Governor Paul E. Patton issued Executive Order 2001-771, which directed the Kentucky Commission to review and study issues relating to
the need for and development of new electric generating capacity in Kentucky. The issues to be considered included the impact of new power plants on the electric supply grid, facility siting issues,
and economic development matters, with the goal of ensuring a continued, reliable source of supply of electricity for the citizens of Kentucky and the continued environmental and economic vitality of
the Commonwealth and its communities. In response to that Executive Order, in July 2001 the Kentucky Commission opened Administrative Case No. 387 to review the adequacy of Kentucky's generation
capacity and transmission system. Specifically, the items reviewed were the appropriate level of reliance on purchased power, the appropriate reserve margins to meet existing and future electric
demand, the impact of spikes in natural gas prices on electric utility planning strategies, and the adequacy of Kentucky's electric transmission facilities. LG&E, as a party to this proceeding, filed
written testimony and responded to two requests for information. Public hearings were held in August, September, and October 2001. In October 2001, LG&E filed a final brief in the case. In December
2001 the Kentucky Commission issued an order in which they noted that LG&E is responsibly addressing the long-term supply needs of native load customers and that current reserve margins are
appropriate. However, due to the rapid pace of change
in the industry, the order also requires LG&E to provide an annual assessment of supply resources, future demand, reserve margin, and the need for new resources.

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

The
Kentucky Commission pledged to continue to monitor all relevant issues and advocate Kentucky's interests at all opportunities.



The Clean Air Act imposed stringent new SO2 and NOx emission limits on electric generating units. LG&E previously had installed scrubbers on all of
its generating units. LG&E's strategy for Phase II SO2 reductions, which commenced January 1, 2000, is to increase scrubber removal efficiency to delay additional capital expenditures and
may also include fuel switching or upgrading scrubbers. LG&E met the NOx emission requirements of the Act through installation of low-NOx burner systems. LG&E's compliance plans are subject to many
factors including developments in the emission allowance and fuel markets, future regulatory and legislative initiatives, and advances in clean air control technology. LG&E will continue to monitor
these developments to ensure that its environmental obligations are met in the most efficient and cost-effective manner.

In
September 1998, the EPA announced its final "NOx SIP Call" rule requiring states to impose significant additional reductions in NOx emissions by May 2003, in order to mitigate alleged
ozone transport impacts on the Northeast region. The Commonwealth of Kentucky is currently in the process of revising its State Implementation Plan or "SIP" to require reductions in NOx emissions from
coal-fired generating units to the 0.15 lb./Mmbtu level on a system-wide basis. In related proceedings in 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 directing similar NOx reductions from a number of specifically targeted generating units including all LG&E units. As a result of appeals to both
rules, the compliance date was extended to May 2004. All LG&E generating units are subject to the May 2004 compliance date under these NOx emissions reduction rules.

44

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LG&E
is currently implementing a plan for adding significant additional NOx 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 through the final compliance date. LG&E estimates that it will incur total capital costs of approximately $160 million to reduce its NOx emissions to
the 0.15 lb./Mmbtu level on a company-wide basis. In addition, LG&E will incur additional operating and maintenance costs in operating new NOx controls. LG&E believes its costs in this regard to be
comparable to those of similarly situated utilities with like generation assets. LG&E had anticipated that such capital and operating costs are the type of costs that are eligible for recovery from
customers under its environmental surcharge mechanism and believed that a significant portion of such costs could be recovered. In April 2001, the Kentucky Commission granted recovery of these costs
for LG&E.

LG&E
is also monitoring several other air quality issues which may potentially 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 and particulate matter, measures to implement EPA's regional haze rule, and EPA's December 2000 determination to regulate mercury emissions from power plants. In addition,
LG&E is currently working with local regulatory authorities to review the effectiveness of remedial measures aimed at controlling particulate matter emissions from its Mill Creek Station. LG&E
previously settled a number of property damage claims from adjacent residents and completed significant remedial measures as part of its ongoing capital construction program. LG&E is in the process of
converting the Mill Creek Station to wet stack operation in an effort to resolve all outstanding issues related to particulate matter emissions.

LG&E
owns or formerly owned three properties which are the location of past MGP operations. Various contaminants are typically found at such former MGP sites and environmental
remediation measures are frequently required. With respect to the sites, LG&E has completed cleanups, obtained regulatory approval of site management plans, or reached agreements for other parties to
assume responsibility for cleanup. Based on currently available information, 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 December 31, 2001 and 2000.

See
Note 12 of LG&E's Notes to Financial Statements under Item 8 for an additional discussion of environmental issues.



LG&E expects to have adequate levels of taxable income to realize its recorded deferred tax assets. At December 31, 2001, deferred tax assets totaled $114.4
million and were principally related to expenses attributable to LG&E's pension plans and post retirement benefit obligations.

Future Outlook



LG&E has moved aggressively over the past decade to be positioned for, and to help promote, the energy industry's shift to customer choice and a competitive
market for energy services. Specifically, LG&E has taken many steps to prepare for the expected increase in competition in its business, including support for performance-based ratemaking structures;
aggressive cost reduction activities; strategic acquisitions, dispositions and growth initiatives; write-offs of previously deferred expenses; an increase in focus on commercial and industrial
customers; an increase in employee training; and necessary corporate and business unit realignments. LG&E continues to be active in the national debate surrounding the restructuring of the energy
industry and the move toward a competitive, market-based environment.

45

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

In
November 1999, the task force issued a report to the Governor of Kentucky and a legislative agency recommending no general electric industry restructuring actions during the 2000
legislative session. No general restructuring actions were taken during the 2001 legislative session.

Thus,
at the time of this report, neither the Kentucky General Assembly nor the Kentucky Commission has adopted or approved a plan or timetable for retail electric industry competition
in Kentucky. The nature or timing of the ultimate legislative or regulatory actions regarding industry restructuring and their impact on LG&E, which may be significant, cannot currently be predicted.

While
many states have moved forward in providing retail choice, many others have not. Some are reconsidering their initiatives and have even delayed implementation. Recent activities in
California
that have resulted in extremely high wholesale (and in some cases, consumer) electric prices are becoming significant factors in the deliberations by other states.

KU

General

The following discussion and analysis by management focuses on those factors that had a material effect on KU's financial results of operations and financial
condition during 2001, 2000, and 1999 and should be read in connection with the financial statements and notes thereto.

Some
of the following discussion may contain forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to
be identified in this document by the words "anticipate," "expect," "estimate," "objective," "possible," "potential" and similar expressions. Actual results may vary materially. Factors that could
cause actual results to differ materially include; general economic conditions; business and competitive conditions in the energy industry; changes in federal or state legislation; unusual weather;
actions by state or federal regulatory agencies; and other factors described from time to time in KU's reports to the Securities and Exchange Commission, including Exhibit No. 99.01 to this
report on Form 10-K.

Mergers and Acquisitions

On April 9, 2001, a German power company, E.ON AG, announced a preconditional cash offer of £5.1 billion ($7.3 billion) for Powergen. The offer
is subject to a number of conditions, including the receipt of certain European and United States regulatory approvals. The Kentucky Public Service Commission, the Federal Energy Regulatory
Commission, the Virginia State Corporation Commission, and the Tennessee Regulatory Authority have all approved the acquisition of Powergen and LG&E Energy by E.ON. The parties expect to obtain the
remaining regulatory approvals and to complete the transaction in the first half of 2002. See Powergen's schedule 14D-9, and associated schedules to such filings, filed with the SEC on April 9, 2001.

On
December 11, 2000, LG&E Energy Corp. was acquired by Powergen plc for cash of approximately $3.2 billion or $24.85 per share and the assumption of all of LG&E Energy's debt. As a
result of the acquisition, LG&E Energy became a wholly owned subsidiary of Powergen and, as a

46

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result, KU became an indirect subsidiary of Powergen. KU has continued its separate identity and serves customers in Kentucky and Virginia under its existing name. The preferred stock and debt
securities of KU were not affected by this transaction and KU continued to file SEC reports. Following the acquisition, Powergen became a registered holding company under PUHCA and KU, as a subsidiary
of a registered holding company, became subject to additional regulation under PUHCA. See "Rates and Regulation" under Item 1.

Results of Operations



KU's net income in 2001 was relatively flat as compared to 2000 with an increase of $.9 million. The increase resulted primarily from decreased depreciation,
interest expenses and property and other taxes, partially offset by higher pension related expenses and amortization of regulatory assets.

KU's
net income decreased $11 million for 2000, as compared to 1999, primarily due to retail rate reductions ordered by the Kentucky Commission. The rate reduction resulted in reduced
retail revenues of $28.3 million. Excluding the impact of the rate reduction, net income would have increased approximately $6.0 million. The increase was due to higher retail electric sales and lower
purchased power and operation expenses, offset by lower off-system sales and increased depreciation and amortization.



A comparison of operating revenues for the years 2001 and 2000, excluding the provision for rate refund, $1.0 million in 2001, 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 PeriodCause2001

2000Retail sales:Fuel clause adjustments, etc.

$
10,220

$
6,893KU/LG&E Merger surcredit


(3,856
)

(2,327
)Environmental cost recovery surcharge


1,458


(4,994
)Performance based rate


1,747


3,439Electric rate reduction


(5,395
)

(28,343
)VDT surcredit


(372
)

Variation in sales volumes, etc.


(1,627
)

20,187Total retail sales


2,175


(5,145
)Wholesale sales


5,108


(88,522
)Other


1,202


2,398Total

$
8,485

$
(91,269
)


Electric
revenues increased in 2001 primarily due to an increase in the recovery of fuel costs passed through the FAC and an increase in wholesale activity partially offset by a rate
reduction ordered by Kentucky Commission in 2000 and lower sales volumes.

Electric
revenues decreased in 2000 primarily due to a decrease in brokered activity in the wholesale electric sales market and the electric rate reduction ordered by the Kentucky
Commission. In January
2000, the Kentucky Commission ordered the termination of KU's proposed electric PBR mechanism and an electric rate reduction.

47

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Fuel for electric generation comprises a large component of KU's total operating expenses. KU's Kentucky jurisdictional electric rates were subject to a FAC
whereby increases or decreases would be reflected in the FAC factor, subject to the approval of the Kentucky Commission. Effective July 2, 1999, the FAC was discontinued and replaced with an amended
electric PBR. In January 2000, the Kentucky Commission rescinded KU's PBR rates and ordered the reinstatement of the FAC. See Note 3 of KU's Notes to Financial Statements under Item 8 for a further
discussion of the PBR and the FAC. KU's wholesale and Virginia jurisdictional electric rates contain a fuel adjustment clause whereby increases or decreases in the cost of fuel are reflected in rates,
subject to the approval of the Virginia Commission and the FERC.

Fuel
for electric generation increased $17.1 million (7.8%) in 2001 because of an increase in the cost of coal burned ($21.8 million), partially offset by a decrease in generation ($4.7
million). Fuel for electric generation was approximately the same in 2000 as compared to 1999. An increase in volume burned ($5.1 million) was offset by decreases in the cost of fuel ($5.1 million).
KU's average delivered cost per ton of coal purchased was $27.84 in 2001, $25.63 in 2000, and $26.65 in 1999.

Power
purchased expense decreased $9.8 million (5.9%) in 2001 primarily due to decreased brokered sales activity in the wholesale electric market and a lower unit cost of the purchases
partially offset by an increase in purchases to meet requirements for native load and off-system sales. Power purchased expense decreased $75.4 million in 2000 primarily due to the decrease in
wholesale sales.

Other
operation expenses increased $10.3 million (9.5%) in 2001. The primary cause for the increase was the amortization of a regulatory assets as a result of the workforce reduction
associated with KU's Value Delivery initiative of $5.0 million and an increase in pension expense of $5.5 million. Operation expenses decreased $8.4 million (7.3%) in 2000 primarily because of
decreased administrative and general expenses of $10 million offset by increased transmission expenses ($2.1 million). The administrative and general expenses decrease was primarily due to decreased
medical expense ($3.4 million) and pension expense ($3.9 million).

Maintenance
expenses decreased $4.6 million (7.5%) primarily due to decreases in steam maintenance ($6.5 million). Maintenance expense increased $4.3 million (7.5%) in 2000 due to
increases in
maintenance at the steam generating plants, primarily due to a scheduled turbine outage at Ghent Unit 1.

Depreciation
and amortization decreased $8 million (8.1%) in 2001 primarily due to a reduction in depreciation rates as a result of a settlement order in December 2001 from the Kentucky
Commission. Depreciation expenses decreased by $6.0 million as a result of the settlement order. Depreciation and amortization increased $8.3 million (9.3%) in 2000 because of additional utility plant
in service.

Property
and other taxes decreased $3.1 million (18.2%) in 2001 due to decreases in payroll taxes related to fewer employees as a result of workforce reductions and transfers to LG&E
Energy Services Company. Property and other taxes increased $2.1 million in 2000 over 1999 (13.8%) due to increases in payroll taxes ($1.4 million), property tax ($.4 million) and Kentucky Commission
fees ($.3 million).

Other
income-net increased $2.1 million (30.5%) in 2001 due to an increase in gain on sale of assets. Other income-net decreased $2.6 million (27.5%) in 2000 as a result of a decrease in
interest and dividend income.

Interest
charges decreased $5.4 million (13.7%) in 2001 as compared to the 2000 due to lower interest rates on variable rate 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 an increase in interest associated with KU's accounts receivable securitization program ($1.8 million).

48

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KU's
weighted average cost of long-term debt was 4.91% at December 31, 2001. See Note 9 of KU's Notes to Financial Statements under Item 8.

Variations
in income tax expense are largely attributable to changes in pre-tax income. The increase in KU's 2001 effective income tax rate to 35.9% from the 33.7% rate in 2000 was
largely the result of lost tax benefits attributable to KU's Employee Stock Ownership Plan. These benefits ceased as a result of the December 2000 acquisition of LG&E Energy Corp. by Powergen.

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 rate adjustments. However, relatively low
rates of inflation in the past few years have moderated the impact on current operating results.

CRITICAL ACCOUNTING POLICIES

Preparation of financial statements and related disclosures in compliance with generally accepted accounting principles (GAAP) requires the application of
appropriate technical accounting rules and guidance, as well as the use of estimates. The application of these policies necessarily involves judgments regarding future events, including the likelihood
of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments, in and of themselves, could materially impact the financial statements and
disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment also may have a significant effect, not only on the operation of the
business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies
applied has not changed. The following list represents accounting policies that are most significant to KU's financial condition and results, and that require management judgments. Each of these has a
higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions. See also Note 1 of KU's Notes to Financial Statements under Item 8.

|Accounting Policy                |  | Judgment/Uncertainties                                                                                                                                   |  | See Also
Under Item 8
|-------------------------------- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ---------------------
|Unbilled Revenue                 |  | Projecting customer electric and gas usage
Estimating impact of weather                                                                                  |  | Note 1               
|Benefit Plan Accounting          |  | Future rate of returns on pension plan assets
Interest rates used in valuing benefit obligation
Health care cost trend rates
Other actuarial assumptions |  | Note 6               
|Derivative Financial Instruments |  | Market conditions in energy industry
Price volatility                                                                                                    |  | Note 4               
|Income Tax                       |  | Application of tax statutes and regulations to transactions
Future decisions of tax authorities                                                          |  | Note 7               
|Regulatory Mechanisms            |  | Future regulatory decisions
Impact of deregulation and competition on ratemaking process
External regulator decisions                                    |  | Note 3               

49

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NEW ACCOUNTING PRONOUNCEMENTS

During 2001 and 2000, the following accounting pronouncements were issued that affect KU:

SFAS
No. 133,Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138,Accounting for
Certain Derivative Instruments and Certain Hedging Activities,establishes accounting and reporting standards requiring that every derivative instrument (including certain
derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or a liability measured at its fair value. SFAS No. 133 requires that changes in the
derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset
related results on the hedged item in the income statement, and requires that LG&E must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. SFAS
No. 133 could increase the volatility in earnings and other comprehensive income. SFAS No. 137,Accounting for Derivative Instruments and Hedging
ActivitiesDeferral of the Effective Date of SFAS No. 133, deferred the effective date of SFAS No. 133 until January 1, 2001. KU adopted SFAS No. 133 and SFAS No.
138 on January 1, 2001. The effect of adopting these statements resulted in a $1.6 million increase in other comprehensive income from a cumulative effect of change in accounting principle (net of tax
of $1.1 million).

The
Financial Accounting Standards Board created the Derivatives Implementation Group (DIG) to provide guidance for implementation of SFAS No. 133. DIG Issue C15,
Normal Purchases and Normal Sales Exception for Option Type Contracts and Forward Contracts in Electricity,was adopted in 2001 and had no impact on results of operations and
financial position. DIG Issue C16,Applying the Normal Purchases and Normal Sales Exception to Contracts that Combine a Forward Contract and a Purchased Option
Contract, was cleared in 2001 and stated that option contracts do not meet the normal purchases and normal sales exception and should follow SFAS No. 133. DIG C16 will be
effective in the second quarter of 2002. KU has not determined the impact this issue will have on its results of operations and financial position.

SFAS
No. 140,Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, revises the standards for
accounting for securitizations and other transfers of financial assets and collateral and requires certain disclosures, and provides accounting and reporting standards for transfers and servicing of
financial assets and extinguishments of liabilities. SFAS No. 140 was adopted in the first quarter of 2001, when KU entered into an accounts receivable securitization transaction.

SFAS
No. 141,Business Combinationsand SFAS No. 142,Goodwill and Other Intangible Assetswere issued in 2001. SFAS No. 141 requires all business combinations initiated after June 30, 2001, to be accounted for using the purchase method. SFAS No. 142 requires goodwill to be recorded, but
not amortized. Further, goodwill will now be subject to a periodic assessment for impairment. The provisions of these new pronouncements were effective July 1, 2001, for KU. The adoption of these
standards did not have a material impact on the results of operations or financial position of KU.

SFAS
No. 143,Accounting for Asset Retirement Obligationsand SFAS No. 144,Accounting for the Impairment or
Disposal of Long-Lived Assets, were issued 2001. SFAS No. 143 establishes accounting and reporting standards for obligations associated with the retirement of tangible
long-lived assets and the associated asset retirement costs. SFAS No. 144 supersedes SFAS No. 121,Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Ofand the accounting and reporting provisions of APB Opinion No. 30,Reporting the Results of OperationsReporting
the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions.SFAS No. 144, among other provisions,
eliminates the requirement of SFAS No. 121 to allocate goodwill to long-lived assets to be tested for impairment. The effective implementation date for SFAS No. 143 is 2003 and SFAS
No. 144 is 2002. Based on current regulatory accounting practices, management does not expect SFAS No. 143 or SFAS No. 144 to have a material impact on results of operations or
financial position of KU.

50

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LIQUIDITY AND CAPITAL RESOURCES

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

Operating Activities

Cash provided by operations was $188 million, $176 million and $204 million in 2001, 2000 and 1999, respectively. The 2001 increase resulted from sale of accounts
receivable through a securitization program. See Note 1 of KU's Notes to Financial Statements under Item 8. The 2000 decrease resulted from a decrease in net income caused by the aforementioned
electric rate reduction ordered by the Kentucky Commission. The decrease was further caused by a net increase in net current assets, including increases in accounts receivable and decreases in
accounts payable, and provision for rate refunds, partially offset by decreases in inventory. The 1999 decrease resulted from an increase in net income and a net decrease in net current assets.

Investing Activities

KU's primary use of funds for investing activities continues to be for capital expenditures. Capital expenditures were $142 million, $101 million and $181 million
in 2001, 2000 and 1999, respectively. The higher amount in 1999 capital expenditures was primarily due to the purchase of a 62% interest in two combustion turbines. KU expects its capital expenditures
for 2002 and 2003 will total approximately $459 million which consists primarily of construction costs associated with installation of nitrogen oxide control equipment as described in the section
titled "Environmental Matters," purchase of two jointly owned CTs with LG&E and on going construction for the distribution system.

Net
cash used for investment activities increased by $39 million in 2001 compared to 2000, and decreased by $81 million in 2000 compared to 1999, primarily due to the level of
construction expenditures.

Financing Activities

Net cash outflows from financing activities were $46 million, $82 million and $75 million in 2001, 2000 and 1999, respectively. In 2000, KU retired a $61.5
million first mortgage bond and refinanced $12.9 million of its pollution control bonds. The long-term debt balance as of December 31, 2001, was $434.5 million. Short-term debt declined $13.4 million
in 2001. KU received $15 million in contributed capital from its parent company in December 2000.

KU
participates in an intercompany money pool agreement wherein LG&E Energy can make funds available to KU at market based rates up to $200 million. At December 31, 2001, the balance of
the money pool loan from LG&E Energy was $47.8 million at an average rate of 2.37% and the remaining money pool availability was $152.2 million. In addition, KU maintains an uncommitted borrowing
facility totaling $60 million that was undrawn at December 31, 2001. LG&E Energy maintains a facility of $200 million with an affiliate to ensure funding availability for the money pool. There was no
outstanding balance under this facility as of December 31, 2001, and availability of $170 million remains after considering the $30 million of commercial paper outstanding at LG&E.

At
December 31, 2000, KU had $61.2 million outstanding under the money pool at an average rate of 6.84%.

Under
the provisions for KU's variable-rate pollution control bonds Series PCS 10, the bonds are subject to tender for purchase at the option of the holder and to mandatory tender for
purchase upon the occurrence of certain events, causing the bonds to be classified as current portion of long-term debt.

51

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Future Capital Requirements

Future capital requirements may be affected in varying degrees by factors such as load growth, changes in construction expenditure levels, rate actions by
regulatory agencies, new legislation, market entry of competing electric power generators, changes in environmental regulations and other regulatory requirements. KU anticipates funding future capital
requirements through operating cash flow, debt, and/or infusion of capital from parent.

KU's
debt ratings as of January 31, 2002, were:

Moody's

S&P

FitchFirst mortgage bonds

A1

A-

A+Preferred stock

a2

BBB-

A-Commercial paper

P-1

A-2

F-1


The
S&P ratings are on Credit Watch with positive implications. The Fitch ratings are on Credit WatchEvolving status. These ratings reflect the views of Moody's, S&P and
Fitch. A security rating is not a recommendation to buy, sell or hold securities and is subject to revision or withdrawal at any time by the rating agency.

Contractual Obligations

The following is provided to summarize KU's contractual cash obligations for periods after December 31, 2001 (in thousands of $):

|                                       |  | Payments Due by Period
|-------------------------------------- |  | ----------------------
|
|Long-term debt (a)                     |  | $                     
|Unconditional purchase obligations (b) |  |                       
|Other long-term obligations (c)        |  |                       
|                                       |  |                       
|Total contractual cash obligations     |  | $                     
|                                       |  |                       

---

Market Risks

KU is exposed to market risks from changes in interest rates and commodity prices. To mitigate changes in cash flows attributable to these exposures, KU uses
various financial instruments including derivatives. Derivative positions are monitored using techniques that include market value and sensitivity analysis. See Notes 1 and 4 of KU's Notes to
Financial Statements under Item 8.

Interest Rate Sensitivity

KU has short-term and long-term variable rate debt obligations outstanding. At December 31, 2001, the potential change in interest expense associated with a 1%
change in base interest rates of KU's variable rate debt is estimated at $2.2 million.

52

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Interest
rate swaps are used to hedge KU's underlying debt obligations. These swaps hedge specific debt issuances and, consistent with management's designation, are accorded hedge
accounting treatment.

As
of December 31, 2001, KU has swaps with a notional value of $153 million. The swaps exchange fixed-rate interest payments for floating interest payments on KU's Series P, R, and PCS-9
Bonds. The potential loss in fair value from these positions resulting from a hypothetical 1% adverse movement in base interest rates is estimated at $8.2 million as of December 31, 2001. This
estimate is derived from third party valuations. Changes in the market value of these swaps if held to maturity, as KU intends to do, will have no effect on KU's net income or cash flow. See Note 4 of
KU's Notes to Financial Statements under Item 8.

Energy Trading & Risk Management Activities

KU conducts energy trading and risk management activities to maximize the value of power sales from physical assets it owns, in addition to the wholesale sale of
excess asset capacity. Certain energy trading activities are accounted for on a mark-to-market basis in accordance withEITF 98-10 Accounting for Contracts Involved in Energy
Trading and Risk Management Activities, SFAS No. 133 Accounting for Derivative Instruments and Hedging Activities,andSFAS No. 138 Accounting for
Certain Derivative Instruments and Certain Hedging Activities. Wholesale sales of excess asset capacity and wholesale purchases are treated as normal sales and purchases under SFAS No.
133andSFAS No. 138and are not marked to market.

The
table below summarizes KU's energy trading and risk management activities in 2001 (in thousands of $).

Fair value of contracts at 12/31/00, net liability

$
(17
)Fair value of contracts when entered into during 2001


3,441Contracts realized or otherwise settled during 2001


(2,894
)Changes in fair values due to changes in assumptions


(716
)Fair value of contracts at 12/31/01, net liability

$
(186
)


No
changes to valuation techniques for energy trading and risk management activities occurred during 2001. All contracts outstanding at December 31, 2001 have a maturity of less than one
year and are valued using prices actively quoted for proposed or executed transactions or quoted by brokers.

KU
maintains policies intended to minimize credit risk and revalues credit exposures daily to monitor compliance with those policies. As December 31, 2001, 100% of the trading and risk
management commitments were with counterparties rated BBB equivalent or better.

Commodity Price Sensitivity

KU has limited exposure to market price volatility in prices of fuel and electricity, since its retail tariffs include the FAC and GSC commodity price
pass-through mechanisms. KU is exposed to market price volatility of fuel and electricity in its wholesale activities.

Accounts Receivable Securitization

On February 6, 2001, KU implemented an accounts receivable securitization program. The purpose of this program is to enable KU to accelerate the receipt of cash
from the collection of retail accounts receivable, thereby reducing dependence upon more costly sources of working capital. The securitization program allows for a percentage of eligible receivables
to be sold. Eligible receivables are generally all receivables associated with retail sales that have standard terms and are not past due. KU is able to terminate this program at any time without
penalty. If there is a significant deterioration in

53

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the payment record of the receivables by the retail customers or if KU fails to meet certain covenants regarding the program, the program may terminate at the election of the financial institutions.
In this case, payments from retail customers would first be used to repay the financial institutions participating in the program, and would then be available for use by KU.

As
part of the program, KU sold retail accounts receivables to a wholly owned subsidiary KU R. Simultaneously, KU R entered into two separate three-year accounts receivable
securitization facilities with two financial institutions and their affiliates whereby KU R can sell, on a revolving basis, an undivided interest in certain of their receivables and receive up to $50
million from an unrelated third party purchaser. The effective cost of the receivables programs is comparable to KU's lowest cost source of capital, and is based on prime rated commercial paper. KU
retains servicing rights of the sold receivables through two separate servicing agreements with the third party purchaser. KU has obtained an opinion from independent legal counsel indicating these
transactions qualify as a true sale of receivables. As of December 31, 2001, the outstanding program balance was $45.1 million.

Management
expects to renew these facilities when they expire.

The
allowance for doubtful accounts associated with the eligible securitized receivables was $520,000 at December 31, 2001. This allowance is based on historical experience of KU. Each
securitization facility contains a fully funded reserve for uncollectible receivables.

RATES AND REGULATION

Following the purchase of LG&E Energy by Powergen, Powergen became a registered holding company under PUHCA. As a result, Powergen, its utility subsidiaries,
including KU, and certain of its non-utility subsidiaries are subject to extensive regulation by the SEC under PUHCA with respect to issuances and sales of securities, acquisitions and sales of
certain utility properties, and intra-system sales of certain goods and services. In addition, PUHCA generally limits the ability of registered holding companies to acquire additional public utility
systems and to acquire and retain businesses unrelated to the utility operations of the holding company. Powergen believes that it has adequate authority (including financing authority) under existing
SEC orders and regulations for it and its subsidiaries to conduct their businesses and will seek additional authorization when necessary.

KU
is subject to the jurisdiction of the Kentucky Commission, the Virginia Commission and FERC in virtually all matters related to electric utility regulation, and as such, its
accounting is subject to SFAS No. 71,Accounting for the Effects of Certain Types of Regulation. Given KU's competitive position in the market and the
status of regulation in the states of Kentucky and Virginia, KU has no plans or intentions to discontinue its application of SFAS No. 71. See Note 3 of KU's Notes to Financial Statements under Item 8.

Kentucky Commission Settlement OrderValue Delivery Costs, ESM and Depreciation

During the first quarter 2001, KU recorded a $64 million charge for a workforce reduction program. Primary components of the charge were separation benefits,
enhanced early retirement benefits, and health care benefits. The result of this workforce reduction was the elimination of over 300 positions, accomplished primarily through a voluntary enhanced
severance program.

On
June 1, 2001, KU filed an application (VDT case) with the Kentucky Commission to create a regulatory asset relating to these first quarter 2001 charges. The application requested
permission to amortize these costs over a four-year period. The Kentucky Commission also opened a case to review the new depreciation study and resulting depreciation rates implemented in 2001.

KU
reached a settlement in the VDT case as well as the other cases involving depreciation rates and ESM with all intervening parties. The settlement agreement was approved by the
Kentucky Commission on December 3, 2001.

54

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The
Kentucky Commission December 3, 2001, order allowed KU to set up a regulatory asset of $54 million for the workforce reduction costs and begin amortizing these costs over a five year
period starting in April 2001. The first quarter charge of $64 million represented all employees who had accepted a voluntary enhanced severance program. Some employees rescinded their participation
in the voluntary enhanced severance program and, along with the non-recurring charge of $6.9 million for FERC and Virginia jurisdictions, thereby decreasing the original charge from $64 million to $54
million. The settlement will also reduce revenues approximately $11 million through a surcredit on future bills to customers over the same five year period. The surcredit represents stipulated net
savings KU is expected to realize from implementation of best practices through the value delivery process. The agreement also established KU's new depreciation rates in effect December 2001,
retroactive to January 1, 2001. The new depreciation rates decreased depreciation expense by $6.0 million in 2001.

Environmental Cost Recovery

In August 1999, a final order of the Kentucky Commission approved KU's settlement agreement concerning the refund of the recovery of costs associated with
pre-1993 environmental projects. KU began applying the refund to customers' bills in October 1999, and completed the refund process in November 2000. All aspects of the original litigation of this
issue have now been resolved.

In
June 2000, the Kentucky Commission approved KU's application for a CCN to construct up to four SCR NOx reduction facilities. The construction and subsequent operation of the SCRs is
intended to reduce NOx emission levels to meet the EPA's mandated NOx emission level of 0.15 lbs./ Mmbtu by May 2004. In its order, the Kentucky Commission 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 application with the Kentucky Commission to amend its
Environmental Compliance Plan to reflect the addition of the proposed NOx reduction technology projects and to amend its Environmental Cost Recovery Tariff to include an overall rate of return on
capital investments. Following the completion of hearings in March 2001, a ruling was issued in April 2001, approving KU's application. Such approval has allowed KU to begin to recover the costs
associated with these new projects, subject to Kentucky Commission oversight during normal six-month and two-year reviews.

ESM

KU's electric rates are subject to an Earnings Sharing Mechanism. The ESM, in place for three years beginning 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 of 10.5% to 12.5%, no action is necessary. If earnings are above the upper limit, then excess earnings are
shared 40% with ratepayers and 60% with shareholders; if earnings are below the lower limit, then earnings deficiency is recovered 40% from ratepayers and 60% from shareholders. The first ESM filing
was made on March 1, 2001, for year ended December 31, 2000. By order of the Kentucky Commission, rate changes prompted by the ESM filing go into effect in April of each year. KU estimated that the
rate of return will fall within the deadband range, subject to Kentucky Commission approval, for the year ended December 31, 2001; therefore, no adjustment to the financial statements was made.

DSM

In May 2001, the Kentucky Commission approved a plan that would expand LG&E's current DSM programs into the service territory served by KU. The filing includes a
rate mechanism that provides for concurrent recovery of DSM costs, provides an incentive for implementing DSM programs, and recovers revenues from lost sales associated with the DSM program.

55

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FAC

Prior to implementation of the PBR in July 1999, and following its termination in March 2000, KU employed an FAC mechanism, which under Kentucky law allowed the
utilities to recover from customers the actual fuel costs associated with retail electric sales.

In
July 1999, the Kentucky Commission issued a series of orders requiring KU to refund approximately $10.1 million resulting from reviews of the FAC from November 1994 to October 1998.
The orders changed KU's method of computing fuel costs associated with electric line losses on off-system sales appropriate for recovery through the FAC, and KU's method for computing system line
losses for the purpose of calculating the system sales component of the FAC charge. At KU's request, in July 1999, the Kentucky Commission stayed the refund requirement pending the Kentucky
Commission's final determination of any rehearing request that KU may file. In August 1999, KU filed its request for rehearing of the July orders.

In
August 1999, the Kentucky Commission issued a final order in the KU proceedings, agreeing, in part, with KU's arguments outlined in its petition for rehearing. While the Kentucky
Commission confirmed that KU should change its method of computing the fuel costs associated with electric line losses, it agreed with KU that the line loss percentage should be based on KU's actual
line losses incurred in making wholesale sales rather than the percentage used in its Open Access Transmission Tariff. The Kentucky Commission also upheld its previous ruling concerning the
computation of system line losses in the calculation of the FAC. The net effect of the Kentucky Commission's final order was to reduce the refund obligation to $6.7 million ($5.8 million on Kentucky
jurisdictional basis) from the original order amount of $10.1 million. In August 1999, KU recorded its estimated share of anticipated FAC refunds. KU began implementing the refund in October and
completed the refund in September 2000. Both KU and the KIUC appealed the order to the Franklin Circuit Court. In October 2000, the Court affirmed the Kentucky Commission's orders concerning all
issues except interest, with respect to which it held that KU will be required to pay interest on the amount disallowed "if the Commission within its discretion so determines", and ordered the case be
remanded to the Kentucky Commission on that issue. In November 2000, KU appealed the Circuit Court's decision to the Kentucky Court of Appeals. Pending a decision on this appeal, a comprehensive
settlement was reached by all parties,
which settlement was filed with the Kentucky Commission on December 21, 2001. Thereunder, KU agreed to credit its fuel clause in the amount of $954,000 (such credit provided over the course of two
monthly billing periods), and the parties agreed on a prospective interpretation of the state's fuel adjustment clause regulation to ensure consistent and mutually acceptable application on a going-
forward basis. All pending FAC proceedings before the court were resolved by the parties to the agreement and all parties requested the Court of Appeals remand the case to the Kentucky Commission. The
Kentucky Commission is expected to approve the settlement in 2002.

Kentucky Commission Administrative Case for Affiliate Transactions

In December 1997, the Kentucky Commission opened Administrative Case No. 369 to consider Kentucky Commission policy regarding cost allocations, affiliate
transactions and codes of conduct governing the relationship between utilities and their non-utility operations and affiliates. The Kentucky Commission intended to address two major areas in the
proceedings: the tools and conditions needed to prevent cost shifting and cross-subsidization between regulated and non-utility operations; and whether a code of conduct should be established to
assure that non-utility segments of the holding company are not engaged in practices that could result in unfair competition caused by cost shifting from the non-utility affiliate to the utility.
During the period September 1998 to February 2000, the Kentucky Commission issued draft codes 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 utilities that provide nonregulated activities to keep separate accounts and allocate costs in accordance with
procedures established by the Kentucky Commission. In the same Bill,

56

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the General Assembly set forth provisions to govern a utilities activities related to the sharing of information, databases, and resources between its employees or an affiliate involved in the
marketing or the provision of nonregulated activities and its employees or an affiliate involved in the provision of regulated services. The legislation became law in July 2000 and KU has been
operating pursuant thereto since that time. On February 14, 2001, the Kentucky Commission published notice of their intent to promulgate new administrative regulation under the auspices of the new
law. This effort is still on going.

Kentucky Commission Administrative Case for System Adequacy

On June 19, 2001, Kentucky Governor Paul E. Patton issued Executive Order 2001-771, which directed the Kentucky Commission to review and study issues relating to
the need for and development of new electric generating capacity in Kentucky. The issues to be considered included the impact of new power plants on the electric supply grid, facility siting issues,
and economic development matters, with the goal of ensuring a continued, reliable source of supply of electricity for the citizens of Kentucky and the continued environmental and economic vitality of
the Commonwealth and its communities. In response to that Executive Order, in July 2001 the Kentucky Commission opened Administrative Case No. 387 to review the adequacy of Kentucky's generation
capacity and transmission system. Specifically, the items reviewed were the appropriate level of reliance on purchased power, the appropriate reserve margins to meet existing and future electric
demand, the impact of spikes in natural gas prices on electric utility planning strategies, and the adequacy of Kentucky's electric transmission facilities. KU,
as a party to this proceeding, filed written testimony and responded to two requests for information. Public hearings were held in August, September, and October 2001. In October 2001, KU filed a
final brief in the case. In December 2001 the Kentucky Commission issued an order in which they noted that KU is responsibly addressing the long-term supply needs of native load customers and that
current reserve margins are appropriate. However, due to the rapid pace of change in the industry, the order also requires KU to provide an annual assessment of supply resources, future demand,
reserve margin, and the need for new resources.

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

The
Kentucky Commission pledged to continue to monitor all relevant issues and advocate Kentucky's interests at all opportunities.

Environmental Matters

The Clean Air Act imposed stringent new SO2 and NOx emission limits on electric generating units. KU met its Phase I SO2 requirements
primarily 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 to
delay additional capital expenditures and may also include fuel switching or the installation of additional scrubbers. KU met the NOx emission requirements of the Act through installation of low-NOx
burner systems. KU's compliance plans are subject to many factors including developments in the emission allowance and fuel markets, future regulatory and legislative initiatives, and advances in
clean air control technology. KU will continue to monitor these developments to ensure that its environmental obligations are met in the most efficient and cost-effective manner.

In
September 1998, the EPA announced its final "NOx SIP Call" rule requiring states to impose significant additional reductions in NOx emissions by May 2003, in order to mitigate alleged
ozone transport impacts on the Northeast region. The Commonwealth of Kentucky is currently in the process

57

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of revising its State Implementation Plan or "SIP" to require reductions in NOx emissions from coal-fired generating units to the 0.15 lb./Mmbtu level on a system-wide basis. In related proceedings
in 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 directing similar NOx reductions from a number of
specifically targeted generating units including all KU units in the eastern half of Kentucky. Additional petitions currently pending before EPA may potentially result in rules encompassing KU's
remaining generating units. As a result of appeals to both rules, the compliance date was extended to May 2004. All KU generating units are subject to the May 2004 compliance date under these NOx
emissions reduction rules.

KU
is currently implementing a plan for adding significant additional NOx 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 through the final compliance date. KU estimates that it will incur total capital costs of approximately $196 million to reduce its NOx
emissions to the 0.15 lb./Mmbtu level on a company-wide basis. In addition, KU will incur additional operating and maintenance costs in operating new NOx controls. KU believes its costs in this regard
to be comparable to those of similarly situated utilities with like generation assets. KU had anticipated that such capital and operating costs are the type of costs that are eligible for recovery
from customers under its environmental surcharge mechanism and believed that a significant portion of such costs could be recovered. In April 2001, the Kentucky Commission granted recovery of these
costs for KU.

KU
is also monitoring several other air quality issues which may potentially 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 and particulate matter, measures to implement EPA's regional haze rule, and EPA's December 2000 determination to regulate mercury emissions from power plants.

KU
owns or formerly owned several properties that contained past MGP operations. Various contaminants are typically found at such former MGP sites and environmental remediation measures
are frequently required. KU has completed the cleanup of a site owned by KU. With respect to other former MGP sites no longer owned by KU, KU is unaware of what, if any, additional exposure or
liability it may have.

In
October 1999, approximately 38,000 gallons of diesel fuel leaked from a cracked valve in an underground pipeline at KU's E.W. Brown Station. Under the oversight of EPA and state
officials, KU commenced immediate spill containment and recovery measures which prevented the spill from reaching the Kentucky River. KU ultimately recovered approximately 34,000 gallons of diesel
fuel. In November 1999, the Kentucky Division of Water issued a notice of violation for the incident. KU is currently negotiating with the state in an effort to reach a complete resolution of this
matter. KU incurred costs of approximately $1.8 million and received insurance reimbursement of $1.2 million.

See
Note 11 of KU's Notes to Financial Statements under Item 8 for an additional discussion of environmental issues.

Deferred Income Taxes

KU expects to have adequate levels of taxable income to realize its recorded deferred tax assets. At December 31, 2001, deferred tax assets totaled $63.9 million
and were principally related to expenses attributable to KU's pension plans and post retirement benefit obligations.

FUTURE OUTLOOK

Competition and Customer Choice

KU has moved aggressively over the past decade to be positioned for, and to help promote the energy industry's shift to customer choice and a competitive market
for energy services. Specifically,

58

---

KU has taken many 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 of previously deferred expenses; an increase in focus on commercial and industrial customers; an increase in employee training; and necessary corporate
and business unit realignments. KU continues to be active in the national debate surrounding the restructuring of the energy industry and the move toward a competitive, market-based environment.

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

In
November 1999, the task force issued a report to the Governor of Kentucky and a legislative agency recommending no general electric industry restructuring actions during the 2000
legislative session. No general industry restructuring actions were taken during the 2001 legislative session.

Thus,
at the time of this report, neither the Kentucky General Assembly nor the Kentucky Commission has adopted or approved a plan or timetable for retail electric industry competition
in Kentucky. The nature or timing of the ultimate legislative or regulatory actions regarding industry restructuring and their impact on KU, which may be significant, cannot currently be predicted.

While
many states have moved forward in providing retail choice, many others have not. Some are reconsidering their initiatives and have even delayed implementation. Recent activities in
California that have resulted in extremely high wholesale (and in some cases, consumer) electric prices are becoming significant factors in the deliberations by other states.

KU's
customers in Virginia will have retail choice beginning January 2002, pursuant to the Virginia Electric Restructuring Act. The Virginia Commission is promulgating regulations to
govern the various activities required by the Act. KU filed unbundled rates that became effective January 1, 2002. KU anticipates seeking an exemption from the Virginia Electric Restructuring Act.

ITEM 7A. Quantitative and Qualitative Disclosure About Market Risk.

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

59

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ITEM 8. Financial Statements and Supplementary Data.

|                    |  | 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               
|EPA                 |  | U.S. Environmental Protection Agency           
|ESM                 |  | Earnings Sharing Mechanism                     
|FAC                 |  | Fuel Adjustment Clause                         
|FERC                |  | Federal Energy Regulatory Commission           
|FPA                 |  | Federal Power Act                              
|FT and FT-A         |  | Firm Transportation                            
|GSC                 |  | Gas Supply Clause                              
|Holding Company Act |  | Public Utility Holding Company Act of 1935     
|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                             
|Kva                 |  | Kilovolt-ampere                                
|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                            
|Merger Agreement    |  | Agreement and Plan of Merger dated May 20, 1997
|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                              
|NOx                 |  | Nitrogen Oxide                                 
|OMU                 |  | Owensboro Municipal Utilities                  
|OVEC                |  | Ohio Valley Electric Corporation               
|PBR                 |  | Performance-Based Ratemaking                   
|Powergen            |  | Powergen plc                                   
|PUHCA               |  | Public Utility Holding Company Act of 1935     
|S&P                 |  | Standard & Poor's Rating Services              
|SCR                 |  | Selective Catalytic Reduction                  
|SEC                 |  | Securities And Exchange Commission             
|SERP                |  | Supplemental Employee Retirement Plan          
|SFAS                |  | Statement of Financial Accounting Standards    
|SIP                 |  | State Implementation Plan                      
|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 Commission Staff                      

60

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Louisville Gas and Electric Company and Subsidiary
Consolidated Statements of Income
(Thousands of $)

|                                      |                                         | Years Ended December 31           |        
|------------------------------------- | --------------------------------------- | --------------------------------- | -------
|
|OPERATING REVENUES:                   |                                         |                                   |        
|                                      | Electric                                |                                   | $      
|                                      | Gas                                     |                                   |        
|                                      | Provision for rate refunds (Note 3)     |                                   |        
|                                      |                                         |                                   |        
|                                      |                                         | Total operating revenues (Note 1) |        
|                                      |                                         |                                   |        
|OPERATING EXPENSES:                   |                                         |                                   |        
|                                      | Fuel for electric generation            |                                   |        
|                                      | Power purchased                         |                                   |        
|                                      | Gas supply expenses                     |                                   |        
|                                      | Other operation expenses                |                                   |        
|                                      | Maintenance                             |                                   |        
|                                      | Depreciation and amortization (Note 1)  |                                   |        
|                                      | Federal and state income taxes (Note 8) |                                   |        
|                                      | Property and other taxes                |                                   |        
|                                      |                                         |                                   |        
|                                      |                                         | Total operating expenses          |        
|                                      |                                         |                                   |        
|Net operating income                  |                                         |                                   | 141,773
|Other incomenet (Note 9)             |                                         |                                   | 2,930  
|Interest charges                      |                                         |                                   | 37,922 
|                                      |                                         |                                   |        
|Net income                            |                                         |                                   | 106,781
|Preferred stock dividends             |                                         |                                   | 4,739  
|                                      |                                         |                                   |        
|Net income available for common stock |                                         | $                                 | 102,042
|                                      |                                         |                                   |        

Consolidated Statements of Retained Earnings
(Thousands of $)

|                    |  |                                   |         | Years Ended December 31
|------------------- |  | --------------------------------- | ------- | -----------------------
|
|Balance January 1   |  | $                                 | 314,594 |                        
|Add net income      |  |                                   | 106,781 |                        
|                    |  |                                   |         |                        
|                    |  |                                   |         |                        
|                    |  |                                   |         |                        
|Deduct:             |  | Cash dividends declared on stock: |         |                        
|                    |  | 5% cumulative preferred           |         |                        
|                    |  | Auction rate cumulative preferred |         |                        
|                    |  | $5.875 cumulative preferred       |         |                        
|                    |  | Common                            |         |                        
|                    |  |                                   |         |                        
|                    |  |                                   |         |                        
|                    |  |                                   |         |                        
|Balance December 31 |  | $                                 | 393,636 |                        
|                    |  |                                   |         |                        

The
accompanying notes are an integral part of these consolidated financial statements.

61

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Louisville Gas and Electric Company and Subsidiary  Consolidated Statements of Comprehensive Income  (Thousands of $)

|                                                                                                                          |  | Years Ended December 31 |        
|------------------------------------------------------------------------------------------------------------------------- |  | ----------------------- | -------
|
|Net income                                                                                                                |  | $                       | 106,781
|Cumulative effect of change in accounting principleAccounting for derivative instruments and hedging activities (Note 1) |  |                         | (5,998 
|Losses on derivative instruments and hedging activities (Note 1)                                                          |  |                         | (2,606 
|Additional minimum pension liability adjustment (Note 7)                                                                  |  |                         | (24,712
|Unrealized holding losses on available-for-sale securities arising during the period                                      |  |                         |       
|Income tax benefit related to items of other comprehensive income                                                         |  |                         | 13,416 
|                                                                                                                          |  |                         |        
|Comprehensive income                                                                                                      |  | $                       | 86,881 
|                                                                                                                          |  |                         |        

The
accompanying notes are an integral part of these consolidated financial statements.

62

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Louisville Gas and Electric Company and Subsidiary
Consolidated Balance Sheets
(Thousands of $)

|                                                   |                                                                       | December 31                    
|-------------------------------------------------- | --------------------------------------------------------------------- | -------------------------------
|
|ASSETS:                                            |                                                                       |                                
|Utility plant, at original cost (Note 1):          |                                                                       |                                
|                                                   | Electric                                                              |                                
|                                                   | Gas                                                                   |                                
|                                                   | Common                                                                |                                
|                                                   |                                                                       |                                
|                                                   |                                                                       |                                
|                                                   | Less: reserve for depreciation                                        |                                
|                                                   |                                                                       |                                
|                                                   |                                                                       |                                
|                                                   | Construction work in progress                                         |                                
|                                                   |                                                                       |                                
|                                                   |                                                                       |                                
|                                                   |                                                                       |                                
|Other property and investmentsless reserve        |                                                                       |                                
|                                                   |                                                                       |                                
|Current assets:                                    |                                                                       |                                
|                                                   | Cash and temporary cash investments                                   |                                
|                                                   | Marketable securities (Note 6)                                        |                                
|                                                   | Accounts receivableless reserve of $1,575 in 2001 and $1,286 in 2000 |                                
|                                                   | Materials and suppliesat average cost:                               |                                
|                                                   |                                                                       | Fuel (predominantly coal)      
|                                                   |                                                                       | Gas stored underground (Note 1)
|                                                   |                                                                       | Other                          
|                                                   | Prepayments and other                                                 |                                
|                                                   |                                                                       |                                
|                                                   |                                                                       |                                
|                                                   |                                                                       |                                
|Deferred debits and other assets:                  |                                                                       |                                
|                                                   | Unamortized debt expense (Note 1)                                     |                                
|                                                   | Regulatory assets (Note 3)                                            |                                
|                                                   | Other                                                                 |                                
|                                                   |                                                                       |                                
|                                                   |                                                                       |                                
|                                                   |                                                                       |                                
|                                                   |                                                                       | $                              
|                                                   |                                                                       |                                
|CAPITAL AND LIABILITIES:                           |                                                                       |                                
|Capitalization (see statements of capitalization): |                                                                       |                                
|                                                   | Common equity                                                         |                                
|                                                   | Cumulative preferred stock                                            |                                
|                                                   | Long-term debt (Note 10)                                              |                                
|                                                   |                                                                       |                                
|                                                   |                                                                       |                                
|                                                   |                                                                       |                                
|Current liabilities:                               |                                                                       |                                
|                                                   | Current portion of long-term debt (Note 10)                           |                                
|                                                   | Notes payable (Note 11)                                               |                                
|                                                   | Accounts payable                                                      |                                
|                                                   | Accrued taxes                                                         |                                
|                                                   | Accrued interest                                                      |                                
|                                                   | Other                                                                 |                                
|                                                   |                                                                       |                                

63

---

|                                        |                                                                  |   | 528,382   |         |   | 529,297  
|--------------------------------------- | ---------------------------------------------------------------- | - | --------- | ------- | - | ---------
|                                        |                                                                  |   |           |        
|Deferred credits and other liabilities: |                                                                  |   |           |         |   |          
|                                        | Accumulated deferred income taxes (Notes 1 and 8)                |   |           | 298,143 |   |          
|                                        | Investment tax credit, in process of amortization                |   |           | 58,689  |   |          
|                                        | Accumulated provision for pensions and related benefits (Note 7) |   |           | 167,526 |   |          
|                                        | Customers' advances for construction                             |   |           | 9,745   |   |          
|                                        | Regulatory liabilities (Note 3)                                  |   |           | 65,349  |   |          
|                                        | Other                                                            |   |           | 16,606  |   |          
|                                        |                                                                  |   |           |        
|                                        |                                                                  |   | 616,058   |         |   | 462,119  
|                                        |                                                                  |   |           |        
|Commitments and contingencies (Note 12) |                                                                  | $ | 2,448,354 |         | $ | 2,226,084
|                                        |                                                                  |   |           |        

The
accompanying notes are an integral part of these consolidated financial statements.

64

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Louisville Gas and Electric Company and Subsidiary
Consolidated Statements of Cash Flows
(Thousands of $)

|                                                         |                                                                | Years Ended December 31                      |      
|-------------------------------------------------------- | -------------------------------------------------------------- | -------------------------------------------- | -----
|
|CASH FLOWS FROM OPERATING ACTIVITIES:                    |                                                                |                                              |      
|                                                         | Net income                                                     |                                              | $    
|                                                         | Items not requiring cash currently:                            |                                              |      
|                                                         |                                                                | Depreciation and amortization                |      
|                                                         |                                                                | Deferred income taxesnet                    |      
|                                                         |                                                                | Investment tax creditnet                    |      
|                                                         |                                                                | Other                                        |      
|                                                         | Change in certain net current assets:                          |                                              |      
|                                                         |                                                                | Accounts receivable                          |      
|                                                         |                                                                | Materials and supplies                       |      
|                                                         |                                                                | Accounts payable                             |      
|                                                         |                                                                | Accrued taxes                                |      
|                                                         |                                                                | Accrued interest                             |      
|                                                         |                                                                | Prepayments and other                        |      
|                                                         | Sale of accounts receivable (Note 1)                           |                                              |      
|                                                         | Other                                                          |                                              |      
|                                                         |                                                                |                                              |      
|                                                         |                                                                | Net cash flows from operating activities     |      
|                                                         |                                                                |                                              |      
|CASH FLOWS FROM INVESTING ACTIVITIES:                    |                                                                |                                              |      
|                                                         | Purchases of securities                                        |                                              |      
|                                                         | Proceeds from sales of securities                              |                                              |      
|                                                         | Construction expenditures                                      |                                              |      
|                                                         |                                                                |                                              |      
|                                                         |                                                                | Net cash flows used for investing activities |      
|                                                         |                                                                |                                              |      
|CASH FLOWS FROM FINANCING ACTIVITIES:                    |                                                                |                                              |      
|                                                         | Short-term borrowings and repayments                           |                                              |      
|                                                         | Issuance of pollution control bonds                            |                                              |      
|                                                         | Retirement of first mortgage bonds and pollution control bonds |                                              |      
|                                                         | Additional paid-in capital                                     |                                              |      
|                                                         | Payment of dividends                                           |                                              |      
|                                                         |                                                                |                                              |      
|                                                         |                                                                | Net cash flows from financing activities     |      
|                                                         |                                                                |                                              |      
|Change in cash and temporary cash investments            |                                                                |                                              | (383 
|Cash and temporary cash investments at beginning of year |                                                                |                                              | 2,495
|                                                         |                                                                |                                              |      
|Cash and temporary cash investments at end of year       |                                                                | $                                            | 2,112
|                                                         |                                                                |                                              |      
|Supplemental disclosures of cash flow information:       |                                                                |                                              |      
|                                                         | Cash paid during the year for:                                 |                                              |      
|                                                         |                                                                | Income taxes                                 |      
|                                                         |                                                                | Interest on borrowed money                   |      

The
accompanying notes are an integral part of these consolidated financial statements.

65

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Louisville Gas and Electric Company and Subsidiary  Consolidated Statements of Capitalization  (Thousands of $)

|               |                                                                                                  | December 31 |        
|-------------- | ------------------------------------------------------------------------------------------------ | ----------- | -------
|
|COMMON EQUITY: |                                                                                                  |             |        
|               | Common stock, without par value
    Authorized 75,000,000 shares, outstanding 21,294,223 shares |             | $      
|               | Common stock expense                                                                             |             |        
|               | Additional paid-in capital                                                                       |             |        
|               | Accumulated other comprehensive income                                                           |             |        
|               | Retained earnings                                                                                |             |        
|               |                                                                                                  |             |        
|               |                                                                                                  |             | 838,070
|               |                                                                                                  |             |        

CUMULATIVE PREFERRED STOCK:
    Redeemable on 30 days notice by LG&E

|                          |                                                                 | Shares
Outstanding                     |                                         | Current
Redemption Price   |   |        |  |        |       
|------------------------- | --------------------------------------------------------------- | -------------------------------------- | --------------------------------------- | -------------------------- | - | ------ |  | ------ | ------
|                          | $25 par value, 1,720,000 shares authorized
    5% series       |                                        | 860,287                                 |                            | $ | 28.00  |  |        | 21,507
|                          | Without par value, 6,750,000 shares
    authorizedAuction rate |                                        | 500,000                                 |                            |   | 100.00 |  |        | 50,000
|                          | $5.875 series                                                   |                                        | 250,000                                 |                            |   | 102.35 |  |        | 25,000
|                          | Preferred stock expense                                         |                                        |                                         |                            |   |        |  |        | (1,367
|                          |                                                                 |                                        |                                         |                            |   |        |  |        |       
|                          |                                                                 |                                        |                                         |                            |   |        |  | 95,140 |       
|                          |                                                                 |                                        |                                         |                            |   |        |  |        |       
|LONG-TERM DEBT (Note 10): |                                                                 |                                        |                                         |                            |   |        |  |        |       
|                          | First mortgage bonds
    Series due August 15, 2003, 6%        |                                        |                                         |                            |   |        |  |        | 42,600
|                          |                                                                 | Pollution control series:              |                                         |                            |   |        |  |        |       
|                          |                                                                 |                                        | R due November 1, 2020, 6.55%           |                            |   |        |  |        |       
|                          |                                                                 |                                        | S due September 1, 2017, variable       |                            |   |        |  |        |       
|                          |                                                                 |                                        | T due September 1, 2017, variable       |                            |   |        |  |        |       
|                          |                                                                 |                                        | U due August 15, 2013, variable         |                            |   |        |  |        |       
|                          |                                                                 |                                        | V due August 15, 2019, 5 5/8%           |                            |   |        |  |        |       
|                          |                                                                 |                                        | W due October 15, 2020, 5.45%           |                            |   |        |  |        |       
|                          |                                                                 |                                        | X due April 15, 2023, 5.90%             |                            |   |        |  |        |       
|                          |                                                                 |                                        | Y due May 1, 2027, variable             |                            |   |        |  |        |       
|                          |                                                                 |                                        | Z due August 1, 2030, variable          |                            |   |        |  |        |       
|                          |                                                                 |                                        | AA due September 1, 2027, variable      |                            |   |        |  |        |       
|                          |                                                                 |                                        |                                         |                            |   |        |  |        |       
|                          |                                                                 |                                        |                                         | Total first mortgage bonds |   |        |  |        |       
|                          | Pollution control bonds (unsecured)                            |                                        |                                         |                            |   |        |  |        |       
|                          |                                                                 | Series due September 1, 2026, variable |                                         |                            |   |        |  |        |       
|                          |                                                                 | Series due September 1, 2026, variable |                                         |                            |   |        |  |        |       
|                          |                                                                 | Series due November 1, 2027, variable  |                                         |                            |   |        |  |        |       
|                          |                                                                 | Series due November 1, 2027, variable  |                                         |                            |   |        |  |        |       
|                          |                                                                 |                                        |                                         |                            |   |        |  |        |       
|                          |                                                                 |                                        | Total unsecured pollution control bonds |                            |   |        |  |        |       
|                          |                                                                 |                                        |                                         |                            |   |        |  |        |       
|                          |                                                                 | Total bonds outstanding                |                                         |                            |   |        |  |        |       
|                          |                                                                 | Less current portion of long-term debt |                                         |                            |   |        |  |        |       
|                          |                                                                 |                                        |                                         |                            |   |        |  |        |       
|                          |                                                                 | Long-term debt                         |                                         |                            |   |        |  |        |       
|                          |                                                                 |                                        |                                         |                            |   |        |  |        |       
|                          |                                                                 | Total capitalization                   |                                         |                            |   |        |  |        | $     
|                          |                                                                 |                                        |                                         |                            |   |        |  |        |       

The accompanying notes are an integral part of these consolidated financial statements.

66

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Louisville Gas and Electric Company and Subsidiary  Notes to Consolidated Financial Statements

Note 1Summary of Significant Accounting Policies

LG&E, a subsidiary of LG&E Energy and an indirect subsidiary of Powergen, 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 in Kentucky. LG&E Energy is an exempt public utility holding company with wholly owned
subsidiaries including LG&E, KU, Capital Corp., LEM, and LG&E Services. All of the LG&E's Common Stock is held by LG&E Energy. LG&E has one wholly owned consolidated subsidiary, LG&E Receivable.

On
December 11, 2000, LG&E Energy Corp.was acquired by Powergen. Powergen is a registered public utility holding company under PUHCA. No costs associated with the Powergen acquisition
nor any of the effects of purchase accounting have been reflected in the financial statements of LG&E.

Certain
reclassification entries have been made to the 2000 financial statements to conform to the 2001 presentation with no impact on the balance sheet totals or previously reported
income.

Utility Plant.LG&E's plant is stated at original cost, which includes payroll-related costs such as taxes, fringe benefits,
and administrative and general costs. Construction work in progress has been included in the rate base for determining retail customer rates. LG&E has not recorded any allowance for funds used during
construction.

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

Depreciation.Depreciation is provided on the straight-line method over the estimated service lives of depreciable plant.
Pursuant to a final order of the Kentucky Commission dated December 3, 2001, LG&E implemented new depreciation rates effective as of January 1, 2001. The amounts provided for 2001 were 3.0% (2.9%
electric, 2.9% gas and 5.7% common); for 2000 were 3.6% (3.3% electric, 3.8% gas and 7.3% common); and for 1999 were 3.4% (3.2% electric, 3.2% gas, and 7.1% common) of average depreciable plant.

Cash and Temporary Cash Investments.LG&E considers all highly liquid debt instruments purchased with a maturity of three
months or less to be cash equivalents. Temporary cash investments are carried at cost, which approximates fair value.

Gas Stored Underground.Gas inventories of $46.4 million and $54.4 million at December 31, 2001, and 2000, respectively, are
included in gas stored underground in the balance sheet. The inventory is accounted for using the average-cost method.

Financial Instruments.LG&E uses over-the-counter interest-rate swap agreements to hedge its exposure to fluctuations in the
interest rates it pays on variable-rate debt. Gains and losses on interest-rate swaps used to hedge interest rate risk are reflected in other comprehensive income. In 2000, LG&E used exchange traded
U.S. Treasury note and bond futures to hedge its exposure to fluctuations in the value of its investments in the preferred stocks of other companies. Gains and losses on U.S. Treasury note and bond
futures were charged or credited to other income-net. See Note 4Financial Instruments.

Debt Expense.Debt expense is capitalized in deferred debits and amortized over the lives of the related bond issues,
consistent with regulatory practices.

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Deferred Income Taxes.Deferred income taxes have been provided for all material book-tax temporary differences.

Investment Tax Credits.Investment tax credits resulted from provisions of the tax law that permitted a reduction of LG&E's
tax liability based on credits for certain construction expenditures. Deferred investment tax credits are being amortized to income over the estimated lives of the related property that gave rise to
the credits.

Revenue Recognition.Revenues are recorded based on service rendered to customers through month-end. LG&E accrues an estimate
for unbilled revenues from each meter reading date to the end of the accounting period. The unbilled revenue estimates included in accounts receivable for LG&E at December 31, 2001 and 2000, were
approximately $37.3 million and $62.8 million, respectively. See Note 3, Rates and Regulatory Matters. LG&E recorded electric revenues that resulted from sales to a related party, KU, of $28.5
million, $20.9 million and $20.2 million for years ended December 31, 2001, 2000 and 1999, respectively.

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

Management's Use of Estimates.The preparation of financial statements in conformity with generally accepted accounting
principles requires management to make estimates and assumptions that affect the reported assets and liabilities and disclosure of contingent items at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. See Note 12, Commitments and Contingencies, for a further discussion.

Accounts Receivable Securitization.SFAS No. 140,Accounting for Transfers and Servicing of Financial
Assets and Extinguishments of Liabilities, revises the standards for accounting for securitizations and other transfers of financial assets and collateral and requires certain
disclosures, and provides accounting and reporting standards for transfers and servicing of financial assets and extinguishments of liabilities. SFAS No. 140 was adopted in the first quarter of 2001,
when LG&E entered into an accounts receivable securitization transaction.

On
February 6, 2001, LG&E implemented an accounts receivable securitization program. The purpose of this program is to enable LG&E to accelerate the receipt of cash from the collection
of retail accounts receivable, thereby reducing dependence upon more costly sources of working capital. The securitization program allows for a percentage of eligible receivables to be sold. Eligible
receivables are generally all receivables associated with retail sales that have standard terms and are not past due. LG&E is able to terminate these programs at any time without penalty. If there is
a significant deterioration in the payment record of the receivables by the retail customers or if LG&E fails to meet certain covenants regarding the program, the program may terminate at the election
of the financial institutions. In this case, payments from retail customers would first be used to repay the financial institutions participating 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 a wholly owned subsidiary, LG&E R. Simultaneously, LG&E R entered into two separate three-year accounts receivable
securitization facilities with two financial institutions and their affiliates whereby LG&E R can sell, on a revolving basis, an undivided interest in certain of their receivables and receive up to
$75 million from an unrelated third party purchaser. The effective cost of the receivables programs is comparable to LG&E's lowest cost source of capital, and is based on prime rated commercial paper.
LG&E retains
servicing rights of the sold receivables through two separate servicing agreements with the third party purchaser. LG&E has obtained an opinion from independent legal counsel indicating these
transactions qualify as true sale of receivables. As of December 31, 2001, the outstanding program balance was $42 million.

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Management
expects to renew these facilities when they expire.

The
allowance for doubtful accounts associated with the eligible securitized receivables was $1.3 million at December 31, 2001. This allowance is based on historical experience of
LG&E. Each securitization facility contains a fully funded reserve for uncollectible receivables.

New Accounting Pronouncements.During 2001 and 2000, the following accounting pronouncements were issued that affect LG&E:

SFAS
No. 133,Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138,Accounting for
Certain Derivative Instruments and Certain Hedging Activities,establishes accounting and reporting standards requiring that every derivative instrument (including certain
derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or a liability measured at its fair value. SFAS No. 133 requires that changes in the
derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset
related results on the hedged item in the income statement, and requires that LG&E must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. SFAS
No. 133 could increase the volatility in earnings and other comprehensive income. SFAS No. 137,Accounting for Derivative Instruments and Hedging
ActivitiesDeferral of the Effective Date of SFAS No. 133, deferred the effective date of SFAS No. 133 until January 1, 2001. LG&E adopted SFAS No. 133 and SFAS No.
138 on January 1, 2001. The effect of adopting these statements resulted in a $3.6 million decrease in other comprehensive income from a cumulative effect of change in accounting principle (net of tax
of $2.4 million).

The
Financial Accounting Standards Board created the Derivatives Implementation Group (DIG) to provide guidance for implementation of SFAS No. 133. DIG Issue C15,
Normal Purchases and Normal Sales Exception for Option Type Contracts and Forward Contracts in Electricitywas adopted in 2001 and had no impact on results of operations and
financial position. DIG Issue C16,Applying the Normal Purchases and Normal Sales Exception to Contracts that Combine a Forward Contract and a Purchased Option
Contract, was cleared in 2001 and stated that option contracts do not meet the normal purchases and normal sales exception and should follow SFAS No. 133. DIG C16 will be
effective in the second quarter of 2002. Management has not determined the impact this issue will have on its results of operations and financial position.

SFAS
No. 141,Business Combinationsand SFAS No. 142,Goodwill and Other Intangible Assetswere issued in 2001. SFAS No. 141 requires all business combinations initiated after June 30, 2001, to be accounted for using the purchase method. SFAS No. 142 requires goodwill to be recorded, but
not amortized. Further, goodwill will now be subject to a periodic assessment for impairment. The provisions of these new pronouncements were effective July 1, 2001, for LG&E. The adoption of these
standards did not have a material impact on the results of operations or financial position of LG&E.

SFAS
No. 143,Accounting for Asset Retirement Obligationsand SFAS No. 144,Accounting for the Impairment
or Disposal of Long-Lived Assets, were issued 2001. SFAS No. 143 establishes accounting and reporting standards for obligations associated with the retirement of tangible
long-lived assets and the associated asset retirement costs. SFAS No. 144 supersedes SFAS No. 121,Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Ofand the accounting and reporting provisions of APB Opinion No. 30,Reporting the Results of
OperationsReporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions.SFAS No.
144, among other provisions, eliminates the requirement of SFAS No. 121 to allocate goodwill to long-lived assets to be tested for impairment. The effective implementation date for
SFAS No. 144 is 2002 and SFAS No. 143 is 2003. Based on current regulatory accounting practices, management does not expect SFAS No. 143 or SFAS No. 144 to have a material
impact on results of operations or financial position of LG&E.

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Note 2Mergers and Acquisitions

On December 11, 2000, LG&E Energy Corp. was acquired by Powergen plc. for cash of approximately $3.2 billion or $24.85 per share and the assumption of all of LG&E
Energy's debt. As a result of the acquisition, LG&E Energy became a wholly owned subsidiary of Powergen and, as a result, LG&E became an indirect subsidiary of Powergen. LG&E has continued its
separate identity and serves customers in Kentucky under its existing name. The preferred stock and debt securities of LG&E were not affected by this transaction resulting in the utility operations'
obligation to continue to file SEC reports. Following the acquisition, Powergen became a registered holding company under PUHCA, and LG&E, as a subsidiary of a registered holding company, became
subject to additional regulations under PUHCA.

LG&E
Energy and KU Energy merged on May 4, 1998, with LG&E Energy as the surviving corporation. As a result of the merger, LG&E Energy, which is the parent of LG&E, became the parent
company of KU. The operating utility subsidiaries (LG&E and KU) have continued to maintain their separate corporate identities and serve customers in Kentucky and Virginia under their present names.
LG&E Energy estimated non-fuel savings over a ten year period following the merger. Costs to achieve these savings for LG&E of $50.2 million were recorded in the second quarter of 1998, $18.1 million
of which were initially deferred and are being amortized over a five-year period pursuant to regulatory orders. Primary components of the merger costs were separation benefits, relocation costs,
and transaction fees, the majority of which were paid by December 31, 1998. LG&E expensed the remaining costs associated with the merger ($32.1 million) in the second quarter of 1998. In regulatory
filings associated with approval of the merger, LG&E committed not to seek increases in existing base rates and proposed reductions in their retail customers' bills in amounts based on one-half of the
savings, net of the deferred and amortized amount, over a five-year period. The preferred stock and debt securities of LG&E were not affected by the merger.

Management
has accounted for the KU/LG&E merger as a pooling of interests and as a tax-free reorganization under the Internal Revenue Code.

As
part of its merger order, the Kentucky Commission approved a surcredit whereby 50% of the net non-fuel cost savings estimated to be achieved from the merger, less $18.1 million or 50%
of the originally estimated costs to achieve such savings, be applied to reduce customer rates through a surcredit on customers' bills and the remaining 50% be retained by the companies. The surcredit
is allocated 53% to KU and 47% to LG&E pursuant to Kentucky Commission order. The surcredit will be about 2% of customer bills through mid 2003 and will amount to approximately $55 million in net
non-fuel savings to LG&E. Any fuel cost savings are passed to Kentucky customers through the companies' fuel adjustment clauses. See Note 3 for more information about LG&E's rates and regulatory
matters.

Note 3Rates and Regulatory Matters

Accounting for the regulated utility business conforms with generally accepted accounting principles as applied to regulated public utilities and as prescribed by
FERC and the Kentucky Commission. LG&E is subject to SFAS No. 71,Accounting for the Effects of Certain Types of Regulation, under which certain costs
that would otherwise be charged to expense are deferred as regulatory assets based on expected recovery from customers in future rates. Likewise, certain credits that would otherwise be reflected as
income are deferred as regulatory liabilities based on expected return to customers in future rates. LG&E's current or expected recovery of deferred costs and expected return of deferred credits is
generally based on specific ratemaking decisions or precedent for each item. The

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following regulatory assets and liabilities were included in LG&E's balance sheets as of December 31 (in thousands of $):

2001

2000VDT Costs

$
127,529

$
Gas supply adjustments due from customers


30,135


12,324Unamortized loss on bonds


17,902


19,036LGE/KU merger costs


5,444


9,073Manufactured gas sites


2,062


2,368One utility costs


3,643


6,331Other


10,427


5,307Total regulatory assets


197,142


54,439Deferred income taxesnet


(48,703
)

(54,593
)Gas supply adjustments due to customers


(15,702
)

(2,209
)Other


(944
)

(4,391
)Total regulatory liabilities


(65,349
)

(61,013
)Regulatory assets (liabilities)net

$
131,793

$
(6,574
)


Kentucky Commission SettlementValue Delivery Costs.During the first quarter 2001, LG&E recorded a $144 million
charge for a workforce reduction program. Primary components of the charge were separation benefits, enhanced early retirement benefits, and health care benefits. The result of this workforce
reduction was the elimination of over 700 positions, accomplished primarily through a voluntary enhanced severance program.

On
June 1, 2001, LG&E filed an application (VDT case) with the Kentucky Commission to create a regulatory asset relating to these first quarter 2001 charges. The application requested
permission to amortize these costs over a four-year period. The Kentucky Commission also opened a case to review the new depreciation study and resulting depreciation rates implemented in 2001.

LG&E
reached a settlement in the VDT case as well as the other cases involving depreciation rates and ESM with all intervening parties. The settlement agreement was approved by the
Kentucky Commission on December 3, 2001.

The
Kentucky Commission December 3, 2001, order allowed LG&E to set up a regulatory asset of $141 million for the workforce reduction costs and begin amortizing these costs over a five
year period starting in April 2001. The first quarter charge of $144 million represented all employees who had accepted a voluntary enhanced severance program. Some employees rescinded their
participation in the voluntary enhanced severance program, thereby decreasing the original charge from $144 million to $141 million. The settlement will also reduce revenues approximately $26 million
through a surcredit on future bills to customers over the same five year period. The surcredit represents net savings stipulated by LG&E. The agreement also established LG&E's new depreciation rates
in effect December 2001, retroactive to January 1, 2001. The new depreciation rates decreased depreciation expense by $5.6 million in 2001.

PUHCA.Following the purchase of LG&E Energy by Powergen, Powergen became a registered holding company under PUHCA. As a
result, Powergen, its utility subsidiaries, including LG&E, and certain of its non-utility subsidiaries are subject to extensive regulation by the SEC under PUHCA with respect to issuances and sales
of securities, acquisitions and sales of certain utility properties, and intra-system sales of certain goods and services. In addition, PUHCA generally limits the ability of registered holding
companies to acquire additional public utility systems and to acquire and retain businesses unrelated to the utility operations of the holding company. Powergen believes that it has adequate

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authority (including financing authority) under existing SEC orders and regulations for it and its subsidiaries to conduct their businesses and will seek additional authorization when necessary.

Environmental Cost Recovery.In June 2000, the Kentucky Commission approved LG&E's application for a CCN to construct up to
three SCR NOx reduction facilities. The construction and subsequent operation of the SCRs is intended to reduce NOx emission levels to meet the EPA's mandated NOx emission level of 0.15 lbs./ Mmbtu by
May 2004. In its order, the Kentucky Commission ruled that LG&E's proposed plan for construction was "reasonable, cost-effective and will not result in the wasteful duplication of facilities." In
October 2000, LG&E filed an application with the Kentucky Commission to amend its Environmental Compliance Plan to reflect the addition of the proposed NOx reduction technology projects and to amend
its Environmental Cost Recovery Tariff to include an overall rate of return on capital investments. Approval of LG&E's application will allow LG&E to begin to recover the costs associated with these
new projects, subject to Kentucky Commission
oversight during normal six-month and two-year reviews. Following the completion of hearings in March 2001, a ruling was issued in April 2001 approving LG&E's application.

ESM.LG&E's electric rates are subject to an ESM. The ESM, in place for three years beginning in 2000, sets an upper and
lower point for rate of return on equity, whereby if LG&E's rate of return for the calendar year falls within the range of 10.5% to 12.5%, no action is necessary. If earnings are above the upper
limit, then excess earnings are shared 40% with ratepayers and 60% with shareholders; if earnings are below the lower limit, then earnings deficiency is recovered 40% from ratepayers and 60% from
shareholders. The first ESM filing was made on March 1, 2001, for year ended December 31, 2000 that resulted in a refund to customers of $618,000. By order of the Kentucky Commission, rate changes
prompted by the ESM filing go into effect in April of each year. LG&E estimated that the rate of return will fall within the deadband range, subject to Kentucky Commission approval, for the year ended
December 31, 2001; therefore, no adjustment to the financial statements was made.

DSM.LG&E's rates contain a DSM provision. The provision includes a rate mechanism that provides concurrent recovery of DSM
costs and provides an incentive for implementing DSM programs. This program had allowed LG&E to recover revenues from lost sales associated with the DSM program. In May 2001, the Kentucky Commission
approved LG&E's plan to continue DSM programs. This filing called for the expansion of the DSM programs into the service territory served by KU and proposes a mechanism to recover revenues from lost
sales associated with DSM programs based on program planning engineering estimates and post-implementation evaluation.

Gas PBR.Since November 1, 1997, LG&E has operated under an experimental performance-based ratemaking mechanism related to
its gas procurement activities. For each of the last four years, LG&E's rates have been adjusted to recover its portion of the savings (or expenses) incurred during each of the four 12-month periods
beginning November 1 and ending October 31. Since its implementation on November 1, 1997, through October 31, 2001, LG&E has achieved $32.1 million in savings. Of the total savings, LG&E has retained
$15.0 million, and the remaining portion of $17.1 million has been distributed to customers. In December 2000, LG&E filed an Application reporting on the operation of the experimental PBR and
requested the Kentucky Commission to extend the PBR as a result of the benefits provided to both LG&E and its customers during the experimental period. Following the discovery and hearing process, the
Kentucky Commission issued an order effective November 1, 2001, extending the experimental PBR program for an additional four years, and making other modifications, including changes to the sharing
levels applicable to savings or expenses incurred under the PBR. Specifically, the Kentucky Commission substituted a 25%/75% Company/Customer sharing for all savings (and expenses) up to 4.5% of the
benchmarked gas costs. Savings (and expenses) in excess of 4.5% of the benchmarked gas costs are shared at a 50%/50% level.

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FAC.Prior to implementation of the PBR in July 1999, and following its termination in March 2000, LG&E employed an FAC
mechanism, which under Kentucky law allowed LG&E to recover from customers the actual fuel costs associated with retail electric sales.

In
February 1999, LG&E received orders from the Kentucky Commission requiring a refund to retail electric customers of approximately $3.9 million resulting from reviews of the FAC from
November 1994, through April 1998, of which $1.9 million was refunded in April 1999, for the period beginning November 1994, and ending October 1996. The orders changed LG&E's method of computing fuel
costs associated with electric line losses on wholesale sales appropriate for recovery through the FAC. Following rehearing in December 1999, the Kentucky Commission agreed with LG&E "s position on
the appropriate loss factor to use in the FAC computation and issued an order reducing the refund level for the 18-month period under review to approximately $800,000 for the period November 1996
through April 1998. LG&E enacted the refund with billings in the month of January 2000. LG&E and KIUC each filed separate appeals from the Kentucky Commission's February 1999 orders with the Franklin
County, Kentucky Circuit Court and in May 2000, the Court affirmed the Kentucky Commission's orders regarding the amounts disallowed and ordered the case remanded as to the Kentucky Commission's
denial of interest, directing the Kentucky Commission to determine whether interest should be awarded to LG&E's ratepayers. In June 2000, LG&E appealed the Circuit Court's decision to the Kentucky
Court of Appeals. Pending a decision on this appeal, a comprehensive settlement was reached by all parties, which settlement was filed with the Kentucky Commission on December 21, 2001. Thereunder,
LG&E agreed to credit its fuel clause in the amount of $720,000 (such credit provided over the course of two monthly billing periods), and the parties agreed on a prospective interpretation of the
state's fuel adjustment clause regulation to ensure consistent and mutually acceptable application on a going-forward basis. All pending FAC proceedings before the court were resolved by the parties
to the agreement and all parties requested the Court of Appeals remand the case to the Kentucky Commission. The Kentucky Commission is expected to approve the settlement in 2002.

Gas Rate Case.In March 2000, LG&E filed an application with the Kentucky Commission requesting an adjustment in LG&E's gas
rates. In September 2000, the Kentucky Commission 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's proposal for a weather normalization billing adjustment mechanism that will normalize the effect of weather on revenues from gas sales.

Wholesale Natural Gas Prices.On September 12, 2000, the Kentucky Commission issued an order establishing Administrative Case
No. 384"An Investigation of Increasing Wholesale Natural Gas Prices and the Impacts of such Increase on the Retail Customers Served by Kentucky's Jurisdictional Natural Gas Distribution
Companies". The impetus for this administrative proceeding was the escalation of wholesale natural gas prices during the summer of 2000.

The
Kentucky Commission directed Kentucky's natural gas distribution companies, including LG&E, to file selected information regarding the individual companies' natural gas purchasing
practices, expectations for the then-approaching winter heating season of 2000-2001, and potential actions which these companies might take to mitigate price volatility. On July 17, 2001, the Kentucky
Commission issued an Order encouraging the natural gas distribution companies in Kentucky to take various actions, among them to propose a natural gas hedge plan, consider performance-based ratemaking
mechanisms, and to increase the use of storage.

On
August 12, 2001, LG&E submitted a natural gas hedge plan in Case No. 2001-253. However, due to significantly decreased wholesale natural gas prices during the Summer of 2001, the
Kentucky Commission ultimately rejected LG&E's proposed gas hedging plan as "untimely" in its order dated October 5, 2001.

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Another
result from that Administrative Case was the Kentucky Commission's decision to engage a consultant to conduct a forward-looking audit of the gas procurement and supply procedures
in order to assist both the Kentucky Commission and each of Kentucky's largest natural gas distribution companies. This audit is underway.

Kentucky Commission Administrative Case for Affiliate Transactions.In December 1997, the Kentucky Commission opened
Administrative Case No. 369 to consider Kentucky Commission policy regarding cost allocations, affiliate transactions and codes of conduct governing the relationship between utilities and their
non-utility operations and affiliates. The Kentucky Commission intended to address two major areas in the proceedings: the tools and conditions needed to prevent cost shifting and cross-subsidization
between regulated and non-utility operations; and whether a code of conduct should be established to assure that non-utility segments of the holding company are not engaged in practices that could
result in unfair competition caused by cost shifting from the non-utility affiliate to the utility. During the period September 1998 to February 2000, the Kentucky Commission issued draft codes 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 utilities that provide
nonregulated activities to keep separate accounts and allocate costs in accordance with procedures established by the Kentucky Commission. In the same Bill, the General Assembly set forth provisions
to govern a utilities activities related to the sharing of information, databases, and resources between its employees or an affiliate involved in the marketing or the provision of nonregulated
activities and its employees or an affiliate involved in the provision of regulated services. The legislation became law in July 2000 and LG&E has been operating pursuant thereto since that time. On
February 14, 2001, the Kentucky Commission published notice of their intent to promulgate new administrative regulations under the auspices of this new law. This effort is still on going.

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Note 4Financial Instruments

The cost and estimated fair values of LG&E's non-trading financial instruments as of December 31, 2001, and 2000 follow (in thousands of $):

|                                                |                                        | 2001 |         | 2000 |   |         |    
|----------------------------------------------- | -------------------------------------- | ---- | ------- | ---- | - | ------- | ---
|
|Marketable securities                           |                                        | $    |        |      | $ |        |    
|Long-term investments                          |                                        |      |         |      |   |         |    
|                                                | Not practicable to estimate fair value |      |         | 490  |   |         | 490
|Preferred stock subject to mandatory redemption |                                        |      | 25,000  |      |   | 25,125  |    
|Long-term debt (including current portion)      |                                        |      | 616,904 |      |   | 620,504 |    
|Interest-rate swaps                             |                                        |      |        |      |   | (8,604  | )  

All
of the above valuations reflect prices quoted by exchanges except for the swaps and the long-term investments. The fair values of the swaps reflect price quotes from dealers or
amounts calculated using accepted pricing models. The fair values of the long-term investments reflect cost, since LG&E cannot reasonably estimate fair value.

Interest Rate Swaps.LG&E uses interest rate swaps to hedge exposure to market fluctuations in certain of its debt
instruments. Pursuant to policy, use of these financial instruments is intended to mitigate risk and earnings volatility and is not speculative in nature. Management has designated all of the interest
rate swaps as hedge instruments. Financial instruments designated as cash flow hedges have resulting gains and losses recorded within other comprehensive income and stockholders' equity. To the extent
a financial instrument or the underlying item being hedged is prematurely terminated or the hedge becomes ineffective, the resulting gains or losses are reclassified from other comprehensive income to
net income. Financial instruments designated as fair value hedges are periodically marked to market with the resulting gains and losses recorded directly into net income to correspond with income or
expense recognized from changes in market value of the items being hedged.

As
of December 31, 2001 and 2000, LG&E was party to various interest rate swap agreements with aggregate notional amounts of $117.3 million and $234.3 million, respectively. Under these
swap agreements, LG&E paid fixed rates averaging 5.13% and 4.40%, and received variable rates based on the Bond Market Association's municipal swap index averaging 1.61% and 4.84% at December 31, 2001
and 2000, respectively. The swap agreements in effect at December 31, 2001 have been designated as cash flow hedges and mature on dates ranging from 2003 to 2020. The hedges have been deemed to be
fully effective resulting in a pretax loss of $2.6 million for 2001, recorded in other comprehension income. Upon expiration of these hedges, the amount recorded in other comprehension income will be
reclassified into earnings. The amounts expected to be reclassified from other comprehension income to earnings in the next twelve months is immaterial.

Energy Trading.LG&E conducts energy trading and risk management activities to maximize the value of power sales from
physical assets it owns, in addition to the wholesale sale of excess asset capacity. Certain energy trading activities are accounted for on a mark-to-market basis in accordance with EITF 98-10 Accounting for Contracts Involved
in Energy Trading and Risk Management Activities, SFAS No. 133 Accounting for Derivative Instruments and Hedging
Activities,andSFAS No. 138 Accounting for Certain Derivative Instruments and Certain Hedging Activities. Wholesale sales of
excess asset capacity and wholesale purchases are treated as normal sales and purchases underSFAS No. 133andSFAS No.
138and are not marked to market.

LG&E
has recorded a net liability of $186,000 and $17,000 at December 31, 2001 and 2000, respectively.

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No
changes to valuation techniques for energy trading and risk management activities occurred during 2001. All contracts outstanding at December 31, 2001 have a maturity of less than one
year and are valued using prices actively quoted for proposed or executed transactions or quoted by brokers.

Note 5Concentrations of Credit and Other Risk

Credit risk represents the accounting loss that would be recognized at the 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 have similar economic or industry characteristics that would cause their ability to meet contractual
obligations to be similarly affected by changes in economic or other conditions.

LG&E's
customer receivables and gas and electric revenues arise from deliveries of natural gas to approximately 305,000 customers and electricity to approximately 378,000 customers in
Louisville and adjacent areas in Kentucky. For the year ended December 31, 2001, 71% of total revenue was derived from electric operations and 29% from gas operations.

In
November 2001, LG&E and IBEW Local 2100 employees, which represent approximately 70% of LG&E's workforce, entered into a four-year collective bargaining agreement.

Note 6Marketable Securities

In 2000, LG&E classified marketable securities as "trading securities" under the provisions of SFAS No. 115,Accounting for Certain
Investments in Debt and Equity Securities. Prior to that, LG&E's marketable securities had been determined to be "available-for-sale." All unrealized holding gains and losses
were immediately recognized in earnings on the date of transfer. Proceeds from sales of trading securities in 2000 were approximately $4.1 million. Proceeds from sales of available-for-sale securities
in 1999 were approximately $11.7 million. Sales of securities resulted in immaterial net realized gains and losses, calculated using the specific identification method.

LG&E
has no trading securities at December 31, 2001. Approximate cost, fair value, and other required information pertaining to LG&E's securities by major security type, as of December
31, 2000, follow (in thousands of $):

2000:

EquityCost

$
4,403Realized losses


(347
)Fair values

$
4,056Fair values:No maturity

$
4,056Total fair values

$
4,056


Note 7Pension Plans and Retirement Benefits

Pension Plans.LG&E sponsors several qualified and non-qualified pension plans and other postretirement benefit plans for its
employees. The following tables provide a reconciliation of the changes in the plans' benefit obligations and fair value of assets over the three-year period ending

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December 31, 2001, and a statement of the funded status as of December 31 for each of the last three years (in thousands of $):

|                                |                                                | 2001 |   | 2000     |   | 1999 |        
|------------------------------- | ---------------------------------------------- | ---- | - | -------- | - | ---- | -------
|Pension Plans:                  |                                                |      |   |          |   |      |        
|Change in benefit obligation    |                                                |      |   |          |   |      |        
|                                | Benefit obligation at beginning of year        |      | $ | 310,822  |   | $    | 283,267
|                                | Service cost                                   |      |   | 1,311    |   |      | 3,408  
|                                | Interest cost                                  |      |   | 25,361   |   |      | 22,698 
|                                | Plan amendments                                |      |   | 1,550    |   |      | 17,042 
|                                | Curtailment loss                               |      |   | 24,563   |   |      |       
|                                | Special termination benefits                   |      |   | 53,610   |   |      |       
|                                | Benefits paid                                  |      |   | (53,292  | ) |      | (16,656
|                                | Actuarial (gain) or loss and other             |      |   | (7,632   | ) |      | 1,063  
|                                |                                                |      |   |          |   |      |        
|                                | Benefit obligation at end of year              |      | $ | 356,293  |   | $    | 310,822
|                                |                                                |      |   |          |   |      |        
|Change in plan assets           |                                                |      |   |          |   |      |        
|                                | Fair value of plan assets at beginning of year |      | $ | 333,378  |   | $    | 360,095
|                                | Actual return on plan assets                   |      |   | (27,589  | ) |      | (6,150 
|                                | Employer contributions and plan transfers      |      |   | (17,134  | ) |      | (1,804 
|                                | Benefits paid                                  |      |   | (53,292  | ) |      | (16,656
|                                | Administrative expenses                        |      |   | (1,419   | ) |      | (2,107 
|                                |                                                |      |   |          |   |      |        
|                                | Fair value of plan assets at end of year       |      | $ | 233,944  |   | $    | 333,378
|                                |                                                |      |   |          |   |      |        
|Reconciliation of funded status |                                                |      |   |          |   |      |        
|                                | Funded status                                  |      | $ | (122,349 | ) | $    | 22,556 
|                                | Unrecognized actuarial (gain) or loss          |      |   | 18,800   |   |      | (74,086
|                                | Unrecognized transition (asset) or obligation  |      |   | (4,215   | ) |      | (5,853 
|                                | Unrecognized prior service cost                |      |   | 35,435   |   |      | 47,984 
|                                |                                                |      |   |          |   |      |        
|                                | Net amount recognized at end of year           |      | $ | (72,329  | ) | $    | (9,399 
|                                |                                                |      |   |          |   |      |        
|Other Benefits:                 |                                                |      |   |          |   |      |        
|Change in benefit obligation    |                                                |      |   |          |   |      |        
|                                | Benefit obligation at beginning of year        |      | $ | 56,981   |   | $    | 44,997 
|                                | Service cost                                   |      |   | 358      |   |      | 822    
|                                | Interest cost                                  |      |   | 5,865    |   |      | 4,225  
|                                | Plan amendments                                |      |   | 1,487    |   |      | 5,826  
|                                | Curtailment loss                               |      |   | 8,645    |   |      |       
|                                | Special termination benefits                   |      |   | 18,089   |   |      |       
|                                | Benefits paid                                  |      |   | (4,877   | ) |      | (4,889 
|                                | Actuarial (gain) or loss                       |      |   | 3,398    |   |      | 6,000  
|                                |                                                |      |   |          |   |      |        
|                                | Benefit obligation at end of year              |      | $ | 89,946   |   | $    | 56,981 
|                                |                                                |      |   |          |   |      |        
|Change in plan assets           |                                                |      |   |          |   |      |        
|                                | Fair value of plan assets at beginning of year |      | $ | 7,166    |   | $    | 10,526 
|                                | Actual return on plan assets                   |      |   | (765     | ) |      | (92    
|                                | Employer contributions and plan transfers      |      |   | 1,282    |   |      | 1,621  
|                                | Benefits paid                                  |      |   | (4,881   | ) |      | (4,889 
|                                |                                                |      |   |          |   |      |        
|                                | Fair value of plan assets at end of year       |      | $ | 2,802    |   | $    | 7,166  
|                                |                                                |      |   |          |   |      |        

77

---

|Reconciliation of funded status |                                               |  |   |         |   |   |         |   |   |        
|------------------------------- | --------------------------------------------- |  | - | ------- | - | - | ------- | - | - | -------
|                                | Funded status                                 |  | $ | (87,144 | ) | $ | (49,815 | ) | $ | (34,471
|                                | Unrecognized actuarial (gain) or loss         |  |   | 15,947  |   |   | 5,623   |   |   | (1,638 
|                                | Unrecognized transition (asset) or obligation |  |   | 7,346   |   |   | 13,374  |   |   | 14,489 
|                                | Unrecognized prior service cost               |  |   | 5,302   |   |   | 8,960   |   |   | 4,292  
|                                |                                               |  |   |         |   |   |        
|                                | Net amount recognized at end of year          |  | $ | (58,549 | ) | $ | (21,858 | ) | $ | (17,328
|                                |                                               |  |   |         |   |   |        

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

The
following tables provide the amounts recognized in the balance sheet and information for plans with benefit obligations in excess of plan assets as of December 31, 2001, 2000 and
1999 (in thousands of $):

|                                                                                                            |                                        | 2001 |   | 2000     |   | 1999 |        
|----------------------------------------------------------------------------------------------------------- | -------------------------------------- | ---- | - | -------- | - | ---- | -------
|Pension Plans:                                                                                              |                                        |      |   |          |   |      |        
|Amounts recognized in the balance sheet consisted of:                                                       |                                        |      |   |          |   |      |        
|                                                                                                            | Prepaid benefits cost                  |      | $ |         |   | $    | 18,880 
|                                                                                                            | Accrued benefit liability              |      |   | (108,977 | ) |      | (28,279
|                                                                                                            | Intangible asset                       |      |   | 11,936   |   |      |       
|                                                                                                            | Accumulated other comprehensive income |      |   | 24,712   |   |      |       
|                                                                                                            |                                        |      |   |          |   |      |        
|                                                                                                            | Net amount recognized at year-end      |      | $ | (72,329  | ) | $    | (9,399 
|                                                                                                            |                                        |      |   |          |   |      |        
|Additional year-end information for plans with accumulated benefit obligations in excess of plan assets(1): |                                        |      |   |          |   |      |        
|                                                                                                            | Projected benefit obligation           |      | $ | 356,293  |   | $    | 4,088  
|                                                                                                            | Accumulated benefit obligation         |      |   | 352,477  |   |      | 3,501  
|                                                                                                            | Fair value of plan assets              |      |   | 233,944  |   |      |       

---

|Other Benefits:                                                                              |                              |  |   |         |   |   |         |   |   |        
|-------------------------------------------------------------------------------------------- | ---------------------------- |  | - | ------- | - | - | ------- | - | - | -------
|Amounts recognized in the balance sheet consisted of:                                        |                              |  |   |         |   |   |         |   |   |        
|                                                                                             | Accrued benefit liability    |  | $ | (58,549 | ) | $ | (21,858 | ) | $ | (17,328
|                                                                                             |                              |  |   |         |   |   |        
|Additional year-end information for plans with benefit obligations in excess of plan assets: |                              |  |   |         |   |   |         |   |   |        
|                                                                                             | Projected benefit obligation |  | $ | 89,946  |   | $ | 56,981  |   | $ | 44,997 
|                                                                                             | Fair value of plan assets    |  |   | 2,802   |   |   | 7,166   |   |   | 10,526 

78

---

The
following table provides the components of net periodic benefit cost for the plans for 2001, 2000 and 1999 (in thousands of $):

|                                        |                                                  | 2001 |   | 2000    |   | 1999 |        
|--------------------------------------- | ------------------------------------------------ | ---- | - | ------- | - | ---- | -------
|Pension Plans:                          |                                                  |      |   |         |   |      |        
|Components of net periodic benefit cost |                                                  |      |   |         |   |      |        
|                                        | Service cost                                     |      | $ | 1,311   |   | $    | 3,408  
|                                        | Interest cost                                    |      |   | 25,361  |   |      | 22,698 
|                                        | Expected return on plan assets                   |      |   | (26,360 | ) |      | (33,025
|                                        | Amortization of prior service cost               |      |   | 3,861   |   |      | 4,646  
|                                        | Amortization of transition (asset) or obligation |      |   | (1,000  | ) |      | (1,112 
|                                        | Recognized actuarial (gain) or loss              |      |   | (777    | ) |      | (6,856 
|                                        |                                                  |      |   |         |   |      |        
|                                        | Net periodic benefit cost                        |      | $ | 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                                     |      | $ | 358     |   | $    | 822    
|                                        | Interest cost                                    |      |   | 5,865   |   |      | 4,225  
|                                        | Expected return on plan assets                   |      |   | (420    | ) |      | (683   
|                                        | Amortization of prior service cost               |      |   | 951     |   |      | 1,158  
|                                        | Amortization of transition (asset) or obligation |      |   | 719     |   |      | 1,114  
|                                        | Recognized actuarial gain                        |      |   | (32     | ) |      | (485   
|                                        |                                                  |      |   |         |   |      |        
|                                        | Net periodic benefit cost                        |      | $ | 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's pension benefit obligation are shown in the following table:

|                                                 |  | 2001 |   | 2000 |   | 1999 |  
|------------------------------------------------ |  | ---- | - | ---- | - | ---- | -
|Weighted-average assumptions as of December 31:  |  |      |   |      |   |      |  
|Discount rate                                    |  | 7.25 | % | 7.75 | % | 8.00 | %
|Expected long-term rate of return on plan assets |  | 9.50 | % | 9.50 | % | 9.50 | %
|Rate of compensation increase                    |  | 4.25 | % | 4.75 | % | 5.00 | %

For
measurement purposes, a 10.00% annual increase in the per capita cost of covered health care benefits was assumed for 2002. The rate was assumed to decrease gradually to 5.00% for
2011 and remain at that level thereafter.

79

---

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

1% Decrease

1% IncreaseEffect on total of service and interest cost components for 2001

$
(189
)
$
212Effect on year-end 2001 postretirement benefit obligations


(3,025
)

3,073


Thrift Savings Plans.LG&E has a thrift savings plan under section 401(k) of the Internal Revenue Code. Under the plan,
eligible employees may defer and contribute to the plan a portion of current compensation in order to provide future retirement benefits. LG&E makes contributions to the plan by matching a portion of
the employee contributions. The costs were approximately $1.2 million for 2001, and $2.7 million for 2000 and 1999, respectively.

Note 8Income Taxes

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

|                                      |          |   |             | 2001   |   | 2000   |        | 1999 |       
|------------------------------------- | -------- | - | ----------- | ------ | - | ------ | ------ | ---- | ------
|Included in operating expenses:       |          |   |             |        |   |        |        |      |       
|                                      | Current  |  | federal     |        | $ | 42,997 |        | $    | 32,612
|                                      |          |  | state       |        |   | 8,668  |        |      | 5,018 
|                                      | Deferred |  | federalnet |        |   | 12,310 |        |      | 24,272
|                                      |          |  | statenet   |        |   | 3,767  |        |      | 6,797 
|Amortization of investment tax credit |          |   | (4,290      | )      |   | (4,274 | )      |      | (4,289
|                                      |          |   |             |        |   |        |        |      |       
|                                      | Total    |   |             | 63,452 |   |        | 64,425 |      |       
|                                      |          |   |             |        |   |        |        |      |       
|Included in other incomenet:         |          |   |             |        |   |        |        |      |       
|                                      | Current  |  | federal     |        |   | (1,870 | )      |      | (2,187
|                                      |          |  | state       |        |   | (483   | )      |      | (568  
|                                      | Deferred |  | federalnet |        |   | 285    |        |      | (39   
|                                      |          |  | statenet   |        |   | 73     |        |      | (10   
|                                      |          |   |             |        |   |        |        |      |       
|                                      | Total    |   |             | (1,995 | ) |        | (2,804 | )    |       
|                                      |          |   |             |        |   |        |        |      |       
|Total income tax expense              |          | $ | 61,457      |        | $ | 61,621 |        | $    | 58,280
|                                      |          |   |             |        |   |        |        |      |       

80

---

Net
deferred tax liabilities resulting from book-tax temporary differences are shown below (in thousands of $):

2001

2000Deferred tax liabilities:Depreciation and other plant-related items

$
334,914

$
329,836Other liabilities


77,611


22,621412,525


352,457Deferred tax assets:Investment tax credit


23,713


25,444Income taxes due to customers


19,709


22,086Pension overfunding


6,621


5,595Accrued liabilities not currently deductible and other


64,339


10,100114,382


63,225Net deferred income tax liability

$
298,143

$
289,232


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

2001

2000

1999Statutory federal income tax rate

35.0
%
35.0
%
35.0
%State income taxes, net of federal benefit

4.7

4.3

5.1Amortization of investment tax credit

(2.6
)
(2.6
)
(2.8
)Other differencesnet

(0.6
)
(0.9
)
(1.9
)Effective income tax rate

36.5
%
35.8
%
35.4
%


Note 9Other Incomenet

Other incomenet consisted of the following at December 31 (in thousands of $):

2001

2000

1999Interest and dividend income

$
748

$
3,103

$
4,086Gains on fixed asset disposals


1,217


1,014


2,394Income taxes and other


965


804


(2,339
)Other incomenet

$
2,930

$
4,921

$
4,141


Note 10First Mortgage Bonds and Pollution Control Bonds

Long-term debt and the current portion of long-term debt, summarized below (in thousands of $), consists primarily of first mortgage bonds and pollution control
bonds. Interest rates and maturities in the table below are for the amounts outstanding at December 31, 2001.

|                                          |  | Stated
Interest Rates |  | Weighted
Average
Interest
Rate |   | Maturities |  | Principal
Amounts
|----------------------------------------- |  | --------------------- |  | ------------------------------ | - | ---------- |  | -----------------
|Noncurrent portion                        |  | Variable6.55%        |  | 5.40                           | % | 2003-2030  |  | $                
|Current portion (pollution control bonds) |  | Variable              |  | 2.33                           | % | 2013-2027  |  |                  

81

---

Under
the provisions for LG&E's variable-rate pollution control bonds, the bonds are subject to tender for purchase at the option of the holder and to mandatory tender for purchase upon
the occurrence of certain events, causing the bonds to be classified as current portion of long-term debt. The average annualized interest rate for these bonds during 2001 was 4.00%.

LG&E's
First Mortgage Bonds, 6% Series of $42.6 million is scheduled to mature in 2003. There are no other scheduled maturities of Pollution Control Bonds for the five years subsequent
to December 31, 2001.

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

In
January 2000, LG&E exercised its call option on its $20 million 7.50% First Mortgage Bonds due July 1, 2002. The bonds were redeemed utilizing proceeds from issuance of commercial
paper.

In
May 2000, LG&E issued $25 million variable rate pollution control bonds due May 1, 2027 and exercised its call option on $25 million, 7.45%, pollution control bonds due June 15, 2015.
In August 2000, LG&E issued $83 million in variable rate pollution control bonds due August 1, 2030 and exercised its call option on its $83 million, 7 5/8%, pollution control bonds due November 1,
2020.

Annual
requirements for the sinking funds of LG&E's First Mortgage Bonds (other than the First Mortgage Bonds issued in connection with certain Pollution Control Bonds) are the amounts
necessary to redeem 1% of the highest principal amount of each series of bonds at any time outstanding. Property additions (166 2/3% of principal amounts of bonds otherwise required to be so redeemed)
have been applied in lieu of cash.

Substantially
all of LG&E's utility plants are pledged as security for its first mortgage bonds. LG&E's indenture, as supplemented, provides that portions of retained earnings will not
be available for the payment of dividends on common stock, under certain specified conditions. No portion of retained earnings is presently restricted by this provision as of December 31, 2001.

Note 11Notes Payable

LG&E participates in an intercompany money pool agreement wherein LG&E Energy can make funds available to LG&E at market based rates up to $200 million. At
December 31, 2001, the balance of the money pool loan from LG&E Energy was $64.2 million at an average rate of 2.37%, and LG&E had outstanding commercial paper of $30 million at an average rate of
2.54%. The resulting remaining money pool availability at December 31, 2001, was $105.8 million. LG&E Energy maintains a facility of $200 million with an affiliate to ensure funding availability for
the money pool. There was no outstanding balance under this facility as of December 31, 2001, and availability of $170 million remains after considering the $30 million of commercial paper outstanding
at LG&E.

At
December 31, 2000, the money pool loan balance was $114.6 million at an average rate of 6.84% and LG&E had no commercial paper outstanding.

82

---

Note 12Commitments and Contingencies

Construction Program.LG&E had commitments in connection with its construction program aggregating approximately $22.3
million at December 31, 2001. Construction expenditures for the years 2002 and 2003 are estimated to total approximately $334 million, although all of this amount is not currently committed. Included
in 2002 is $38 million for the purchase of 29% of two CTs currently under construction by LG&E Capital Corp. at LG&E's Trimble County location. KU will own 71% of the two CTs. LG&E is waiting for
approval from the Kentucky Commission for the purchase of the CTs.

Operating Lease.LG&E leases office space and accounts for all of its office space leases as operating leases. Total lease
expense for 2001, 2000, and 1999, less amounts contributed by the parent company, was $1.1 million, $.9 million, and $1.5 million, respectively. The future minimum annual lease payments under this
lease agreement for years subsequent to December 31, 2001, are as follows (in thousands of $):

2002

$
3,5942003


3,5072004


3,5072005


1,754Total

$
12,362


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

Environmental.The Clean Air Act imposed stringent new SO2 and NOx emission limits on electric generating units.
LG&E previously had installed scrubbers on all of its generating units. LG&E's strategy for Phase II SO2 reductions, which commenced January 1, 2000, is to increase scrubber removal
efficiency to delay additional capital expenditures and may also include fuel switching or upgrading scrubbers. LG&E met the NOx emission requirements of the Act through installation of low-NOx burner
systems. LG&E's compliance plans are subject to many factors including developments in the emission allowance and fuel markets, future regulatory and legislative initiatives, and advances in clean air
control technology. LG&E will continue to monitor these developments to ensure that its environmental obligations are met in the most efficient and cost-effective manner.

In
September 1998, the EPA announced its final "NOx SIP Call" rule requiring states to impose significant additional reductions in NOx emissions by May 2003, in order to mitigate alleged
ozone transport impacts on the Northeast region. The Commonwealth of Kentucky is currently in the process of revising its State Implementation Plan or "SIP" to require reductions in NOx emissions from
coal-fired generating units to the 0.15 lb./Mmbtu level on a system-wide basis. In related proceedings in 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 directing similar NOx reductions from a number of specifically targeted generating units including all LG&E units. As a result of appeals to both
rules, the compliance date was extended to May 2004. All LG&E generating units are subject to the May 2004 compliance date under these NOx emissions reduction rules.

LG&E
is currently implementing a plan for adding significant additional NOx 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 through the final compliance date. In addition, LG&E will incur additional operating and maintenance costs in operating new NOx
controls.

83

---

LG&E believes its costs in this regard to be comparable to those of similarly situated utilities with like generation assets. LG&E anticipated that such capital and operating costs are the type of
costs that are eligible for recovery from customers under its environmental surcharge mechanism and believed that a significant portion of such costs could be recovered. In April 2001, the Kentucky
Commission granted recovery of these costs.

LG&E
is also monitoring several other air quality issues which may potentially 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 and particulate matter, measures to implement EPA's regional haze rule, and EPA's December 2000 determination to regulate mercury emissions from power plants. In addition,
LG&E is currently working with local regulatory authorities to review the effectiveness of remedial measures aimed at controlling particulate matter emissions from its Mill Creek Station. LG&E
previously settled a number
of property damage claims from adjacent residents and completed significant remedial measures as part of its ongoing capital construction program. LG&E is in the process of converting the Mill Creek
Station to wet stack operation in an effort to resolve all outstanding issues related to particulate matter emissions.

LG&E
owns or formerly owned three properties which are the location of past MGP operations. Various contaminants are typically found at such former MGP sites and environmental
remediation measures are frequently required. With respect to the sites, LG&E has completed cleanups, obtained regulatory approval of site management plans, or reached agreements for other parties to
assume responsibility for cleanup. Based on currently available information, 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 December 31, 2001 and 2000.

Purchased Power.LG&E has a contract for purchased power during 2002-2006 with OVEC for various MW capacities. The estimated
future minimum annual payments under purchased power agreements for the five years ended December 31, 2006, are as follows (in thousands of $):

2002

$
12,8052003


12,9342004


13,0632005


13,1932006


13,325Total

$
65,320


Note 13Jointly Owned Electric Utility Plant

LG&E owns a 75% undivided interest in Trimble County Unit 1 which the Kentucky Commission has allowed to be reflected in customer rates.

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

84

---

The
following data represent shares of the jointly owned property:

|                                               |  | Trimble County |        
|---------------------------------------------- |  | -------------- | -------
|
|Ownership interest                             |  |                | 75     
|Mw capacity                                    |  |                | 371.25 
|LG&E's 75% ownership (in thousands of $):      |  |                |        
|Cost                                           |  | $              | 560,381
|Accumulated depreciation                       |  |                | 170,875
|                                               |  |                |        
|Net book value                                 |  | $              | 389,506
|                                               |  |                |        
|Construction work in progress (included above) |  | $              | 12,842 

LG&E and KU jointly own the following combustion turbines ($ in thousands):

LG&E

KU

TOTALPaddy's Run 13

Ownership %


53
%

47
%

100
%Mw capacity


84


74


158Cost

$
33,844

$
29,908

$
63,752Depreciation


563


491


1,054Net book Value

$
33,281

$
29,417

$
62,698E.W. Brown 5

Ownership %


53
%

47
%

100
%Mw capacity


70


63


133Cost

$
23,941

$
21,078

$
45,019Depreciation


394


342


736Net book Value

$
23,547

$
20,736

$
44,283E.W. Brown 6

Ownership %


38
%

62
%

100
%Mw capacity


62


102


164Cost

$
23,696

$
36,253

$
59,949Depreciation


953


2,955


3,908Net book Value

$
22,743

$
33,298

$
56,041E.W. Brown 7

Ownership %


38
%

62
%

100
%Mw capacity


62


102


164Cost

$
23,607

$
44,785

$
68,392Depreciation


3,268


3,033


6,301Net book Value

$
20,339

$
41,752

$
62,091


See also Note 12, Construction Program, for LG&E's planned purchase of two jointly owned CTs in 2002.

Note 14Segments of Business and Related Information

Effective December 31, 1998, LG&E adopted SFAS No. 131,Disclosure About Segments of an Enterprise and Related
Information. LG&E is a regulated public utility engaged in the generation,

85

---

transmission, distribution, and sale of electricity and the storage, distribution, and sale of natural gas. Financial data for business segments, follow (in thousands of $):

Electric

Gas

Total2001Operating revenues

$
705,925
(a)
$
290,775

$
996,700Depreciation and amortization


85,572


14,784


100,356Interest income


616


132


748Interest expense


31,295


6,627


37,922Operating income taxes


55,527


7,925


63,452Net income


94,996


11,768


106,764Total assets


1,985,252


463,102


2,448,354Construction expenditures


227,107


25,851


252,9582000Operating revenues

$
710,958
(b)
$
272,489

$
983,447Depreciation and amortization


84,761


13,530


98,291Interest income


2,551


552


3,103Interest expense


35,604


7,614


43,218Operating income taxes


57,869


6,556


64,425Net income


100,395


10,178


110,573Total assets


1,760,305


465,779


2,226,084Construction expenditures


109,798


34,418


144,2161999Operating revenues

$
790,670
(c)
$
177,579

$
968,249Depreciation and amortization


83,619


13,602


97,221Interest income


3,435


651


4,086Interest expense


31,558


6,404


37,962Operating income taxes


56,883


891


57,774Net income


104,853


1,417


106,270Total assets


1,775,498


395,954


2,171,452Construction expenditures


160,844


33,800


194,644




Note 15Selected Quarterly Data (Unaudited)

Selected financial data for the four quarters of 2001 and 2000 are shown below. Because of seasonal fluctuations in temperature and other factors, results for
quarters may fluctuate throughout the year.

Quarters EndedMarch

June

September

December(Thousands of $)2001Operating revenues

$
313,271

$
228,841

$
231,885

$
222,703Net operating income (loss)


(43,732
)

37,624


49,092


98,789Net income (loss)


(54,115
)

28,467


40,270


92,159Net income (loss) available for common stock


(55,413
)

27,247


39,160


91,0482000Operating revenues

$
249,642

$
209,731

$
229,640

$
294,434Net operating income


26,592


37,285


48,161


36,832Net income


17,421


28,009


38,117


27,026Net income available for common stock


16,256


26,692


36,756


25,659


86

---

Note 16Subsequent Events

On April 9, 2001, a German power company, E.ON AG, announced a preconditional cash offer of £5.1 billion ($7.3 billion) for Powergen. The offer is
subject to a number of conditions, including the receipt of certain European and United States regulatory approvals. The Kentucky Public Service Commission, the Federal Energy Regulatory Commission,
the Virginia State Corporation Commission, and the Tennessee Regulatory Authority have all approved the acquisition of Powergen and LG&E Energy by E.ON. The parties expect to obtain the remaining
regulatory approvals and to complete the transaction in the first half of 2002. See Powergen's schedule 14D-9, and associated schedules to such filings, filed with the SEC on April 9, 2001.

LG&E
(along with KU) is a founding member of the MISO, such membership obtained in 1998 in response to and consistent with federal policy initiatives. As a MISO member, LG&E filed for
and received authorization from FERC to transfer control of its transmission facilities (100 kV and above) to the MISO, the first step in allowing the latter to assume responsibility for all
tariff-related transmission functions (e.g.,scheduling through and on LG&E's transmission system) as well as non-tariff related regional transmission
activities (e.g.,operations planning, maintenance coordination, long-term regional planning and market monitoring). The FERC approved the MISO as the
nation's first Regional Transmission Organization on December 19, 2001, after which LG&E submitted a filing at FERC to cancel all services under its Open Access Transmission Tariff except those that
will not be provided by the MISO (certain ancillary services). The MISO became operational on February 1, 2002.

In
October 2001, the FERC issued an order requiring that the bundled retail 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, including start-up capital (debt) costs. LG&E, along with several other transmission owners, opposed
the FERC's ruling in this regard, which opposition the FERC rejected in an order on rehearing issued in 2002. As of the end of 2001, negotiations were continuing between MISO, its transmission owners
and other interested industry segments regarding the level of cost responsibility properly borne by bundled and grandfathered load under these FERC rulings. Absent settlement, this issue is expected
to go to hearing in 2002.

At
the end of 2001, in response to an earlier FERC ruling, MISO and its transmission owning members (including LG&E) filed to increase MISO's rate of return on equity from 10.5% (a
stipulated percentage agreed to in 1998) to 13.0%, to compensate MISO's transmission owners for the inherent risks and uncertainties associated with transferring control of their facilities to the
MISO. This issue is expected to go to hearing in 2002.

87

---



Louisville Gas and Electric Company  Report of Management

The management of Louisville Gas and Electric Company is responsible for the preparation and integrity of the financial statements and related information
included in this Annual Report. These statements have been prepared in accordance with accounting principles generally accepted in the United States applied on a consistent basis and, necessarily,
include amounts that reflect the best estimates and judgment of management.

LG&E's
current year financial statements have been audited by PricewaterhouseCoopers LLP, independent accountants, and prior years financial statements were audited by Arthur Andersen
LLP. Management made available to PricewaterhouseCoopers LLP and Arthur Andersen LLP (in prior years) all LG&E's financial records and related data as well as the minutes of shareholders' and
directors' meetings.

Management
has established and maintains a system of internal controls that provides reasonable assurance that transactions are completed in accordance with management's authorization,
that assets are safeguarded and that financial statements are prepared in conformity with generally accepted accounting principles. Management believes that an adequate system of internal controls is
maintained through the selection and training of personnel, appropriate division of responsibility, establishment and communication of policies and procedures and by regular reviews of internal
accounting controls by LG&E's internal auditors. Management reviews and modifies its system of internal controls in light of changes in conditions and operations, as well as in response to
recommendations from the internal auditors. These recommendations for the year ended December 31, 2001, did not identify any material weaknesses in the design and operation of LG&E's internal control
structure.

The
Audit Committee of the Board of Directors is composed entirely of outside directors. In carrying out its oversight role for the financial reporting and internal controls of LG&E, the
Audit Committee meets regularly with LG&E's independent public accountants, internal auditors and management. The Audit Committee reviews the results of the independent accountants' audit of the
financial statements and their audit procedures, and discusses the adequacy of internal accounting controls. The Audit Committee also approves the annual internal auditing program and reviews the
activities and results of the internal auditing function. Both the independent public accountants and the internal auditors have access to the Audit Committee at any time.

Louisville
Gas and Electric Company maintains and internally 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 of proprietary information.

S.
Bradford Rives
Senior Vice President-Finance and Controller

Louisville
Gas and Electric Company
Louisville, Kentucky

88

---

Louisville Gas and Electric Company and Subsidiary  Report of Independent Accountants

To
the Shareholders of Louisville Gas and Electric Company and Subsidiary:

In
our opinion, the accompanying consolidated balance sheet as of December 31, 2001 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 Electric Company and Subsidiary (the "Company"), a wholly-owned subsidiary of LG&E Energy
Corp., at December 31, 2001, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of
America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our
audit of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance
about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable
basis for our opinion.

/s/
PricewaterhouseCoopers LLP
January 25, 2002
Louisville, Kentucky

89

---

Louisville Gas and Electric Company  Report of Independent Public Accountants

To
the Shareholders of Louisville Gas and Electric Company:

We
have audited the accompanying balance sheet and statement of capitalization of Louisville Gas and Electric Company (a Kentucky corporation and a wholly-owned subsidiary of LG&E Energy
Corp.) as of December 31, 2000, and the related statements of income, retained earnings, cash flows and comprehensive income for each of the two years in the period ended December 31, 2000. These
financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We
conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for our opinion.

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

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

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

90

---



INDEX OF ABBREVIATIONS

Capital Corp.

LG&E Capital Corp.Clean Air Act

The Clean Air Act, as amended in 1990CCN

Certificate of Public Convenience and NecessityCT

Combustion TurbinesDSM

Demand Side ManagementECR

Environmental Cost RecoveryEEI

Electric Energy, Inc.EITF

Emerging Issues Task Force IssueEPA

U.S. Environmental Protection AgencyESM

Earnings Sharing MechanismFAC

Fuel Adjustment ClauseFERC

Federal Energy Regulatory CommissionFPA

Federal Power ActFT and FT-A

Firm TransportationGSC

Gas Supply ClauseHolding Company Act

Public Utility Holding Company Act of 1935IBEW

International Brotherhood of Electrical WorkersIMEA

Illinois Municipal Electric AgencyIMPA

Indiana Municipal Power AgencyKentucky Commission

Kentucky Public Service CommissionKIUC

Kentucky Industrial Utility Consumers, Inc.KU

Kentucky Utilities CompanyKU Energy

KU Energy CorporationKU R

KU Receivables LLCKva

Kilovolt-ampereLEM

LG&E Energy Marketing Inc.LG&E

Louisville Gas and Electric CompanyLG&E Energy

LG&E Energy Corp.LG&E R

LG&E Receivables LLCLG&E Services

LG&E Energy Services Inc.Mcf

Thousand Cubic FeetMerger Agreement

Agreement and Plan of Merger dated May 20, 1997MGP

Manufactured Gas PlantMISO

Midwest Independent System OperatorMmbtu

Million British thermal unitsMoody's

Moody's Investor Services, Inc.Mw

MegawattsMwh

Megawatt hoursNNS

No-Notice ServiceNOx

Nitrogen OxideOMU

Owensboro Municipal UtilitiesOVEC

Ohio Valley Electric CorporationPBR

Performance-Based RatemakingPowergen

Powergen plcPUHCA

Public Utility Holding Company Act of 1935


91

---

S&P

Standard & Poor's Rating ServicesSCR

Selective Catalytic ReductionSEC

Securities And Exchange CommissionSERP

Supplemental Employee Retirement PlanSFAS

Statement of Financial Accounting StandardsSIP

State Implementation PlanSO2

Sulfur DioxideTennessee Gas

Tennessee Gas Pipeline CompanyTexas Gas

Texas Gas Transmission CorporationTRA

Tennessee Regulatory AuthorityTrimble County

LG&E's Trimble County Unit 1USWA

United Steelworkers of AmericaUtility Operations

Operations of LG&E and KUVDT

Value Delivery Team ProcessVirginia Commission

Virginia State Corporation CommissionVirginia Staff

Virginia Commission Staff


92

---



Kentucky Utilities Company and Subsidiary  Consolidated Statements of Income  (Thousands of $)

|                                                                                                                                        |                                         | Years Ended December 31  |        
|--------------------------------------------------------------------------------------------------------------------------------------- | --------------------------------------- | ------------------------ | -------
|
|OPERATING REVENUES:                                                                                                                     |                                         |                          |        
|                                                                                                                                        | Electric (Note 1)                       |                          | $      
|                                                                                                                                        | Provision for rate refunds (Note 3)     |                          |        
|                                                                                                                                        |                                         |                          |        
|                                                                                                                                        |                                         | Total operating revenues |        
|                                                                                                                                        |                                         |                          |        
|OPERATING EXPENSES:                                                                                                                     |                                         |                          |        
|                                                                                                                                        | Fuel for electric generation            |                          |        
|                                                                                                                                        | Power purchased                         |                          |        
|                                                                                                                                        | Other operation expenses                |                          |        
|                                                                                                                                        | Non-recurring charge (Note 3)           |                          |        
|                                                                                                                                        | Maintenance                             |                          |        
|                                                                                                                                        | Depreciation and amortization (Note 1)  |                          |        
|                                                                                                                                        | Federal and state income taxes (Note 7) |                          |        
|                                                                                                                                        | Property and other taxes                |                          |        
|                                                                                                                                        |                                         |                          |        
|                                                                                                                                        |                                         | Total operating expenses |        
|                                                                                                                                        |                                         |                          |        
|Net operating income                                                                                                                    |                                         |                          | 121,370
|Other income  net (Note 8)                                                                                                             |                                         |                          | 8,932  
|Interest charges                                                                                                                        |                                         |                          | 34,024 
|                                                                                                                                        |                                         |                          |        
|Net income before cumulative effect of a change in accounting principle                                                                 |                                         |                          | 96,278 
|Cumulative effect of a change in accounting principle-accounting for Derivative instruments and hedging activities, net of tax (Note 1) |                                         |                          | 136    
|                                                                                                                                        |                                         |                          |        
|Net income                                                                                                                              |                                         |                          | 96,414 
|Preferred stock dividends                                                                                                               |                                         |                          | 2,256  
|                                                                                                                                        |                                         |                          |        
|Net income available for common stockholders                                                                                            |                                         | $                        | 94,158 
|                                                                                                                                        |                                         |                          |        

Consolidated Statements of Retained Earnings  (Thousands of $)

|                  |  | Years Ended December 31
|----------------- |  | -----------------------
|
|Balance January 1 |  | $                      
|Add net income    |  |                        
|                  |  |                        
|                  |  |                        
|                  |  |                        

|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 |         |  | 73,999
|                    |  |                                   |         |  |        |         |  |       
|                    |  |                                   |         |  | 32,756 |         |  | 77,756 |         |  | 76,255
|                    |  |                                   |         |  |        |         |  |       
|Balance December 31 |  | $                                 | 410,896 |  | $      | 347,238 |  | $      | 329,470
|                    |  |                                   |         |  |        |         |  |       

93

---

The
accompanying notes are an integral part of these consolidated financial statements.

94

---

Kentucky Utilities Company and Subsidiary  Consolidated Statements of Comprehensive Income  (Thousands of $)

|                                                                                                                            |  | Years Ended December 31
|--------------------------------------------------------------------------------------------------------------------------- |  | -----------------------
|
|Net income                                                                                                                  |  | $                      
|Cumulative effect of change in accounting principle  Accounting for derivative instruments and hedging activities (Note 1) |  |                        
|Income tax expense related to items of other comprehensive income                                                           |  |                        
|                                                                                                                            |  |                        
|Comprehensive income                                                                                                        |  | $                      
|                                                                                                                            |  |                        

The
accompanying notes are an integral part of these consolidated financial statements.



|                                                   |                                                                  | December 31              
|-------------------------------------------------- | ---------------------------------------------------------------- | -------------------------
|
|ASSETS:                                            |                                                                  |                          
|Utility plant, at original cost (Note 1)           |                                                                  | $                        
|Less: reserve for depreciation                     |                                                                  |                          
|                                                   |                                                                  |                          
|                                                   |                                                                  |                          
|Construction work in progress                      |                                                                  |                          
|                                                   |                                                                  |                          
|                                                   |                                                                  |                          
|                                                   |                                                                  |                          
|Other property and investmentsless reserve        |                                                                  |                          
|                                                   |                                                                  |                          
|Current assets:                                    |                                                                  |                          
|                                                   | Cash and temporary cash investments                              |                          
|                                                   | Accounts receivable-less reserve of $800 in 2001 and 2000        |                          
|                                                   | Materials and suppliesat average cost:                          |                          
|                                                   |                                                                  | Fuel (predominantly coal)
|                                                   |                                                                  | Other                    
|                                                   | Prepayments and other                                            |                          
|                                                   |                                                                  |                          
|                                                   |                                                                  |                          
|                                                   |                                                                  |                          
|Deferred debits and other assets:                  |                                                                  |                          
|                                                   | Unamortized debt expense (Note 1)                                |                          
|                                                   | Regulatory assets (Note 3)                                       |                          
|                                                   | Other                                                            |                          
|                                                   |                                                                  |                          
|                                                   |                                                                  |                          
|                                                   |                                                                  |                          
|                                                   |                                                                  | $                        
|                                                   |                                                                  |                          
|CAPITAL AND LIABILITIES:                           |                                                                  |                          
|Capitalization (see statements of capitalization): |                                                                  |                          
|                                                   | Common equity                                                    |                          
|                                                   | Cumulative preferred stock                                       |                          
|                                                   | Long-term debt (Note 9)                                          |                          
|                                                   |                                                                  |                          
|                                                   |                                                                  |                          
|                                                   |                                                                  |                          
|Current liabilities:                               |                                                                  |                          
|                                                   | Current portion of long-term debt (Note 9)                       |                          
|                                                   | Notes payable to parent (Note 10)                                |                          
|                                                   | Accounts payable                                                 |                          
|                                                   | Accrued taxes                                                    |                          
|                                                   | Accrued interest                                                 |                          
|                                                   | Other                                                            |                          
|                                                   |                                                                  |                          
|                                                   |                                                                  |                          
|                                                   |                                                                  |                          
|Deferred credits and other liabilities:            |                                                                  |                          
|                                                   | Accumulated deferred income taxes (Notes 1 and 7)                |                          
|                                                   | Investment tax credit, in process of amortization                |                          
|                                                   | Accumulated provision for pensions and related benefits (Note 6) |                          
|                                                   | Customers' advances for construction                             |                          
|                                                   | Regulatory liabilities (Note 3)                                  |                          
|                                                   | Other                                                            |                          
|                                                   |                                                                  |                          
|                                                   |                                                                  |                          
|                                                   |                                                                  |                          
|Commitments and contingencies (Note 11)            |                                                                  |                          
|                                                   |                                                                  | $                        
|                                                   |                                                                  |                          

The accompanying notes are an integral part of these consolidated financial statements.

97

---



Kentucky Utilities Company and Subsidiary  Consolidated Statements of Cash Flows  (Thousands of $)

|                                                         |                                                       | Years Ended December 31                      |      
|-------------------------------------------------------- | ----------------------------------------------------- | -------------------------------------------- | -----
|
|CASH FLOWS FROM OPERATING ACTIVITIES:                    |                                                       |                                              |      
|                                                         | Net income                                            |                                              | $    
|                                                         | Items not requiring cash currently:                   |                                              |      
|                                                         |                                                       | Depreciation and amortization                |      
|                                                         |                                                       | Deferred income taxesnet                    |      
|                                                         |                                                       | Investment tax creditnet                    |      
|                                                         |                                                       | Other                                        |      
|                                                         | Change in certain net current assets and liabilities: |                                              |      
|                                                         |                                                       | Accounts receivable                          |      
|                                                         |                                                       | Materials and supplies                       |      
|                                                         |                                                       | Accounts payable                             |      
|                                                         |                                                       | Provision for rate refunds                   |      
|                                                         |                                                       | Accrued taxes                                |      
|                                                         |                                                       | Accrued interest                             |      
|                                                         |                                                       | Prepayments and other                        |      
|                                                         | Sale of accounts receivable (Note 1)                  |                                              |      
|                                                         | Other                                                 |                                              |      
|                                                         |                                                       |                                              |      
|                                                         |                                                       | Net cash flows from operating activities     |      
|                                                         |                                                       |                                              |      
|CASH FLOWS FROM INVESTING ACTIVITIES:                    |                                                       |                                              |      
|                                                         | Proceeds from sales of securities                     |                                              |      
|                                                         | Construction expenditures                             |                                              |      
|                                                         |                                                       |                                              |      
|                                                         |                                                       | Net cash flows used for investing activities |      
|                                                         |                                                       |                                              |      
|CASH FLOWS FROM FINANCING ACTIVITIES:                    |                                                       |                                              |      
|                                                         | Short-term borrowings and repayments                  |                                              |      
|                                                         | Retirement of long-term debt                          |                                              |      
|                                                         | Issuance of long-term debt                            |                                              |      
|                                                         | Additional paid-in capital                            |                                              |      
|                                                         | Payment of dividends                                  |                                              |      
|                                                         |                                                       |                                              |      
|                                                         |                                                       | Net cash flows used for financing activities |      
|                                                         |                                                       |                                              |      
|Change in cash and temporary cash investments            |                                                       |                                              | 2,981
|Cash and temporary cash investments at beginning of year |                                                       |                                              | 314  
|                                                         |                                                       |                                              |      
|Cash and temporary cash investments at end of year       |                                                       | $                                            | 3,295
|                                                         |                                                       |                                              |      
|Supplemental disclosures of cash flow information:       |                                                       |                                              |      
|                                                         | Cash paid during the year for:                        |                                              |      
|                                                         |                                                       | Income taxes                                 |      
|                                                         |                                                       | Interest on borrowed money                   |      

The
accompanying notes are an integral part of these consolidated financial statements.

98

---

Kentucky Utilities Company and Subsidiary
Consolidated Statements of Capitalization
(Thousands of $)

|               |                                        | December 31                   |        
|-------------- | -------------------------------------- | ----------------------------- | -------
|
|COMMON EQUITY: |                                        |                               |        
|               | Common stock, without par value       |                               |        
|               |                                        | outstanding 37,817,878 shares |        
|               | Additional paid-in-capital             |                               |        
|               | Retained earnings                      |                               |        
|               | Accumulated other comprehensive income |                               |        
|               | Other                                  |                               |        
|               |                                        |                               |        
|               |                                        |                               | 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 |       
|                                                  |                                                     | 6.53% series, $100 stated value            |                                    | 200,000                  |         | Not redeemable |         |       
|                                                  |                                                     |                                            |                                    |                          |         |                |         |       
|                                                  |                                                     |                                            |                                    |                          |         |                | 40,000  |       
|                                                  |                                                     |                                            |                                    |                          |         |                |         |       
|LONG-TERM DEBTfirst mortgage
    bonds (Note 9): |                                                     |                                            |                                    |                          |         |                |         |       
|                                                  | Q due June 15, 2003, 6.32%                          |                                            |                                    |                          |         |                |         | 62,000
|                                                  | S due January 15, 2006, 5.99%                       |                                            |                                    |                          |         |                |         | 36,000
|                                                  | P due May 15, 2007, 7.92%                           |                                            |                                    |                          |         |                |         | 53,000
|                                                  | R due June 1, 2025, 7.55%                           |                                            |                                    |                          |         |                |         | 50,000
|                                                  | P due May 15, 2027, 8.55%                           |                                            |                                    |                          |         |                |         | 33,000
|                                                  | Pollution control series:                           |                                            |                                    |                          |         |                |         |       
|                                                  |                                                     | 1B due February 1, 2018, 6.25%             |                                    |                          |         |                |         |       
|                                                  |                                                     | 2B due February 1, 2018, 6.25%             |                                    |                          |         |                |         |       
|                                                  |                                                     | 3B due February 1, 2018, 6.25%             |                                    |                          |         |                |         |       
|                                                  |                                                     | 4B due February 1, 2018, 6.25%             |                                    |                          |         |                |         |       
|                                                  |                                                     | 8, due September 15, 2016, 7.45%           |                                    |                          |         |                |         |       
|                                                  |                                                     | 9, due December 1, 2023, 5.75%             |                                    |                          |         |                |         |       
|                                                  |                                                     | 10, due November 1, 2024, variable         |                                    |                          |         |                |         |       
|                                                  |                                                     | A, due May 1, 2023, variable               |                                    |                          |         |                |         |       
|                                                  | Long-term debt marked to market
    (Note 4)        |                                            |                                    |                          |         |                |         | 3,676 
|                                                  |                                                     |                                            |                                    |                          |         |                |         |       
|                                                  |                                                     | Total bonds outstanding                    |                                    |                          |         |                |         |       
|                                                  |                                                     | Less current portion of long-term
    debt |                                    |                          |         |                |         |       
|                                                  |                                                     |                                            |                                    |                          |         |                |         |       
|                                                  |                                                     | Long-term debt                             |                                    |                          |         |                |         |       
|                                                  |                                                     |                                            |                                    |                          |         |                |         |       
|                                                  |                                                     | Total capitalization                       |                                    |                          |         |                |         | $     
|                                                  |                                                     |                                            |                                    |                          |         |                |         |       

The
accompanying notes are an integral part of these consolidated financial statements.

99

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Kentucky Utilities Company and Subsidiary  Notes to Consolidated Financial Statements

Note 1Summary of Significant Accounting Policies

KU, a subsidiary of LG&E Energy and an indirect subsidiary of Powergen, is a regulated public utility engaged in the generation, transmission, distribution, and
sale of electric energy. LG&E Energy is an exempt public utility holding company with wholly owned subsidiaries including LG&E, KU, Capital Corp., LEM, and LG&E Services. All of the KU's Common Stock
is held by LG&E Energy. KU has one wholly owned consolidated subsidiary, KU Receivables.

On
December 11, 2000, LG&E Energy Corp. was acquired by Powergen plc. Powergen is a registered public utility holding company under PUHCA. No costs associated with the Powergen
acquisition nor any of the effects of purchase accounting have been reflected in the financial statements of KU.

Certain
reclassification entries have been made to the previous year financial statements to conform to the 2001 presentation with no impact on the balance sheet totals or previously
reported income.

Cash and Temporary Cash Investments.KU considers all highly liquid debt instruments purchased with a maturity of three
months or less to be cash equivalents. Temporary cash investments are carried at cost, which approximates fair value.

Utility Plant.KU's utility plant is stated at original cost, which includes payroll-related costs such as taxes, fringe
benefits, and administrative and general costs. Construction work in progress has been included in the rate base for determining retail customer rates. KU has not recorded any significant allowance
for funds used during construction.

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

Depreciation and amortization.Depreciation is provided on the straight-line method over the estimated service lives of
depreciable plant. Pursuant to a final order of the Kentucky Commission dated December 3, 2001, KU implemented new deprecation rates effective January 1, 2001. The amounts provided for KU approximated
3.1% in 2001, 3.5% in 2000 and 1999.

Financial Instruments.KU uses over-the-counter interest-rate swap agreements to hedge its exposure to interest rates. Gains
and losses on interest-rate swaps used to hedge interest rate risk are reflected in interest charges monthly. See Note 4Financial Instruments.

Debt Expense.Debt expense is capitalized in deferred debits and amortized over the lives of the related bond issues,
consistent with regulatory practices.

Deferred Income Taxes.Deferred income taxes have been provided for all material book-tax temporary differences.

Investment Tax Credits.Investment tax credits resulted from provisions of the tax law that permitted a reduction of KU's tax
liability based on credits for certain construction expenditures. Deferred investment tax credits are being amortized to income over the estimated lives of the related property that gave rise to the
credits.

Revenue Recognition.Revenues are recorded based on service rendered to customers through month-end. KU accrues an estimate
for unbilled revenues from each meter reading date to the end of

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the accounting period. The unbilled revenue estimates included in accounts receivable for KU equaled approximately $33.4 million and $34.8 million at December 31, 2001, and 2000, respectively.

KU
recorded electric revenues that resulted from sales to a related party, LG&E, of $31.1 million, $22.1 million and 22.4 million for years ended December 31, 2001, 2000 and 1999,
respectively.

Fuel Costs.The cost of fuel for electric generation is charged to expense as used.

Management's Use of Estimates.The preparation of financial statements in conformity with generally accepted accounting
principles requires management to make estimates and assumptions that affect the reported assets and liabilities and disclosure of contingent items at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. See Note 11, Commitments and Contingencies, for a further discussion.

Accounts Receivable Securitization.SFAS No. 140,Accounting for Transfers and Servicing of Financial
Assets and Extinguishments of Liabilities, revises the standards for accounting for securitizations and other transfers of financial assets and collateral and requires certain
disclosures, and provides accounting and reporting standards for transfers and servicing of financial assets and extinguishments of liabilities. SFAS No. 140 was adopted in the first quarter of 2001,
when KU entered into an accounts receivable securitization transaction.

On
February 6, 2001, KU implemented an accounts receivable securitization program. The purpose of this program is to enable KU to accelerate the receipt of cash from the collection of
retail accounts receivable, thereby reducing dependence upon more costly sources of working capital. The securitization program allows for a percentage of eligible receivables to be sold. Eligible
receivables are generally all receivables associated with retail sales that have standard terms and are not past due. KU is able to terminate this program at any time without penalty. If there is a
significant deterioration in the payment record of the receivables by the retail customers or if KU fails to meet certain covenants regarding the program, the program may terminate at the election of
the financial institutions. In this case, payments from retail customers would first be used to repay the financial institutions participating in the program, and would then be available for use by
KU.

As
part of the program, KU sold retail accounts receivables to a wholly owned subsidiary KU R. Simultaneously, KU R entered into two separate three-year accounts receivable
securitization facilities with two financial institutions and their affiliates whereby KU R can sell, on a revolving basis, an undivided interest in certain of their receivables and receive up to $50
million from an unrelated third party purchaser. The effective cost of the receivables programs is comparable to KU's lowest cost source of capital, and is based on prime rated commercial paper. KU
retains servicing rights of the sold receivables through two separate servicing agreements with the third party purchaser. KU has obtained an opinion from independent legal counsel indicating these
transactions qualify as a true sale of receivables. As of December 31, 2001, the outstanding program balance was $45.1 million.

Management
expects to renew these facilities when they expire.

The
allowance for doubtful accounts associated with the eligible securitized receivables was $520,000 at December 31, 2001. This allowance is based on historical experience of KU. Each
securitization facility contains a fully funded reserve for uncollectible receivables.

New Accounting Pronouncements.During 2001 and 2000, the following accounting pronouncements were issued that affect KU:

SFAS
No. 133,Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138,Accounting for
Certain Derivative Instruments and Certain Hedging Activities, establishes accounting and reporting standards requiring that every derivative instrument (including certain
derivative instruments

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embedded in other contracts) be recorded on the balance sheet as either an asset or a liability measured at its fair value. SFAS No. 133 requires that changes in the derivative's fair value be
recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the
hedged item in the income statement, and requires that KU must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. SFAS No. 133 could increase the
volatility in earnings and other comprehensive income. SFAS No. 137,Accounting for Derivative Instruments and Hedging ActivitiesDeferral of the Effective Date of
SFAS No. 133, deferred the effective date of SFAS No. 133 until January 1, 2001. KU adopted SFAS No. 133 and SFAS No. 138 on January 1, 2001. The effect of
adopting these statements resulted in a $1.6 million increase in other comprehensive income from a cumulative effect of change in accounting principle (net of tax of $1.1 million).

The
Financial Accounting Standards Board created the Derivatives Implementation Group (DIG) to provide guidance for implementation of SFAS No. 133. DIG Issue C15,
Normal Purchases and Normal Sales Exception for Option Type Contracts and Forward Contracts in Electricitywas adopted in 2001 and had no impact on results of operations and
financial position. DIG Issue C16,Applying the Normal Purchases and Normal Sales Exception to Contracts that Combine a Forward Contract and a Purchased Option
Contract, was cleared in 2001 and stated that option contracts do not meet the normal purchases and normal sales exception and should follow SFAS No. 133. DIG C16 will be
effective in the second quarter of 2002. Management has not determined the impact this issue will have on its results of operations and financial position.

SFAS
No. 141,Business Combinationsand SFAS No. 142,Goodwill and Other Intangible Assetswere issued in 2001. SFAS No. 141 requires all business combinations initiated after June 30, 2001, to be accounted for using the purchase method. SFAS No. 142 requires goodwill to be recorded, but
not amortized. Further, goodwill will now be subject to a periodic assessment for impairment. The provisions of these new pronouncements were effective July 1, 2001, for KU. The adoption of these
standards did not have a material impact on the results of operations or financial position of KU.

SFAS
No. 143,Accounting for Asset Retirement Obligationsand. SFAS No. 144,Accounting for the Impairment
or Disposal of Long-Lived Assets, was issued in 2001. SFAS No. 143 establishes accounting and reporting standards for obligations associated with the retirement of tangible
long-lived assets and the associated asset retirement costs. SFAS No. 144 supersedes SFAS No. 121,Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Ofand the accounting and reporting provisions of APB Opinion No. 30,Reporting the Results of OperationsReporting
the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions.SFAS No. 144, among other provisions,
eliminates the requirement of SFAS No. 121 to
allocate goodwill to long-lived assets to be tested for impairment. The effective implementation date for SFAS No. 144 is 2002 and SFAS No. 143 is 2003. Based on current regulatory practices,
management does not expect SFAS No. 143 or SFAS No. 144 to have a material impact on KU's financial position or results of operations.

Note 2Mergers and Acquisitions

On December 11, 2000, LG&E Energy Corp. was acquired by Powergen plc. for cash of approximately $3.2 billion or $24.85 per share and the assumption of all of LG&E
Energy's debt. As a result of the acquisition, LG&E Energy became a wholly owned subsidiary of Powergen and, as a result, KU became an indirect subsidiary of Powergen. KU has continued its separate
identity and serves customers in Kentucky and Virginia under its existing name. The preferred stock and debt securities of KU were not affected by this transaction resulting in the utility operations'
obligation to continue to file SEC reports. Following the acquisition, Powergen became a registered holding company under PUHCA and KU, as a subsidiary of a registered holding company, became subject
to additional regulations under PUHCA.

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LG&E
Energy and KU Energy merged on May 4, 1998, with LG&E Energy as the surviving corporation. As a result of the merger, LG&E Energy, which is the parent of LG&E, became the parent
company of KU. The operating utility subsidiaries (LG&E and KU) have continued to maintain their separate corporate identities and serve customers in Kentucky and Virginia under their present names.
LG&E Energy estimated non-fuel savings over a ten-year period following the merger. Costs to achieve these savings for KU of $42.3 million were recorded in the second quarter of 1998, $20.5 million of
which were initially deferred and are being amortized over a five-year period pursuant to regulatory orders. Primary components of the merger costs were separation benefits, relocation costs, and
transaction fees, the majority of which were paid by December 31, 1998. KU expensed the remaining costs associated with the merger ($21.8 million) at the time of the merger in the second quarter of
1998. In regulatory filings associated with approval of the merger, KU committed not to seek increases in existing base rates and proposed reductions in their retail customers' bills in amounts based
on one-half of the savings, net of the deferred and amortized amount, over a five-year period. The preferred stock and debt securities of KU were not affected by the merger.

Management
has accounted for the KU/LG&E merger as a pooling of interests and as a tax-free reorganization under the Internal Revenue Code.

As
part of its merger order, the Kentucky Commission approved a surcredit whereby 50% of the net non-fuel cost savings estimated to be achieved from the merger, less $38.6 million or 50%
of the originally estimated costs to achieve such savings, be applied to reduce customer rates through a surcredit on customers' bills and the remaining 50% be retained by the companies. The surcredit
is allocated 53% to KU and 47% to LG&E pursuant to Kentucky Commission order. The surcredit will be about 2% of customer bills through mid 2003 and will amount to approximately $63 million in net
non-fuel savings to KU. Any fuel cost savings are passed to Kentucky customers through the companies' fuel adjustment clauses. See Note 3 for more information about KU's rates and regulatory matters.

Note 3Utility Rates and Regulatory Matters

Accounting for the regulated utility business conforms with generally accepted accounting principles as applied to regulated public utilities and as prescribed by
FERC, the Kentucky Commission and the Virginia Commission. KU is subject to SFAS No. 71,Accounting for the Effects of Certain Types of Regulation,
under which certain costs that would otherwise be charged to expense are deferred as regulatory assets based on expected recovery from customers in future rates. Likewise, certain credits that would
otherwise be reflected as income are deferred as regulatory liabilities based on expected return to customers in future rates. KU's current or expected recovery of deferred costs and expected return
of deferred credits is generally based on specific ratemaking decisions or precedent for each

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item. The following regulatory assets and liabilities were included in KU's balance sheets as of December 31 (in thousands of $):

|                                    |  | 2001 |         | 2000 |  
|----------------------------------- |  | ---- | ------- | ---- | -
|VDT costs                           |  | $    | 48,811  |      | $
|Unamortized loss on bonds           |  |      | 6,142   |      |  
|LG&E/KU merger costs                |  |      | 6,139   |      |  
|One utility costs                   |  |      | 4,365   |      |  
|Other                               |  |      | 1,010   |      |  
|                                    |  |      |         |      |  
|Total regulatory assets             |  |      | 66,467  |      |  
|                                    |  |      |         |      |  
|Deferred income taxesnet           |  |      | (32,872 | )    |  
|Other                               |  |      | (1,017  | )    |  
|                                    |  |      |         |      |  
|Total regulatory liabilities        |  |      | (33,889 | )    |  
|                                    |  |      |         |      |  
|Regulatory assets/(liabilities)net |  | $    | 32,578  |      | $
|                                    |  |      |         |      |  

Kentucky Commission Settlement OrderValue Delivery Costs.During the first quarter 2001, KU recorded a $64
million charge for a workforce reduction program. Primary components of the charge were separation benefits, enhanced early retirement benefits, and health care benefits. The result of this workforce
reduction was the elimination of over 300 positions, accomplished primarily through a voluntary enhanced severance program.

On
June 1, 2001, KU filed an application (VDT case) with the Kentucky Commission to create a regulatory asset relating to these first quarter 2001 charges. The application requested
permission to amortize these costs over a four-year period. The Kentucky Commission also opened a case to review the new depreciation study and resulting depreciation rates implemented in 2001.

KU
reached a settlement in the VDT case as well as the other cases involving depreciation rates and ESM with all intervening parties. The settlement agreement was approved by the
Kentucky Commission on December 3, 2001.

The
Kentucky Commission December 3, 2001, order allowed KU to set up a regulatory asset of $54 million for the workforce reduction costs and begin amortizing these costs over a five year
period starting in April 2001. The first quarter charge of $64 million represented all employees who had accepted a voluntary enhanced severance program. Some employees rescinded their participation
in the voluntary enhanced severance program and, along with the non-recurring charge of $6.9 million for FERC and Virginia jurisdictions, thereby decreasing the original charge from $64 million to $54
million. The settlement will also reduce revenues approximately $11 million through a surcredit on future bills to customers over the same five year period. The surcredit represents net savings
stipulated by KU. The agreement also established KU's new depreciation rates in effect December 2001, retroactive to January 1, 2001. The new depreciation rates decreased depreciation expense by $6.0
million in 2001.

PUHCA.Following the purchase of LG&E Energy by Powergen, Powergen became a registered holding company under PUHCA. As a
result, Powergen, its utility subsidiaries, including KU, and certain of its non-utility subsidiaries are subject to extensive regulation by the SEC under PUHCA with respect to issuances and sales of
securities, acquisitions and sales of certain utility properties, and intra-system sales of certain goods and services. In addition, PUHCA generally limits the ability of registered holding companies
to acquire additional public utility systems and to acquire and retain businesses
unrelated to the utility operations of the holding company. Powergen believes that it has adequate authority (including financing authority) under existing SEC orders and regulations for it and its
subsidiaries to conduct their businesses and will seek additional authorization when necessary.

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Environmental Cost Recovery.In June 2000, the Kentucky Commission approved KU's application for a CCN to construct up to
four SCR NOx reduction facilities. The construction and subsequent operation of the SCRs is intended to reduce NOx emission levels to meet the EPA's mandated NOx emission level of 0.15 lbs./ Mmbtu by
May 2004. In its order, the Kentucky Commission 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 application with the Kentucky Commission to amend its Environmental Compliance Plan to reflect the addition of the proposed NOx reduction technology projects and to amend its
Environmental Cost Recovery Tariff to include an overall rate of return on capital investments. Following the completion of hearings in March 2001, a ruling was issued in April 2001 granting KU's
application. Such approval has allowed KU to begin to recover the costs associated with these new projects, subject to Kentucky Commission oversight during normal six-month and two-year reviews.

ESM.KU's electric rates are subject to an ESM. The ESM, in place for three years beginning 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 of 10.5% to 12.5%, no action is necessary. If earnings are above the upper limit, then
excess earnings are shared 40% with ratepayers and 60% with shareholders; if earnings are below the lower limit, then earnings deficiency is recovered 40% from ratepayers and 60% from shareholders.
The first ESM filing was made on March 1, 2001, for year ended December 31, 2000. By order of the Kentucky Commission, rate changes prompted by the ESM filing go into effect in April of each year. KU
estimated that the rate of return will fall within the deadband range, subject to Kentucky Commission approval, for the year ended December 31, 2001; therefore, no adjustment to the financial
statements was made.

DSM.In May 2001, the Kentucky Commission approved a plan that would expand LG&E's current DSM programs into the service
territory served by KU. The filing includes a rate mechanism that provides for concurrent recovery of DSM costs, provides an incentive for implementing DSM programs, and recovers revenues from lost
sales associated with the DSM program.

FAC.Prior to implementation of the PBR in July 1999, and following its termination in March 2000, KU employed an FAC
mechanism, which under Kentucky law allowed the utilities to recover from customers the actual fuel costs associated with retail electric sales.

In
July 1999, the Kentucky Commission issued a series of orders requiring KU to refund approximately $10.1 million resulting from reviews of the FAC from November 1994 to October 1998.
The orders changed KU's method of computing fuel costs associated with electric line losses on off-system sales
appropriate for recovery through the FAC, and KU's method for computing system line losses for the purpose of calculating the system sales component of the FAC charge. At KU's request, in July 1999,
the Kentucky Commission stayed the refund requirement pending the Kentucky Commission's final determination of any rehearing request that KU may file. In August 1999, KU filed its request for
rehearing of the July orders.

In
August 1999, the Kentucky Commission issued a final order in the KU proceedings, agreeing, in part, with KU's arguments outlined in its petition for rehearing. While the Kentucky
Commission confirmed that KU should change its method of computing the fuel costs associated with electric line losses, it agreed with KU that the line loss percentage should be based on KU's actual
line losses incurred in making wholesale sales rather than the percentage used in its Open Access Transmission Tariff. The Kentucky Commission also upheld its previous ruling concerning the
computation of system line losses in the calculation of the FAC. The net effect of the Kentucky Commission's final order was to reduce the refund obligation to $6.7 million ($5.8 million on Kentucky
jurisdictional basis) from the original order amount of $10.1 million. In August 1999, KU recorded its estimated share of anticipated FAC refunds. KU began implementing the refund in October and
completed the refund in September 2000. Both KU and the KIUC appealed the order to the Franklin Circuit Court. In October 2000, the

105

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Court affirmed the Kentucky Commission's orders concerning all issues except interest, with respect to which it held that KU will be required to pay interest on the amount disallowed "if the
Commission within its discretion so determines", and ordered the case be remanded to the Kentucky Commission on that issue. In November 2000, KU appealed the Circuit Court's decision to the Kentucky
Court of Appeals. Pending a decision on this appeal, a comprehensive settlement was reached by all parties, which settlement was filed with the Kentucky Commission on December 21, 2001. Thereunder, KU
agreed to credit its fuel clause in the amount of $954,000 (such credit provided over the course of two monthly billing periods), and the parties agreed on a prospective interpretation of the state's
fuel adjustment clause regulation to ensure consistent and mutually acceptable application on a going-forward basis. All pending FAC proceedings before the court were resolved by the parties to the
agreement and all parties requested the Court of Appeals remand the case to the Kentucky Commission. The Kentucky Commission is expected to approve the settlement in 2002.

Kentucky Commission Administrative Case for Affiliate Transactions.In December 1997, the Kentucky Commission opened
Administrative Case No. 369 to consider Kentucky Commission policy regarding cost allocations, affiliate transactions and codes of conduct governing the relationship between utilities and their
non-utility operations and affiliates. The Kentucky Commission intended to address two major areas in the proceedings: the tools and conditions needed to prevent cost shifting and cross-subsidization
between regulated and non-utility operations; and whether a code of conduct should be established to assure that non-utility segments of the holding company are not engaged in practices that could
result in unfair competition caused by cost shifting from the non-utility affiliate to the utility. During the period September 1998 to February 2000, the Kentucky Commission issued draft codes 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 utilities that provide
nonregulated activities to keep separate accounts and allocate costs in accordance with procedures established by the Kentucky Commission. In the same Bill, the General Assembly set forth provisions
to govern a utilities activities related to the sharing of information, databases, and resources between its employees or an affiliate involved in the marketing or the provision of nonregulated
activities and its employees or an affiliate involved in the provision of regulated services. The legislation became law in July 2000 and KU has been operating pursuant thereto since that time. On
February 14, 2001, the
Kentucky Commission published notice of their intent to promulgate new administrative regulations under the auspices of this new law. This effort is still on-going.

106

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Note 4Financial Instruments

The cost and estimated fair values of the KU's non-trading financial instruments as of December 31, 2001, and 2000 follow (in thousands of $):

2001

2000Cost

Fair
Value

Cost

Fair
ValueLong-term debt (including current portion)

$
484,830

$
499,618

$
484,830

$
491,277Interest-rate swaps





6,906





3,559


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

Interest Rate Swaps.KU uses interest rate swaps to hedge exposure to market fluctuations in certain of its debt instruments.
Pursuant to policy, use of these financial instruments is intended to mitigate risk and earnings volatility and is not speculative in nature. Management has designated all of the interest rate swaps
as hedge instruments. Financial instruments designated as fair value hedges are periodically
marked to market with the resulting gains and losses recorded directly into net income to correspond with income or expense recognized from changes in market value of the items being hedged.

As
of December 31, 2001 and 2000, KU was party to various interest rate swap agreements with aggregate notional amounts of $153 million in each year. Under these swap agreements, KU paid
variable rates based on either LIBOR or the Bond Market Association's municipal swap index averaging 2.54% and 6.69%, and received fixed rates averaging 7.13% and 7.13% at December 31, 2001 and 2000,
respectively. The swap agreements in effect at December 31, 2001 have been designated as fair value hedges and mature on dates ranging from 2007 to 2025. For 2001, the effective of marking these
financial instruments and the underlying debt to market resulted in immaterial pretax gains recorded in interest expense.

Interest
rate swaps hedge interest rate risk on the underlying debt under SFAS 133, in addition to swaps being marked to market, the item being hedged must also be marked to market,
consequently at December 31, 2001, KU's debt reflects a $3.6 million mark to market adjustment.

Energy Trading.KU conducts energy trading and risk management activities to maximize the value of power sales from physical
assets it owns, in addition to the wholesale sale of excess asset capacity. Certain energy trading activities are accounted for on a mark-to-market basis in accordance with EITF 98-10 Accounting for Contracts Involved in
Energy Trading and Risk Management Activities, SFAS No. 133 Accounting for Derivative Instruments and Hedging
Activities,andSFAS No. 138 Accounting for Certain Derivative Instruments and Certain Hedging Activities. Wholesale sales of
excess asset capacity and wholesale purchases are treated as normal sales and purchases underSFAS No. 133andSFAS No.
138and are not marked to market.

KU
has recorded a net liability of $186,000 and $17,000 at December 31, 2001 and 2000, respectively.

No
changes to valuation techniques for energy trading and risk management activities occurred during 2001. All contracts outstanding at December 31, 2001 have a maturity of less than one
year and are valued using prices actively quoted for proposed or executed transactions or quoted by brokers.

Note 5Concentrations of Credit and Other Risk

Credit risk represents the accounting loss that would be recognized at the reporting date if counterparties failed to perform as contracted. Concentrations of
credit risk (whether on- or off-

107

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balance sheet) relate to groups of customers or counterparties that have similar economic or industry characteristics that would cause their ability to meet contractual obligations to be similarly
affected by changes in economic or other conditions.

KU's
customer receivables and revenues arise from deliveries of electricity to about 469,000 customers in over 600 communities and adjacent suburban and rural areas in 77 counties in
central, southeastern and western Kentucky and to about 30,000 customers in five counties in southwestern Virginia. For the year ended December 31,
2001,100% of total utility revenue was derived from electric operations.

In
August 2001, KU and their employees represented by IBEW Local 2100 entered into a two-year collective bargaining agreement. KU and their employees represented by USWA Local 9447-01
entered into a two year collective bargaining agreement effective August 2000 and expiring July 31, 2002. In July 2001, KU and employees represented by USWA entered into a wage reopener whereby higher
wages were negotiated. The employees represented by these two bargaining units comprise approximately 17% of KU's workforce.

Note 6Pension Plans and Retirement Benefits

Pension Plans.KU sponsors qualified and non-qualified pension plans and other postretirement benefit plans for its
employees. The following tables provide a reconciliation of the changes in the plans' benefit obligations and fair value of assets over the three-year period ending December 31, 2001, and a statement
of the funded status as of December 31 for each of the last three years (in thousands of $):

2001

2000

1999Pension Plans:Change in benefit obligationBenefit obligation at beginning of year

$
233,034

$
219,628

$
233,288Service cost


2,761


4,312


6,210Interest cost


17,534


17,205


15,564Plan amendment


4


11,757


Change due to transfers


(16,827
)




Curtailment loss


1,400





Special termination benefits


24,274





Benefits paid


(29,166
)

(16,512
)

(12,822
)Actuarial (gain) or loss and other


11,458


(3,356
)

(22,612
)Benefit obligation at end of year

$
244,472

$
233,034

$
219,628Change in plan assetsFair value of plan assets at beginning of year

$
244,677

$
274,109

$
238,124Actual return on plan assets


18,155


(10,943
)

49,883Employer contributions and plan transfers


(15,300
)

(994
)

Benefits paid


(29,166
)

(16,512
)

(12,822
)Administrative expenses


(1,419
)

(983
)

(1,076
)Fair value of plan assets at end of year

$
216,947

$
244,677

$
274,109Reconciliation of funded statusFunded status

$
(27,525
)
$
11,643

$
54,481Unrecognized actuarial (gain) or loss


(20,581
)

(36,435
)

(74,579
)Unrecognized transition (asset) or obligation


(664
)

(847
)

(988
)Unrecognized prior service cost


11,027


14,176


3,564Net amount recognized at end of year

$
(37,743
)
$
(11,463
)
$
(17,522
)


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Other Benefits:Change in benefit obligationBenefit obligation at beginning of year

$
64,213

$
54,201

$
79,650Service cost


495


757


1,596Interest cost


5,433


4,781


3,837Plan amendments





7,127


(24,488
)Curtailment loss


6,381





Special termination benefits


3,824





Benefits paid net of retiree contributions


(5,446
)

(4,318
)

(4,646
)Actuarial (gain) or loss


8,323


1,665


(1,748
)Benefit obligation at end of year

$
83,223

$
64,213

$
54,201Change in plan assetsFair value of plan assets at beginning of year

$
23,762

$
28,720

$
24,337Actual return on plan assets


(4,404
)

(1,162
)

5,322Employer contributions and plan transfers


473


522


3,520Benefits paid net of retiree contributions


(5,501
)

(4,318
)

(4,459
)Fair value of plan assets at end of year

$
14,330

$
23,762

$
28,720Reconciliation of funded statusFunded status

$
(68,893
)
$
(40,451
)
$
(25,481
)Unrecognized actuarial (gain) or loss


(437
)

(23,561
)

(28,976
)Unrecognized transition (asset) or obligation


12,290


21,871


23,694Unrecognized prior service cost


3,548


6,109


Net amount recognized at end of year

$
(53,492
)
$
(36,032
)
$
(30,763
)


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

The
following tables provide the amounts recognized in the balance sheet and information for plans with benefit obligations in excess of plan assets as of December 31, 2001, 2000 and
1999 (in thousands of $):

|                                                                                                             |                                                                | 2001 |   | 2000    |   | 1999 |        
|------------------------------------------------------------------------------------------------------------ | -------------------------------------------------------------- | ---- | - | ------- | - | ---- | -------
|Pension Plans:                                                                                               |                                                                |      |   |         |   |      |        
|Amounts recognized in the balance sheet consisted of:                                                        |                                                                |      |   |         |   |      |        
|                                                                                                             | Accrued benefit liability                                      |      | $ | (37,743 | ) | $    | (11,463
|                                                                                                             |                                                                |      |   |         |   |      |        
|Additional year-end information for plans with accumulated benefit obligations in excess of plan assets (1): |                                                                |      |   |         |   |      |        
|                                                                                                             | Projected benefit obligation                                   |      | $ | 244,472 |   | $    | 1,505  
|                                                                                                             | Accumulated benefit obligation                                 |      |   | 224,261 |   |      | 336    
|                                                                                                             | Fair value of plan assets                                      |      |   | 216,947 |   |      |       
|                                                                                                             | (1) 2001 includes all plans. 2000 and 1999 include SERPs only. |      |   |         |   |      |        
|Other Benefits:                                                                                              |                                                                |      |   |         |   |      |        
|Amounts recognized in the balance sheet consisted of:                                                        |                                                                |      |   |         |   |      |        
|                                                                                                             | Accrued benefit liability                                      |      | $ | (53,492 | ) | $    | (36,032
|                                                                                                             |                                                                |      |   |         |   |      |        
|Additional year-end information for plans with benefit obligations in excess of plan assets:                 |                                                                |      |   |         |   |      |        
|                                                                                                             | Projected benefit obligation                                   |      | $ | 83,223  |   | $    | 64,213 
|                                                                                                             | Fair value of plan assets                                      |      |   | 14,330  |   |      | 23,762 

109

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The
following table provides the components of net periodic benefit cost for the plans for 2001, 2000 and 1999 (in thousands of $):

|                                        |                                                  | 2001 |   | 2000    |   | 1999 |        
|--------------------------------------- | ------------------------------------------------ | ---- | - | ------- | - | ---- | -------
|Pension Plans:                          |                                                  |      |   |         |   |      |        
|Components of net periodic benefit cost |                                                  |      |   |         |   |      |        
|                                        | Service cost                                     |      | $ | 2,761   |   | $    | 4,312  
|                                        | Interest cost                                    |      |   | 17,534  |   |      | 17,205 
|                                        | Expected return on plan assets                   |      |   | (19,829 | ) |      | (25,170
|                                        | Amortization of transition (asset) or obligation |      |   | (136    | ) |      | (141   
|                                        | Amortization of prior service cost               |      |   | 962     |   |      | 1,145  
|                                        | Recognized actuarial (gain) or loss              |      |   | (120    | ) |      | (3,410 
|                                        |                                                  |      |   |         |   |      |        
|                                        | Net periodic benefit cost                        |      | $ | 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                                     |      | $ | 495     |   | $    | 757    
|                                        | Interest cost                                    |      |   | 5,433   |   |      | 4,781  
|                                        | Expected return on plan assets                   |      |   | (1,313  | ) |      | (1,768 
|                                        | Amortization of prior service cost               |      |   | 740     |   |      | 1,018  
|                                        | Amortization of transition (asset) or obligation |      |   | 1,193   |   |      | 1,823  
|                                        | Recognized actuarial (gain) or loss              |      |   | (40     | ) |      | (820   
|                                        |                                                  |      |   |         |   |      |        
|                                        | Net periodic benefit cost                        |      | $ | 6,508   |   | $    | 5,791  
|                                        |                                                  |      |   |         |   |      |        
|Special charges                         |                                                  |      |   |         |   |      |        
|                                        | Transition obligation recognized                 |      | $ | 7,638   |   | $    |       
|                                        | Prior service cost                               |      |   | 1,613   |   |      |       
|                                        | Special termination benefits                     |      |   | 3,824   |   |      |       
|                                        |                                                  |      |   |         |   |      |        
|                                        | Total charges                                    |      | $ | 13,075  |   | $    |       
|                                        |                                                  |      |   |         |   |      |        

KU
provides nonpension postretirement benefits for eligible retired employees.

The
assumptions used in the measurement of KU's pension benefit obligation are shown in the following table:

2001

2000

1999Weighted-average assumptions as of December 31:Discount rate

7.25
%
7.75
%
8.00
%Expected long-term rate of return on plan assets

9.50
%
9.50
%
9.50
%Rate of compensation increase

4.25
%
4.75
%
5.00
%


For
measurement purposes, a 10.00% annual increase in the per capita cost of covered health care benefits was assumed for 2002. The rate was assumed to decrease gradually to 5.00% for
2011 and remain at that level thereafter.

110

---

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

1% Decrease

1% IncreaseEffect on total of service and interest cost components for 2001

$
(340
)
$
385Effect on year-end 2001 postretirement benefit obligations


(5,297
)

6,010


Thrift Savings Plans.KU has a thrift savings plan under section 401(k) of the Internal Revenue Code. Under the plan,
eligible employees may defer and contribute to the plan a portion of current compensation in order to provide future retirement benefits. KU makes contributions to the plan by matching a portion of
the employee contributions. The costs of this matching were approximately $1.4 million for 2001, $2.5 million for 2000 and $2.3 million for 1999.

Note 7Income Taxes

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

|                                |                                       |       |        |           |             | 2001   |        | 2000    |        | 1999   |       
|------------------------------- | ------------------------------------- | ----- | ------ | --------- | ----------- | ------ | ------ | ------- | ------ | ------ | ------
|Included in operating expenses: |                                       |       |        |           |             |        |        |         |        |       
|                                | Current                               |       |       |           | federal     |        | $      | 58,337  |        | $      | 44,927
|                                |                                       |      |        | state     |             |        | 13,465 |         |        | 9,333  |       
|                                | Deferred                              |       |       |           | federalnet |        |        | (12,980 | )      |        | (3,254
|                                |                                       |      |        | statenet |             |        | (1,340 | )       |        | 957    |       
|                                |                                       |       |        |           |             |        |        |         |        |        |       
|                                |                                       | Total |        |           | 57,482      |        |        | 51,963  |        |        | 60,380
|                                |                                       |       |        |           |             |        |        |         |        |        |       
|Included in other incomenet:   |                                       |       |        |           |             |        |        |         |        |       
|                                | Current                               |       |       |           | federal     |        |        | (948    | )      |        | 349   
|                                |                                       |      |        | state     |             |        | (268   | )       |        | 67     |       
|                                | Deferred                              |       |       |           | federalnet |        |        | 863     |        |        | (122  
|                                |                                       |      |        | statenet |             |        | 222    |         |        | (30    | )     
|                                | Amortization of investment tax credit |       |        | (3,446    | )           |        | (3,674 | )       |        | (3,727 | )     
|                                |                                       |       |        |           |             |        |        |         |        |        |       
|                                |                                       | Total |        |           | (3,577      | )      |        | (3,410  | )      |        | (2,361
|                                |                                       |       |        |           |             |        |        |         |        |        |       
|Total income tax expense        |                                       | $     | 53,905 |           | $           | 48,553 |        | $       | 58,019 |       
|                                |                                       |       |        |           |             |        |        |         |        |        |       

111

---

Net
deferred tax liabilities resulting from book-tax temporary differences are shown below (in thousands of $):

2001

2000Deferred tax liabilities:Depreciation and other plant-related items

$
269,752

$
279,047Other liabilities


33,376


13,718303,128


292,765Deferred tax assets:Investment tax credit


4,623


6,014Income taxes due to customers


13,263


15,124Pension overfunding


4,595


3,974Accrued liabilities not currently deductible and other


41,443


20,97363,924


46,085Net deferred income tax liability

$
239,204

$
246,680


A
reconciliation of differences between the statutory U.S. federal income tax rate and KU's effective income tax rate follows:

2001

2000

1999Statutory federal income tax rate

35.0
%
35.0
%
35.0
%State income taxes, net of federal benefit

5.4

4.9

5.7Amortization of investment tax credit

(2.3
)
(2.6
)
(2.9
)Other differencesnet

(2.2
)
(3.6
)
(2.5
)Effective income tax rate

35.9
%
33.7
%
35.3
%


Note 8Other Incomenet

Other incomenet consisted of the following at December 31 (in thousands of $):

2001

2000

1999Equity in earningssubsidiary company

$
1,803

$
2,242

$
2,334Interest and dividend income


1,368


1,206


4,293Gains on fixed asset disposals


1,844


5


759Income taxes and other


3,917


3,390


2,051Other incomenet

$
8,932

$
6,843

$
9,437


Note 9First Mortgage Bonds and Pollution Control Bonds

Long-term debt and the current portion of long-term debt, summarized below (in thousands of $), consists primarily of first mortgage bonds and pollution control
bonds. Interest rates and maturities in the table below are for the amounts outstanding at December 31, 2001.

Stated interest rates

Variable, 5.75%-8.55%Weighted-average interest rate

4.91%Maturities

2003-2027Noncurrent portion

$434,506Current portion

$54,000


112

---

Under
the provisions for KU's variable-rate pollution control bonds Series PCS 10, the bonds are subject to tender for purchase at the option of the holder and to mandatory tender for
purchase upon the occurrence of certain events, causing the bonds to be classified as current portion of long-term debt. The average annualized interest rate for these bonds during 2001 was 2.99%.

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

KU's
First Mortgage Bond, 6.32% Series Q of $62 million is scheduled to mature in 2003 and KU's First Mortgage Bond, 5.99% Series S of $36 million matures in 2006. There are no scheduled
maturities of Pollution Control Bonds for the five years subsequent to December 31, 2001.

Substantially
all of KU's utility plant is pledged as security for its First Mortgage Bonds.

Note 10Notes Payable

KU participates in an intercompany money pool agreement wherein LG&E Energy can make funds available to KU at market based rates up to $200 million. At December
31, 2001, the balance of the money pool loan from LG&E Energy was $47.8 million at an average rate of 2.37% and the remaining money pool availability was $152.2 million. In addition, KU maintains an
uncommitted borrowing facility totaling $60 million that was undrawn at December 31, 2001. LG&E Energy maintains a facility of $200 million with an affiliate to ensure funding availability for the
money pool. There was no outstanding balance under this facility as of December 31, 2001, and availability of $170 million remains after considering the $30 million of commercial paper outstanding at
LG&E.

At
December 31, 2000, KU had $61.2 million outstanding under the money pool at an average rate of 6.84%.

Note 11Commitments and Contingencies

Construction Program.KU had $8 million of commitments in connection with its construction program at December 31, 2001.
Construction expenditures for the years 2002 and 2003 are estimated to total approximately $459 million; although all of this is not currently committed. Included in 2002 is $89 million for the
purchase of 71% of two CTs currently under construction by Capital Corp. at LG&E's Trimble County location. LG&E will own 29% of the two CTs. KU is waiting for approval from the Kentucky and Virginia
Commissions.

Operating Leases.KU leases office space, office equipment, and vehicles. KU accounts for these leases as operating leases.
Total lease expense for 2001, 2000, and 1999, was $2.8 million, $2.3 million, and $1.7 million, respectively.

In
December 1999, LG&E and KU entered into an 18-year cross-border lease of its two jointly owned combustion turbines recently installed at KU's Brown facility (units 6 and 7). KU's
obligation was defeased upon consummation of the cross-border lease. The transaction produced a pre-tax gain of approximately $1.9 million which was recorded in other income on the income statement in
2000, pursuant to a Kentucky Commission order.

Environmental.The Clean Air Act imposed stringent new SO2 and NOx emission limits on electric generating units.
KU met its Phase I SO2requirements primarily 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 to delay additional capital expenditures and may also

113

---

include fuel switching or the installation of additional scrubbers. KU met the NOx emission requirements of the Act through installation of low-NOx burner systems. KU's compliance plans are subject
to many factors including developments in the emission allowance and fuel markets, future regulatory and legislative initiatives, and advances in clean air control technology. KU will continue to
monitor these developments to ensure that its environmental obligations are met in the most efficient and cost-effective manner.

In
September 1998, the EPA announced its final "NOx SIP Call" rule requiring states to impose significant additional reductions in NOx emissions by May 2003, in order to mitigate alleged
ozone transport impacts on the Northeast region. The Commonwealth of Kentucky is currently in the process of revising its State Implementation Plan or "SIP" to require reductions in NOx emissions from
coal-fired generating units to the 0.15 lb./Mmbtu level on a system-wide basis. In related proceedings in 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 directing similar NOx reductions from a number of specifically targeted generating units including all KU units in the eastern half of Kentucky.
Additional petitions currently pending before EPA may potentially result in rules encompassing KU's remaining generating units. As a result of appeals to both rules, the compliance date was extended
to May 2004. All KU generating units are subject to the May 2004 compliance date under these NOx emissions reduction rules.

KU
is currently implementing a plan for adding significant additional NOx 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 through the final compliance date. In addition, KU will incur additional operation and maintenance costs in operating new NOx controls.
KU believes its costs in this regard to be comparable to those of similarly situated utilities with like generation assets. KU anticipated that such capital and operating costs are the type of costs
that are eligible for recovery from customers under its environmental surcharge mechanism and believed that a significant portion of such costs could be recovered. In April 2001, the Kentucky
Commission granted recovery of these costs for KU.

KU
is also monitoring several other air quality issues which may potentially 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 and particulate matter, measures to implement EPA's regional haze rule, and EPA's December 2000 determination to regulate mercury emissions from power plants.

KU
owns or formerly owned several properties that contained past MGP operations. Various contaminants are typically found at such former MGP sites and environmental remediation measures
are frequently required. KU has completed the cleanup of a site owned by KU. With respect to other former MGP sites no longer owned by KU, KU is unaware of what, if any, additional exposure or
liability it may have.

In
October 1999, approximately 38,000 gallons of diesel fuel leaked from a cracked valve in an underground pipeline at KU's E.W. Brown Station. Under the oversight of EPA and state
officials, KU commenced immediate spill containment and recovery measures which prevented the spill from reaching the Kentucky River. KU ultimately recovered approximately 34,000 gallons of diesel
fuel. In November 1999, the Kentucky Division of Water issued a notice of violation for the incident. KU is currently negotiating with the state in an effort to reach a complete resolution of this
matter. KU incurred costs of approximately $1.8 million and received insurance reimbursement of $1.2 million.

Purchased Power.KU has purchase power arrangements with OMU, EEI and other parties. Under the OMU agreement, which expires
on January 1, 2020, KU purchases all of the output of a

114

---

400-Mw generating station not required by OMU. The amount of purchased power available to KU during 2002-2006, which is expected to be approximately 9% of KU's total kWh requirements, is dependent
upon a number of factors including the units' availability, maintenance schedules, fuel costs and OMU requirements. Payments are based on the total costs of the station allocated per terms of the OMU
agreement, which generally follows delivered kWh. Included in the total costs is KU's proportionate share of debt service requirements on $153 million of OMU bonds outstanding at December 31, 2001.
The debt service is allocated to KU based on its annual allocated share of capacity, which averaged approximately 48% in 2001.

KU
has a 20% equity ownership in EEI, which is accounted for on the equity method of accounting. KU's entitlement is 20% of the available capacity of a 1,000 Mw station. Payments are
based on the total costs of the station allocated per terms of an agreement among the owners, which generally follows delivered kWh.

KU
has several other contracts for purchased power during 20022006 of various Mw capacities and for varying periods with a maximum entitlement at any time of 62 Mw.

The
estimated future minimum annual payments under purchased power agreements for the five years ended December 31, 2006, are as follows (in thousands of $):

2002

$
37,7882003


34,6652004


41,7362005


41,7772006


41,807Total

$
197,773


115

---

Note 12Jointly Owned Electric Utility Plant

LG&E and KU jointly own the following combustion turbines ($ in thousands):

|               |  |                |  | LG&E |        | KU |   | TOTAL  |  
|-------------- |  | -------------- |  | ---- | ------ | -- | - | ------ | -
|Paddy's Run 13 |  | Ownership %    |  |      | 53     | %  |   | 47     | %
|               |  | Mw capacity    |  |      | 84     |    |   | 74     |  
|               |  | Cost           |  | $    | 33,844 |    | $ | 29,908 |  
|               |  | Depreciation   |  |      | 563    |    |   | 491    |  
|               |  |                |  |      |        |    |   |        |  
|               |  | Net book Value |  | $    | 33,281 |    | $ | 29,417 |  
|               |  |                |  |      |        |    |   |        |  
|E.W. Brown 5   |  | Ownership %    |  |      | 53     | %  |   | 47     | %
|               |  | Mw capacity    |  |      | 70     |    |   | 63     |  
|               |  | Cost           |  | $    | 23,941 |    | $ | 21,078 |  
|               |  | Depreciation   |  |      | 394    |    |   | 342    |  
|               |  |                |  |      |        |    |   |        |  
|               |  | Net book Value |  | $    | 23,547 |    | $ | 20,736 |  
|               |  |                |  |      |        |    |   |        |  
|E.W. Brown 6   |  | Ownership %    |  |      | 38     | %  |   | 62     | %
|               |  | Mw capacity    |  |      | 62     |    |   | 102    |  
|               |  | Cost           |  | $    | 23,696 |    | $ | 36,253 |  
|               |  | Depreciation   |  |      | 953    |    |   | 2,955  |  
|               |  |                |  |      |        |    |   |        |  
|               |  | Net book Value |  | $    | 22,743 |    | $ | 33,298 |  
|               |  |                |  |      |        |    |   |        |  
|E.W. Brown 7   |  | Ownership %    |  |      | 38     | %  |   | 62     | %
|               |  | Mw capacity    |  |      | 62     |    |   | 102    |  
|               |  | Cost           |  | $    | 23,607 |    | $ | 44,785 |  
|               |  | Depreciation   |  |      | 3,268  |    |   | 3,033  |  
|               |  |                |  |      |        |    |   |        |  
|               |  | Net book Value |  | $    | 20,339 |    | $ | 41,752 |  
|               |  |                |  |      |        |    |   |        |  

See
also Note 11, Construction Program, for KU's planned purchase of two jointly owned CTs in 2002.

Note 13Selected Quarterly Data (Unaudited)

Selected financial data for the four quarters of 2001 and 2000 are shown below. Because of seasonal fluctuations in temperature and other factors, results for
quarters may fluctuate throughout the year.

|                                             |  | Quarters Ended
|-------------------------------------------- |  | --------------
|
|
|2001                                         |  |               
|Revenues                                     |  | $             
|Operating income (loss)                      |  |               
|Net income (loss)                            |  |               
|Net income (loss) available for common stock |  |               
|2000                                         |  |               
|Revenues                                     |  | $             
|Operating income                             |  |               
|Net income                                   |  |               
|Net income available for common stock        |  |               

116

---

Note 14Subsequent Events

On April 9, 2001, a German power company, E.ON AG, announced a preconditional cash offer of £5.1 billion ($7.3 billion) for Powergen. The offer is
subject to a number of conditions, including the receipt of certain European and United States regulatory approvals. The Kentucky Public Service Commission, the Federal Energy Regulatory Commission,
the Virginia State Corporation Commission, and the Tennessee Regulatory Authority have all approved the acquisition of Powergen and LG&E Energy by E.ON. The parties expect to obtain the remaining
regulatory approvals and to complete the transaction in the first half of 2002. See Powergen's schedule 14D-9, and associated schedules to such filings, filed with the SEC on April 9, 2001.

KU
(along with LG&E) is a founding member of the MISO, such membership obtained in 1998 in response to and consistent with federal policy initiatives. As a MISO member, KU filed for and
received authorization from FERC to transfer control of its transmission facilities (100 kV and above) to the MISO, the first step in allowing the latter to assume responsibility for all
tariff-related transmission functions (e.g.,scheduling through and on KU's transmission system) as well as non-tariff related regional transmission
activities (e.g.,operations planning, maintenance coordination, long-term regional planning and market monitoring). The FERC approved the MISO as the
nation's first Regional Transmission Organization on December 19, 2001, after which KU submitted a filing at FERC to cancel all services under its Open Access Transmission Tariff except those that
will not be provided by the MISO (certain ancillary services). The MISO became operational on February 1, 2002.

In
October 2001, the FERC issued an order requiring that the bundled retail load and grandfathered wholesale load of each member transmission owner (including KU) be included in the
current calculation of MISO's "cost-adder," a charge designed to recover MISO's costs of operation, including start-up capital (debt) costs. KU, along with several other transmission owners, opposed
the FERC's ruling in this regard, which opposition the FERC rejected in an order on rehearing issued in 2002. As of the end of 2001, negotiations were continuing between MISO, its transmission owners
and other interested industry segments regarding the level of cost responsibility properly borne by bundled and grandfathered load under these FERC rulings. Absent settlement, this issue is expected
to go to hearing in 2002.

At
the end of 2001, in response to an earlier FERC ruling, MISO and its transmission owning members (including KU) filed to increase MISO's rate of return on equity from 10.5% (a
stipulated percentage agreed to in 1998) to 13.0%, to compensate MISO's transmission owners for the inherent risks and uncertainties associated with transferring control of their facilities to the
MISO. This issue is expected to go to hearing in 2002.

117

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Kentucky Utilities Company  Report of Management

The management of Kentucky Utilities Company is responsible for the preparation and integrity of the financial statements and related information included in this
Annual Report. These statements have been prepared in accordance with accounting principles generally accepted in the United States applied on a consistent basis and, necessarily, include amounts that
reflect the best estimates and judgment of management.

KU's
current year financial statements have been audited by PricewaterhouseCoopers LLP, independent accountants and prior years financial statements were audited by Arthur Andersen LLP.
Management made available to PricewaterhouseCoopers LLP and to Arthur Andersen LLP (in prior years) all KU's financial records and related data as well as the minutes of shareholders' and directors'
meetings.

Management
has established and maintains a system of internal controls that provide reasonable assurance that transactions are completed in accordance with management's authorization,
that assets are safeguarded and that financial statements are prepared in conformity with generally accepted accounting principles. Management believes that an adequate system of internal controls is
maintained through the selection and training of personnel, appropriate division of responsibility, establishment and communication of policies and procedures and by regular reviews of internal
accounting controls by KU's internal auditors. Management reviews and modifies its system of internal controls in light of changes in conditions and operations, as well as in response to
recommendations from the internal auditors. These recommendations for the year ended December 31, 2001, did not identify any material weaknesses in the design and operation of KU's internal control
structure.

The
Audit Committee of the Board of Directors is composed entirely of outside directors. In carrying out its oversight role for the financial reporting and internal controls of KU, the
Audit Committee meets regularly with KU's independent public accountants, internal auditors and management. The Audit Committee reviews the results of the independent accountants' audit of the
financial statements and their audit procedures, and discusses the adequacy of internal accounting controls. The Audit Committee also approves the annual internal auditing program, and reviews the
activities and results of the internal auditing function. Both the independent public accountants and the internal auditors have access to the Audit Committee at any time.

Kentucky
Utilities Company maintains and internally 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 of proprietary information.

S.
Bradford Rives
Senior Vice President-Finance and Controller

Kentucky
Utilities Company
Louisville, Kentucky

118

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Kentucky Utilities Company and Subsidiary  Report of Independent Accountants

To
the Shareholders of Kentucky Utilities Company and Subsidiary:

In
our opinion, the accompanying consolidated balance sheet as of December 31, 2001 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 Kentucky Utilities Company and Subsidiary (the "Company"), a wholly-owned subsidiary of LG&E Energy Corp., at
December 31, 2001, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. These
financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these
statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our
opinion.

/s/
PricewaterhouseCoopers LLP
January 25, 2002
Louisville, Kentucky

119

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Kentucky Utilities Company  Report of Independent Public Accountants

To
the Shareholders of Kentucky Utilities Company:

We
have audited the accompanying balance sheet and statement of capitalization of Kentucky Utilities Company (a Kentucky and Virginia corporation and a wholly-owned subsidiary of LG&E
Energy Corp.) as of December 31, 2000, and the related statements of income, retained earnings and cash flows for each of the two years in the period ended December 31, 2000. These financial
statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We
conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for our opinion.

In
our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Kentucky Utilities Company as of December 31, 2000, and the
results of its operations and its cash flows for each of the two years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States.

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

Arthur
Andersen LLP

Louisville,
Kentucky
January 26, 2001

120

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

Effective April 30, 2001, PricewaterhouseCoopers LLP was appointed as certifying accountants for the year ended December 31, 2001, for LG&E
and KU. PricewaterhouseCoopers LLP was the independent accountant of Powergen prior to the acquisition of LG&E Energy and has continued in such engagement. Arthur Andersen LLP was the
certifying account for LG&E Energy and its subsidiaries. Arthur Andersen LLP was notified of their dismissal in April 2001. For further information see LG&E and KU's 8-K dated May 7,
2001.

PART III

ITEMS 10, 11, 12 and 13 are omitted pursuant to General Instruction G of Form 10-K. The information required by ITEMS 10, 11, 12 and 13 for
LG&E and KU are incorporated herein by reference to their definitive proxy statements anticipated to be filed during April 2002 with the Commission pursuant to Regulation 14A of the Securities
and Exchange Act of 1934. Additionally, in accordance with General Instruction G, the information required by ITEM 10 relating to executive officers of LG&E and KU has been included in
Part I of this Form 10-K.

PART IV

ITEM 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.

|(a) |  | 1. |  | Financial Statements (included in Item 8):                                                            
|--- |  | -- |  | ------------------------------------------------------------------------------------------------------
|    |  |    |  | LG&E:                                                                                                 
|    |  |    |  | Consolidated statements of income for the three years ended December 31, 2001 (page 61).              
|    |  |    |  | Consolidated statements of retained earnings for the three years ended December 31, 2001 (page 61).   
|    |  |    |  | Consolidated statements of comprehensive income for the three years ended December 31, 2001 (page 62).
|    |  |    |  | Consolidated balance sheets-December 31, 2001, and 2000 (pages 63-64).                                
|    |  |    |  | Consolidated statements of cash flows for the three years ended December 31, 2001 (page 65).          
|    |  |    |  | Consolidated statements of capitalization-December 31, 2001, and 2000 (page 66).                      
|    |  |    |  | Notes to consolidated financial statements (pages 67-87).                                             
|    |  |    |  | Report of management (page 88).                                                                       
|    |  |    |  | Report of independent accountants (pages 89-90).                                                      
|    |  |    |  | KU:                                                                                                   
|    |  |    |  | Consolidated statements of income for the three years ended December 31, 2001 (page 93).              
|    |  |    |  | Consolidated statements of retained earnings for the three years ended December 31, 2001 (page 93).   
|    |  |    |  | Consolidated statements of comprehensive income for the three years ended December 31, 2001 (page 95).
|    |  |    |  | Consolidated balance sheets-December 31, 2001, and 2000 (page 95).                                    
|    |  |    |  | Consolidated statements of cash flows for the three years ended December 31, 2001 (page 96).          
|    |  |    |  | Consolidated statements of capitalization-December 31, 2001, and 2000 (page 97).                      
|    |  |    |  | Notes to consolidated financial statements (pages 98-115).                                            
|    |  |    |  | Report of management (page 116).                                                                      
|    |  |    |  | Report of independent accountants (pages 117-118).                                                    

121

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| |  | 2. |  | Financial Statement Schedules (included in Part IV):                                                                                                                                                              
| |  | -- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  |    |  | Schedule II                                                                                                                                                                                                       
| |  |    |  | 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:                                                                                                                                                                                                         

| |      |  | Applicable to Form 10-K of |  |  
| | ---- |  | -------------------------- |  | -
|
|
| |      |  |                            |  |  
| | 2.01 |  | x                          |  | x
| | 2.02 |  | x                          |  | x
| | 2.03 |  | x                          |  | x
| | 3.01 |  | x                          |  |  
| | 3.02 |  | x                          |  |  
| | 3.03 |  |                            |  | x
| | 3.04 |  |                            |  | x
| | 4.01 |  | x                          |  |  
| | 4.02 |  | x                          |  |  
| |      |  |                            |  |  

122

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| | 4.03 |  | x |  |  |  | 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 |  | x |  |  |  | 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 |  | x |  |  |  | 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 |  | x |  |  |  | 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 |  | x |  |  |  | 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]     
| | 4.08 |  | x |  |  |  | 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 |  | x |  |  |  | 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 |  | x |  |  |  | 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 |  | x |  |  |  | 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 |  | x |  |  |  | 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 |  | x |  |  |  | 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]
| |      |  |   |  |  |  |                                                                                                                                                                                                                         

123

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| | 4.14 |  | x |  |  |  | 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 |  | x |  |  |  | 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 |  | x |  |  |  | Copy of Supplemental Indenture dated February 15, 1979, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.16 to LG&E's Registration Statement 2-65271 and incorporated by reference herein]                                   
| | 4.17 |  | x |  |  |  | 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 |  | x |  |  |  | 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 |  | x |  |  |  | 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 |  | x |  |  |  | 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 |  | x |  |  |  | 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 |  | x |  |  |  | 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 |  | x |  |  |  | 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 |  | x |  |  |  | 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]      
| |      |  |   |  |  |  |                                                                                                                                                                                                                                                            

124

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| | 4.25 |  | x |  |  |  | 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 |  | x |  |  |  | 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 |  | x |  |  |  | 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 |  | x |  |  |  | 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 |  | x |  |  |  | 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 |  | x |  |  |  | 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 |  | x |  |  |  | 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 |  | x |  |  |  | Copy of Supplemental Indenture dated September 1, 1992, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.32 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1992, and
incorporated by reference herein]
| | 4.33 |  | x |  |  |  | Copy of Supplemental Indenture dated September 2, 1992, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.33 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1992, and
incorporated by reference herein]
| | 4.34 |  | x |  |  |  | Copy of Supplemental Indenture dated August 15, 1993, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.34 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1993, and
incorporated by reference herein]  
| | 4.35 |  | x |  |  |  | Copy of Supplemental Indenture dated August 16, 1993, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.35 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1993, and
incorporated by reference herein]  
| |      |  |   |  |  |  |                                                                                                                                                                                                                                                           

125

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| | 4.36 |  | x |  |   |  | Copy of Supplemental Indenture dated October 15, 1993, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.36 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1993, and
incorporated by reference herein]                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
| | ---- |  | - |  | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | 4.37 |  | x |  |   |  | Copy of Supplemental Indenture dated May 1, 2000, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.37 to LG&E's Annual Report on Form 10-K/A for the year ended December 31, 2000, and
incorporated by reference herein]                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
| | 4.38 |  | x |  |   |  | Copy of Supplemental Indenture dated August 1, 2000, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.38 to LG&E's Annual Report on Form 10-K/A for the year ended December 31, 2000, and
incorporated by reference herein]                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
| | 4.39 |  |   |  | x |  | Indenture of Mortgage or Deed of Trust dated May 1, 1947, between KU and First Trust National Association (successor Trustee) and a successor individual co-trustee, as Trustees (the Trustees) (Amended Exhibit 7(a) in File No. 2-7061),
and Supplemental Indentures thereto dated, respectively, January 1, 1949 (Second Amended Exhibit 7.02 in File No. 2-7802), July 1, 1950 (Amended Exhibit 7.02 in File No. 2-8499), June 15, 1951 (Exhibit 7.02(a)
in File No. 2-8499), June 1, 1952 (Amended Exhibit 4.02 in File No. 2-9658), April 1, 1953 (Amended Exhibit 4.02 in File No. 2-10120), April 1, 1955 (Amended Exhibit 4.02 in File No. 2-11476),
April 1, 1956 (Amended Exhibit 2.02 in File No. 2-12322), May 1, 1969 (Amended Exhibit 2.02 in File No. 2-32602), April 1, 1970 (Amended Exhibit 2.02 in File No. 2-36410), September 1, 1971 (Amended
Exhibit 2.02 in File No. 2-41467), December 1, 1972 (Amended Exhibit 2.02 in File No. 2-46161), April 1, 1974 (Amended Exhibit 2.02 in File No. 2-50344), September 1, 1974 (Exhibit 2.04 in File
No. 2-59328), July 1, 1975 (Exhibit 2.05 in File No. 2-59328), May 15, 1976 (Amended Exhibit 2.02 in File No. 2-56126), April 15, 1977 (Exhibit 2.06 in File No. 2-59328), August 1, 1979
(Exhibit 2.04 in File No. 2-64969), May 1, 1980 (Exhibit 2 to Form 10-Q Quarterly Report of KU for the quarter ended June 30, 1980), September 15, 1982 (Exhibit 4.04 in File No. 2-79891), August 1,
1984 (Exhibit 4B to Form 10-K Annual Report of KU for the year ended December 31, 1984), June 1, 1985 (Exhibit 4 to Form 10-Q Quarterly Report of KU for the quarter ended June 30, 1985), May 1, 1990
(Exhibit 4 to Form 10-Q Quarterly Report of KU for the quarter ended June 30, 1990), May 1, 1991 (Exhibit 4 to Form 10-Q Quarterly Report of KU for the quarter ended June 30, 1991), May 15, 1992
(Exhibit 4.02 to Form 8-K of KU dated May 14, 1992), August 1, 1992 (Exhibit 4 to Form 10-Q Quarterly Report of KU for the quarter ended September 30, 1992), June 15, 1993 (Exhibit 4.02 to Form 8-K of
KU dated June 15, 1993) and December 1, 1993 (Exhibit 4.01 to Form 8-K of KU dated December 10, 1993), November 1, 1994 (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 (Exhibit 4.E to Form 10-K Annual Report of KU for the year ended December 31, 1995).
Incorporated by reference.
| |      |  |   |  |   |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             

126

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| | 4.40  |  |   |  | x |  | 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]                                                                                                                                                                                            
| | ----- |  | - |  | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | 4.41  |  |   |  | x |  | Copy of Supplemental Indenture dated May 1, 2000, which is a supplemental instrument to Exhibit 4.39 hereto. [Filed as Exhibit 4.41 to KU's Annual Report on Form 10-K/A for the year ended December 31, 2000, and incorporated
by reference herein]                                                                                                                                                                                                                                        
| | 4.42  |  | x |  |   |  | Copy of Supplemental Indenture dated September 1, 2001, which is a supplemental instrument to Exhibit 4.01 hereto.                                                                                                                                                                                                                                                                                                                                                                         
| | 4.43  |  |   |  | x |  | Receivables Purchase Agreement dated as of February 6, 2001 among KU Receivables LLC, Kentucky Utilities Company as Servicer, the Various Purchaser Groups From Time to Time Party Hereto and PNC Bank, National Association, as
Administrator                                                                                                                                                                                                                                             
| | 4.44  |  |   |  | x |  | Purchase and Sale Agreement dated as of February 6, 2001 between KU Receivables LLC and Kentucky Utilities Company                                                                                                                                                                                                                                                                                                                                                                         
| | 4.45  |  | x |  |   |  | Receivables Purchase Agreement dated as of February 6, 2001 among LG&E Receivables LLC, Louisville Gas and Electric Company as Servicer, the Various Purchaser Groups From Time to Time Party Hereto and PNC Bank, National Association, as
Administrator                                                                                                                                                                                                                                  
| | 4.46  |  | x |  |   |  | Purchase and Sale Agreement dated as of February 6, 2001 between LG&E Receivables LLC and Louisville Gas and Electric Company                                                                                                                                                                                                                                                                                                                                                              
| | 10.01 |  | x |  |   |  | 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 |  | x |  |   |  | Copy of Modification No. 1 dated July 23, 1953, to the Power Agreement 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 |  | x |  |   |  | 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 |  | x |  |   |  | 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]                                                                                                                                                                            
| |       |  |   |  |   |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             

127

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| | 10.05 |  | x |  |   |  | 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 |  | x |  | x |  | Copies of (i) Inter-Company Power Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies (which Agreement includes as Exhibit A the Power Agreement, dated July 10, 1953, between Ohio Valley
Electric Corporation and Indiana-Kentucky Electric Corporation); (ii) First Supplementary Transmission Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies; (iii) Inter-Company Bond Agreement, dated
July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies; (iv) Inter-Company Bank Credit Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 5.02f
to LG&E's Registration Statement 2-61607 and incorporated by reference herein]
| | 10.07 |  | x |  | x |  | Copy of Modification No. 1 and No. 2 dated June 3, 1966 and January 7, 1967, respectively, to Inter-Company Power Agreement dated July 10, 1953. [Filed as Exhibits 4(a)(8) and 4(a)(10) to LG&E's Registration
Statement 2-26063 and incorporated by reference herein]                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
| | 10.08 |  | x |  |   |  | Copies of Amendments to Agreements (iii) and (iv) referred to under 10.06 above as follows: (i) Amendment to Inter-Company Bond Agreement and (ii) Amendment to Inter-Company Bank Credit Agreement. [Filed as Exhibit 5.02h to LG&E's
Registration Statement 2-61607 and incorporated by reference herein]                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            
| | 10.09 |  | x |  |   |  | Copy of Modification No. 1, dated August 20, 1958, to First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 5.02i to LG&E's
Registration Statement 2-61607 and incorporated by reference herein]                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
| | 10.10 |  | x |  |   |  | Copy of Modification No. 2, dated April 1, 1965, to the First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 5.02j to LG&E's
Registration Statement 2-61607 and incorporated by reference herein]                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
| | 10.11 |  | x |  |   |  | Copy of Modification No. 3, dated January 20, 1967, to First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 4(a)(7) to LG&E's
Registration Statement 2-26063 and incorporated by reference herein]                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  
| | 10.12 |  | x |  |   |  | 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]                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
| |       |  |   |  |   |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        

128

---

| | 10.13 |  | x |  | x |  | Copy of Modification No. 3 dated November 15, 1967, to the Inter-Company Power Agreement dated July 10, 1953. [Filed as Exhibit 4.02m to LG&E's Registration Statement 2-37368 and incorporated by reference herein]                                                                                          
| | ----- |  | - |  | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | 10.14 |  | x |  |   |  | 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 |  | x |  | x |  | Copy of Modification No. 4 dated November 5, 1975, to the Inter-Company Power Agreement dated July 10, 1953. [Filed as Exhibit 5.02o to LG&E's Registration Statement 2-56357 and incorporated by reference herein]                                                                                           
| | 10.16 |  | x |  |   |  | Copy of Modification No. 4 dated April 30, 1976, to First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 5.02p to LG&E's
Registration Statement 2-61607 and incorporated by reference herein]              
| | 10.17 |  | x |  |   |  | 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 |  | x |  |   |  | 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 |  | x |  |   |  | 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 |  | x |  |   |  | 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 |  | x |  | x |  | Copy of Modification No. 5 dated September 1, 1979, to Inter-Company Power Agreement dated July 5, 1953, among Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 4 to LG&E's Annual Report on
Form 10-K for the year ended December 31, 1979, and incorporated by reference herein]
| | 10.22 |  | x |  |   |  | 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]                      
| |       |  |   |  |   |  |                                                                                                                                                                                                                                                                                                               

129

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| | 10.23 |  | x |  | x |  | Copy of Modification No. 6 dated August 1, 1981, to Inter-Company Power Agreement dated July 5, 1953, among Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 10.26 to LG&E's Annual Report on
Form 10-K for the year ended December 31, 1981, and incorporated by reference herein]                                                              
| | ----- |  | - |  | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | 10.24 |  | x |  | * |  | Copy of Nonqualified Savings Plan covering officers of the Company, effective January 1, 1992. [Filed as Exhibit 10.43 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference
herein]                                                                                                                               
| | 10.25 |  | x |  |   |  | 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 |  | x |  |   |  | 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 |  | x |  | x |  | Copy of Modification No. 7 dated January 15, 1992, to Inter-Company Power Agreement dated July 10, 1953, among Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 10.44 to LG&E's Annual Report on
Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]                                                           
| | 10.28 |  | x |  |   |  | 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 |  | x |  |   |  | Copies of Firm No Notice Transportation Agreements, each effective November 1, 1993, between Texas Gas Transmission Corporation and LG&E (expiring October 31, 2000, 2001 and 2003) covering the transmission of natural gas.                                                                                                                                                
| |       |  |   |  |   |  | [All filed as Exhibit 10.47 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]                                                                                                                                                                                                                                 
| | 10.30 |  | x |  | x |  | Copy of Modification No. 8 dated January 19, 1994, to Intercompany 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 |  | x |  |   |  | Copy of Amendment dated March 1, 1995, to Firm No-Notice Transportation Agreements dated November 1, 1993 (2-Year, 5-Year and 8-Year), between Texas Gas Transmission Corporation and LG&E covering the transmission of natural gas. [Filed
as Exhibit 10.44 of LG&E's Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
| |       |  |   |  |   |  |                                                                                                                                                                                                                                                                                                                                                                              

130

---

| | 10.32 |  | x |  | x |  | Copy of Modification No. 9, dated August 17, 1995, to the Inter-Company Power Agreement dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 10.39 to LG&E's Annual Report
on Form 10-K for the year ended December 31, 1996, and incorporated by reference herein]                            
| | ----- |  | - |  | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | 10.33 |  | x |  |   |  | Copy of Agreement and Plan of Merger, dated February 10, 1995, between LG&E Natural Inc., formerly known as Hadson Corporation, Carousel Acquisition Corporation and the Company. [Filed as Exhibit 2 of Schedule 13D by the Company on
February 21, 1995, and incorporated by reference herein]                                                      
| | 10.34 |  | x |  |   |  | Copies of Firm Transportation Agreements, each dated March 1, 1995, between Texas Gas Transmission Corporation and LG&E (expiring October 31, 2001 and 2003) covering the transportation of natural gas. [Both filed as Exhibit 10.45
to LG&E's Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
| | 10.35 |  | x |  |   |  | Copy of Firm Transportation Agreement, dated March 1, 1995, between Texas Gas Transmission Corporation and LG&E (expires October 31, 2000) covering the transportation of natural gas. [Filed as Exhibit 10.41 to LG&E's Annual
Report on Form 10-K for the year ended December 31, 1996, and incorporated by reference herein]                       
| | 10.36 |  | x |  |   |  | * Copy of Amendment to the Non-Qualified Savings Plan, effective January 1, 1992. [Filed as Exhibit 10.55 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference
herein]                                                                                                                     
| | 10.37 |  | x |  |   |  | * Copy of Amendment to the Non-Qualified Savings Plan, effective January 1, 1995. [Filed as Exhibit 10.56 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference
herein]                                                                                                                     
| | 10.38 |  | x |  |   |  | * Copy of Amendment to the Non-Qualified Savings Plan, effective January 1, 1995. [Filed as Exhibit 10.57 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference
herein]                                                                                                                     
| | 10.39 |  | x |  |   |  | Copy of Form of Master Gas Purchase Agreement, dated December 14, 1993, among Santa Fe, SFEOP and AGPC. [Filed as Exhibit 10.23 to LG&E Natural Inc.'s, formerly known as Hadson Corporation, Registration Statement on
Form S-4, File No. 33-68224, and incorporated by reference herein]                                                            
| | 10.40 |  | x |  |   |  | Copy of Credit Agreement, dated as of December 18, 1995, among LG&E, as Borrower, the Banks named therein, PNC Bank, Kentucky, Inc. as Agent and Bank of Montreal as Co-Agent. [Filed as Exhibit 10.01 to the LG&E's Quarterly Report on
Form 10-Q/A for the quarter ended March 31, 1996, and incorporated by reference herein]                      
| |       |  |   |  |   |  |                                                                                                                                                                                                                                                                                                                                                       

131

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| | 10.41 |  | x |  |   |  | Copy of Firm Transportation Agreement, dated November 1, 1996, between LG&E and Tennessee Gas Pipeline Company for 30,000 Mmbtu per day in Firm Transportation Service under Tennessee's Rate FT-A (expires October 31, 2001). [Filed as
Exhibit 10.42 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1996, and incorporated by reference herein]                              
| | ----- |  | - |  | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | 10.42 |  | x |  |   |  | Copy of Amendment No. 1, dated as of November 5, 1996, to Credit Agreement dated as of December 18, 1995, by and among Louisville Gas and Electric Company, the Banks party thereto, and PNC Bank, Kentucky, Inc. as Agent and Bank of
Montreal as Co-Agent. [Filed as Exhibit 10.59 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1996, and incorporated by reference herein]
| | 10.43 |  | x |  |   |  | * Copy of LG&E Energy Corp. and Louisville Gas and Electric Company Non-Officer Senior Management Pension Restoration Plan, effective May 1, 1996. [Filed as Exhibit 10.69 to LG&E Energy's Annual Report on Form 10-K for the year
ended December 31, 1996, and incorporated by reference herein]                                                                                                   
| | 10.44 |  | x |  | x |  | * Copy of Supplemental Executive Retirement Plan as amended through January 1, 1998, covering officers of LG&E Energy. [Filed as Exhibit 10.74 to LG&E Energy's Annual Report on Form 10-K for the year ended December 31,
1997, and incorporated by reference herein]                                                                                                                               
| | 10.45 |  | x |  |   |  | Copy of Coal Supply Agreement between LG&E and Kindill Mining, Inc., dated July 1, 1997. [Filed as Exhibit 10.76 to LG&E Energy's Annual Report on Form 10-K for the year ended December 31, 1997, and incorporated by
reference herein]                                                                                                                                                             
| | 10.46 |  | x |  |   |  | Copy of Coal Supply Agreement between LG&E and Warrior Coal Corp. dated January 1, 1997, and Amendments #1 and #2 dated May 1, 1997, and December 1, 1997, thereto. [Filed as Exhibit 10.79 to LG&E Energy's Annual Report on
Form 10-K for the year ended December 31, 1997, and incorporated by reference herein]                                                                                  
| | 10.47 |  | x |  |   |  | Copies of Amendments dated September 23, 1997, to Firm No-Notice Transportation Agreements dated November 1, 1993, between Texas Gas Transmission Corporation and LG&E, as amended. [Filed as Exhibit 10.81 to LG&E Energy's Annual
Report on Form 10-K for the year ended December 31, 1997, and incorporated by reference herein]                                                                  
| | 10.48 |  | x |  |   |  | Copies of Amendments dated September 23, 1997, to Firm Transportation Agreements dated March 1, 1995, between Texas Gas Transmission Corporation and LG&E, as amended. [Filed as Exhibit 10.82 to LG&E Energy's Annual Report on
Form 10-K for the year ended December 31, 1997, and incorporated by reference herein]                                                                               
| |       |  |   |  |   |  |                                                                                                                                                                                                                                                                                                                                                                                                      

132

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| | 10.49 |  | x |  |   |  | Copy of Gas Transportation Agreement dated November 1, 1996, between Tennessee Gas Pipeline Company and LG&E and amendments dated February 4, 1997, thereto. [Filed as Exhibit 10.83 to LG&E Energy's Annual Report on
Form 10-K for the year ended December 31, 1997, and incorporated by reference herein] [Certain portions of this exhibit have been omitted pursuant to a confidential treatment request filed with the Securities and Exchange Commission]
| | ----- |  | - |  | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | 10.50 |  | x |  |   |  | Copy of Coal Supply Agreement dated January 1, 1999 between LG&E and Peabody COALSALES Company. [Filed as Exhibit 10.77 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1998 and incorporated by
reference herein]                                                                                                                                                                                                                         
| | 10.51 |  | x |  | x |  | Copy of Coal Supply Agreement between LG&E and KU and Black Beauty Coal Company, dated as of January 1, 2002, covering the purchase of coal.                                                                                                                                                                                                                                                                                                                   
| | 10.52 |  | x |  | x |  | Copy of Coal Supply Agreement between LG&E and KU and McElroy Coal Company, Consolidation Coal Company, Consol Pennsylvania Coal Company, Greenon Coal Company, Nineveh Coal Company, Eighty Four Mining Company and Island Creek Coal Company,
dated as of January 1, 2000, and Amendment No. 1 dated as of January 1, 2002, for the purchase of coal.                                                                                                        
| | 10.53 |  |   |  | x |  | Copy of Coal Supply Agreement between KU and Arch Coal Sales Company, Inc., as agent for the independent operating subsidiaries of Arch Coal, Inc. dated as of July 22, 2001, for the purchase of coal.                                                                                                                                                                                                                                                        
| | 10.54 |  | x |  |   |  | Copy of Coal Supply Agreement between LG&E and Hopkins County Coal, LLC and Alliance Coal Sales, a division of Alliance Coal, LLC, dated as of January 1, 2002, for the purchase of coal.                                                                                                                                                                                                                                                                      
| | 10.55 |  |   |  | x |  | Copy of Coal Supply Agreement between KU and Arch Coal Sales Company, Inc., as agent for the independent operating subsidiaries of Arch Coal, Inc., dated as of August 12, 2001, for the purchase of coal.                                                                                                                                                                                                                                                     
| | 10.56 |  |   |  | x |  | 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                                                                                                                                                                                                                                                                               
| | 10.57 |  | x |  |   |  | Copy of Amendment dated November 6, 2000 to Firm No-Notice Transportation Agreement between LG&E and Texas Gas Transmission Corporation covering the transmission of natural gas (expires October 31, 2006)                                                                                                                                                                                                                                                    
| | 10.58 |  | x |  |   |  | Copy of Amendment dated November 6, 2000 to Firm No-Notice Transportation Agreement between LG&E and Texas Gas Transmission Corporation covering the transmission of natural gas (expires October 31, 2008)                                                                                                                                                                                                                                                    
| | 10.59 |  | x |  |   |  | Copy of Amendment dated November 6, 2000 to Firm No-Notice Transportation Agreement between LG&E and Texas Gas Transmission Corporation covering the transmission of natural gas (expires October 31, 2006)                                                                                                                                                                                                                                                    
| |       |  |   |  |   |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                 

133

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| | 10.60 |  | x |  |   |  | Copy of Amendment dated September 15, 1999 to Firm No-Notice Transportation Agreement between LG&E and Texas Gas Transmission Corporation covering the transmission of natural gas (expires October 31, 2006)                                                                                                                      
| | ----- |  | - |  | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | 10.61 |  | x |  | x |  | * Copy of Amendment to LG&E Energy's Supplemental Executive Retirement Plan, effective September 2, 1998. [Filed as Exhibit 10.90 to LG&E Energy's Annual Report on Form 10-K for the year ended December 31, 1998 and incorporated
by reference herein]                                                                            
| | 10.62 |  | x |  | x |  | * Copy of Employment Agreement, dated as of February 25, 2000, by and among LG&E Energy, Powergen plc and Roger W. Hale. [Filed as Exhibit 1 to Appendix A of LG&E Energy's Preliminary Proxy Statement on Schedule 14A on
March 13, 2000 and incorporated by reference herein]                                                     
| | 10.63 |  | x |  | x |  | * Copy of form of Employment and Severance Agreement, dated as of February 25, 2000, by and among LG&E Energy, Powergen plc and certain executive officers of the Company.[Filed as Exhibit 10.94 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]         
| | 10.64 |  | x |  | x |  | * Copy of Amendment, effective October 1, 1999, to LG&E Energy's Non-Qualified Savings Plan.[Filed as Exhibit 10.96 to LG&E's and KU's Annual Report on Form 10-K for the year ended December 31, 1999, and incorporated
herein by reference]                                                                                       
| | 10.65 |  | x |  | x |  | * Copy of Amendment, effective December 1, 1999, to LG&E Energy's Non-Qualified Savings Plan.[Filed as Exhibit 10.97 to LG&E's and KU's Annual Report on Form 10-K for the year ended December 31, 1999, and incorporated
herein by reference]                                                                                      
| | 10.66 |  | x |  | x |  | Copy of Modification No. 10, dated January 1, 1998, to the Inter-Company Power Agreement dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies.[Filed as Exhibit 10.102 to LG&E's and KU's
Annual Report on Form 10-K for the year ended December 31, 1999, and incorporated herein by reference]
| | 10.67 |  | x |  | x |  | Copy of Modification No. 11, dated April 1, 1999, to the Inter-Company Power Agreement dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies.[Filed as Exhibit 10.103 to LG&E's and KU's Annual
report on Form 10-K for the year ended December 31, 1999, and incorporated herein by reference]  
| | 10.68 |  | x |  |   |  | Copy of Amendment No. 1, dated January 1, 2000, to Amended and Restated Coal Supply Agreement, dated April 1, 1998, among LG&E, Hopkins County Coal, LLC and Webster County Coal, LLC.[Filed as Exhibit 10.104 to LG&E's
Annual Report on Form 10-K for the year ended December 31, 1999, and incorporated herein by reference]     
| | 10.69 |  | x |  |   |  | Copy of Amendment No. 1, dated January 1, 2000, to Coal Supply Contract, dated January 1, 1999, between LG&E and Peabody CoalSales Company. [Field as Exhibit 10.105 to LG&E's Annual Report on Form 10-K for the year
ended December 31, 1999, and incorporated herein by reference]                                               
| |       |  |   |  |   |  |                                                                                                                                                                                                                                                                                                                                     

134

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| | 10.70 |  | x |  |   |  | 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 herein by reference.]
| | ----- |  | - |  | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | 10.71 |  | x |  | x |  | *Copy of Powergen Long-Term Incentive Plan, effective December 11, 2000, applicable to certain employees of LG&E Energy Corp. and its subsidiaries [Filed as Exhibit 10.107 to LG&E's Annual Report on Form 10-K for the year ended
December 31, 2000, and incorporated herein by reference]            
| | 10.72 |  | x |  | x |  | *Copy of Powergen Short-Term Incentive Plan, effective January 1, 2001, applicable to certain employees of LG&E Energy Corp. and its subsidiaries [Filed as Exhibit 10.109 to LG&E's Annual Report on Form 10-K for the year ended
December 31, 2000, and incorporated herein by reference]             
| | 10.73 |  | x |  | x |  | *Copy of two forms of Change-In-Control Agreement applicable to certain employees of LG&E Energy Corp. and its subsidiaries. [Filed as Exhibit 10.110 to LG&E's Annual Report on Form 10-K for the year ended December 31, 2000,
and incorporated herein by reference]                                  
| | 10.74 |  | x |  | x |  | *Copy of employment and Severance Agreement, dated as of February 25, 2000, and amendments thereto dated December 8, 2000 and April 30, 2001, by and among LG&E Energy, Powergen plc and Victor A. Staffieri.                                                                                           
| | 10.75 |  | x |  | x |  | *Copy of form of Amendments, dated as of December 8, 2000, to Employment and Severance Agreements dated as of February 25, 2000, by and among LG&E Energy, Powergen plc and certain executive officers of the Company.                                                                                  
| | 10.76 |  | x |  | x |  | *Copy of form of offer letter, dated as of November 29, 2000, by and among LG&E Energy and certain executive officers of the Company.                                                                                                                                                                   
| | 12    |  | x |  | x |  | Computation of Ratio of Earnings to Fixed Charges for LG&E and KU.                                                                                                                                                                                                                                     
| | 21    |  | x |  | x |  | Subsidiaries of the Registrants.                                                                                                                                                                                                                                                                       
| | 23.01 |  | x |  |   |  | Consents of Independent Accountants for LG&E.                                                                                                                                                                                                                                                          
| | 23.02 |  |   |  | x |  | Consents of Independent Accountants for KU.                                                                                                                                                                                                                                                            
| | 24    |  | x |  | x |  | Powers of Attorney.                                                                                                                                                                                                                                                                                    
| | 99.01 |  | x |  | x |  | Cautionary Statement for purposes of the "Safe Harbor" provisions of the Private Securities Litigation Reform Act of 1995.                                                                                                                                                                             
| | 99.02 |  | x |  | x |  | LG&E and KU Director and Officer Information                                                                                                                                                                                                                                                            

Exhibits preceded by a dagger ("") above are incorporated by reference to their filing as exhibits to LG&E's or KU's Annual Report on Form 10-K
for the year ended December 31, 2001.



135

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136

---





REPORT OF INDEPENDENT ACCOUNTANTS  ON FINANCIAL STATEMENT SCHEDULES

To
the Shareholders of Louisville Gas and Electric Company and Subsidiary:

Our
audit of the consolidated financial statements of Louisville Gas and Electric Company and Subsidiary as of December 31, 2001 and for the year then ended referred to in our report
dated January 25, 2002 also included an audit of the financial statement schedule listed in Item 14(a)2 of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all
material respects, the information set forth therein as of December 31, 2001 and for the year then ended when read in conjunction with the related consolidated financial statements.

/s/
PricewaterhouseCoopers LLP
January 25, 2002
Louisville, Kentucky

137

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Schedule II

Louisville Gas and Electric Company  Schedule IIValuation and Qualifying Accounts  For the Three Years Ended December 31, 2001  (Thousands of $)

|                          |                                                       | Other
Property
and
Investments |    | Accounts
Receivable
(Uncollectible
Accounts)
|------------------------- | ----------------------------------------------------- | ------------------------------ | -- | --------------------------------------------
|Balance December 31, 1998 |                                                       | $                              | 63 |                                             
|Additions:                |                                                       |                                |    |                                             
|                          | Charged to costs and expenses                         |                                |    |                                            
|Deductions:               |                                                       |                                |    |                                             
|                          | Net charges of nature for which reserves were created |                                |    |                                            
|                          |                                                       |                                |    |                                             
|Balance December 31, 1999 |                                                       |                                | 63 |                                             
|Additions:                |                                                       |                                |    |                                             
|                          | Charged to costs and expenses                         |                                |    |                                            
|Deductions:               |                                                       |                                |    |                                             
|                          | Net charges of nature for which reserves were created |                                |    |                                            
|                          |                                                       |                                |    |                                             
|Balance December 31, 2000 |                                                       |                                | 63 |                                             
|Additions:                |                                                       |                                |    |                                             
|                          | Charged to costs and expenses                         |                                |    |                                            
|Deductions:               |                                                       |                                |    |                                             
|                          | Net charges of nature for which reserves were created |                                |    |                                            
|                          |                                                       |                                |    |                                             
|Balance December 31, 2001 |                                                       | $                              | 63 |                                             
|                          |                                                       |                                |    |                                             

138

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Report of Independent Accountants  on Financial Statement Schedules

To
the Shareholders of Kentucky Utilities Company and Subsidiary:

Our
audit of the consolidated financial statements of Kentucky Utilities Company and Subsidiary as of December 31, 2001 and for the year then ended referred to in our report dated
January 25, 2002 also included an audit of the financial statement schedule listed in Item 14(a)2 of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material
respects, the information set forth therein as of December 31, 2001 and for the year then ended when read in conjunction with the related consolidated financial statements.

/s/
PricewaterhouseCoopers LLP
January 25, 2002
Louisville, Kentucky

139

---



Schedule II

Kentucky Utilities Company  Schedule IIValuation and Qualifying Accounts  For the Three Years Ended December 31, 2001  (Thousands of $)

|                          |                                                       | Other
Property
and
Investments |     | Accounts
Receivable
(Uncollectible
Accounts)
|------------------------- | ----------------------------------------------------- | ------------------------------ | --- | --------------------------------------------
|Balance December 31, 1998 |                                                       | $                              | 576 |                                             
|Additions:                |                                                       |                                |     |                                             
|                          | Charged to costs and expenses                         |                                |     | 111                                         
|Deductions:               |                                                       |                                |     |                                             
|                          | Net charges of nature for which reserves were created |                                |     |                                            
|                          |                                                       |                                |     |                                             
|Balance December 31, 1999 |                                                       |                                | 687 |                                             
|Additions:                |                                                       |                                |     |                                             
|                          | Charged to costs and expenses                         |                                |     | 64                                          
|Deductions:               |                                                       |                                |     |                                             
|                          | Net charges of nature for which reserves were created |                                |     |                                            
|                          |                                                       |                                |     |                                             
|Balance December 31, 2000 |                                                       |                                | 751 |                                             
|Additions:                |                                                       |                                |     |                                             
|                          | Charged to costs and expenses                         |                                |     | 9                                           
|Deductions:               |                                                       |                                |     |                                             
|                          | Net charges of nature for which reserves were created |                                |     | 630                                         
|                          |                                                       |                                |     |                                             
|Balance December 31, 2001 |                                                       | $                              | 130 |                                             
|                          |                                                       |                                |     |                                             

140

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SIGNATURESLOUISVILLE GAS AND ELECTRIC COMPANY

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

|                      |  | LOUISVILLE GAS AND ELECTRIC COMPANY
Registrant
|--------------------- |  | ----------------------------------------------
|(Date) March 28, 2002 |  | /s/S. BRADFORD RIVES                          
|                      |  | S. Bradford Rives                             

Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant 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);                |  |     
|*David J. Jackson      |  | Director;                                                                                   |  |     
|*Nicholas Baldwin      |  | Director;                                                                                   |  |     
|*Edmund Wallis         |  | Director.                                                                                   |  |     

|By: |  | /s/S. BRADFORD RIVES* |  |  |  |               
|--- |  | --------------------- |  |  |  | --------------
|    |  | (Attorney-In-Fact)    |  |  |  | March 28, 2002

141

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SIGNATURESKENTUCKY UTILITIES COMPANY

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

|                      |  | KENTUCKY UTILITIES COMPANY
Registrant
|--------------------- |  | -------------------------------------
|(Date) March 28, 2002 |  | /s/S. BRADFORD RIVES                 
|                      |  | S. Bradford Rives                    

Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant 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);                |  |     
|*David J. Jackson      |  | Director;                                                                                   |  |     
|*Nicholas Baldwin      |  | Director;                                                                                   |  |     
|*Edmund Wallis         |  | Director.                                                                                   |  |     

|By: |  | /s/S. BRADFORD RIVES* |  |  |  |               
|--- |  | --------------------- |  |  |  | --------------
|    |  | (Attorney-In-Fact)    |  |  |  | March 28, 2002

142

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