10-K/A

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549

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 registered
Preferred 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 Company
5% Cumulative Preferred Stock, $25 Par Value
$5.875 Cumulative Preferred Stock, Without Par Value
Auction Rate Series A Preferred Stock, Without Par Value
(Title of class)

Kentucky Utilities Company
Preferred Stock, 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.

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

(a)

Incorporated by reference.

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

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.

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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		30
Industrial			104,438			15,750		120,188		15
Public authorities			53,725			13,223		66,948		8
	Total retail		535,629			276,656		812,285		100	%
Wholesale sales			159,406			5,702		165,108
Gas transported—net			—			6,042		6,042
Provision for rate refunds			(720	)		—		(720	)
Miscellaneous			11,610			2,375		13,985
	Total	$	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			1999
ELECTRIC OPERATING REVENUES
(Thousands of $):
Residential		$	205,926		$	205,105		$	214,733
Commercial			171,540			171,414			176,457
Industrial			104,438			104,738			111,889
Public authorities			53,725			54,270			55,968
	Total retail		535,629			535,527			559,047
Wholesale sales			159,406			165,080			221,336
Provision for rate refunds			(720	)		(2,500	)		(1,735	)
Miscellaneous			11,610			12,851			12,022
	Total	$	705,925		$	710,958		$	790,670
ELECTRIC SALES (Thousands of Mwh):
Residential			3,782			3,722			3,680
Commercial			3,395			3,350			3,290
Industrial			2,976			3,043			3,047
Public authorities			1,224			1,214			1,187
	Total retail		11,377			11,329			11,204
Wholesale sales			6,957			6,834			8,428
	Total		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

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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.

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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		1999
GAS OPERATING REVENUES
(Thousands of $):
Residential		$	177,387	$	159,670	$	103,655
Commercial			70,296		61,888		38,627
Industrial			15,750		15,898		10,401
Public authorities			13,223		9,193		9,013
	Total retail		276,656		246,649		161,696
Wholesale sales			5,702		17,344		8,118
Gas transported—net			6,042		6,922		6,350
Miscellaneous			2,375		1,574		1,415
	Total	$	290,775	$	272,489	$	177,579
GAS SALES (Millions of cu. ft.):
Residential			20,429		24,274		21,565
Commercial			8,587		10,132		9,033
Industrial			2,160		3,089		2,781
Public authorities			1,681		1,576		2,228
	Total retail		32,857		39,071		35,607
Wholesale sales			1,882		5,115		3,881
Gas transported			13,108		14,729		14,014
	Total		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

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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

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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.

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

	2001			2000			1999
Per ton	$	21.27		$	20.96		$	21.49
Per Mmbtu	$	.93		$	.92		$	.95
Spot 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.

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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.

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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	$	242,304
Commercial			165,389			161,291		160,895
Industrial			146,968			153,017		154,460
Mine Power			28,196			27,089		28,792
Public authorities			58,770			57,979		58,500
	Total retail		643,327			641,159		644,951
Wholesale sales			203,181			198,073		286,595
Provision for rate refunds			(954	)		—		(5,900	)
Miscellaneous			13,918			12,709		11,664
	Total	$	859,472		$	851,941	$	937,310
ELECTRIC SALES (Thousands of Mwh):
Residential			5,678			5,714		5,447
Commercial			3,990			3,954		3,760
Industrial			4,716			5,044		4,911
Mine Power			771			767		752
Public authorities			1,481			1,495		1,437
	Total retail		16,636			16,974		16,307
Wholesale sales			7,713			7,573		10,188
	Total		24,349			24,547		26,495

        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

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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.

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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.

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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			1999
Per ton	$	27.84		$	25.63		$	26.65
Per Mmbtu	$	1.20		$	1.07		$	1.11
Spot 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.

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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.

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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

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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.

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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, KY
	Unit 1		303,000
	Unit 2		301,000
	Unit 3		386,000
	Unit 4		480,000
		Total Mill Creek	1,470,000
Cane Run—near Louisville, KY
	Unit 4		155,000
	Unit 5		168,000
	Unit 6		240,000
		Total Cane Run	563,000
Trimble County—Bedford, KY (a)
	Unit 1		371,000
Combustion Turbine Generators (Peaking capability):
Zorn			16,000
Paddy's Run (b)			127,000
Cane Run			16,000
Waterside			33,000
E.W. Brown (c)			195,000
	Total combustion turbine generators		387,000
	Total capability rating		2,791,000

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(a)

Amount shown represents LG&E's 75% interest in Trimble County. See Notes 12 and 13 of LG&E's Notes to Financial Statements, Jointly Owned Electric Utility Plant, under Item 8 for further discussion on ownership.

(b)

Amount shown represents LG&E's 53% interest in Paddy's Run Unit 13 and 100% ownership of two other Paddy's Run CTs. See Notes 12 and 13 of LG&E's Notes to Financial Statement, under item 8 for further discussion on ownership.

(c)

Amount shown represents LG&E's 38% interest in Units 6 and 7 and LG&E's 53% interest in Unit 5 at E.W. Brown. See Notes 12 and 13 of LG&E's Notes to Financial Statements, under Item 8 for further discussion on ownership.

        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		27,000
	Unit 2		31,000
	Unit 3		71,000
		Total Tyrone	129,000
Green River—South Carrollton, KY
	Unit 1		26,000
	Unit 2		27,000
	Unit 3		71,000
	Unit 4		103,000
		Total Green River	227,000

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E.W. Brown—Burgin, KY
	Unit 1		104,000
	Unit 2		168,000
	Unit 3		439,000
		Total E.W. Brown	711,000
Pineville—Four Mile, KY. (a)
	Unit 3		34,000
Ghent—Ghent, KY.
	Unit 1		483,000
	Unit 2		492,000
	Unit 3		493,000
	Unit 4		494,000
		Total Ghent	1,962,000
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	905,000
Total capability rating			3,968,000

(a)

Pineville Unit 3 has been taken out of active service as of January 31, 2002 and will be retired in 2002.

(b)

Amount shown represents KU's 62% interest in Units 6 and 7 at E.W. Brown, KU's 47% interest in Unit 5 at E.W. Brown and 100% of four other units. See Notes 11 and 12 of KU's Notes to Financial Statements, under Item 8 for further discussion on ownership.

(c)

Amount shown represents KU's 47% interest in Unit 13 at Paddy's Run. See Notes 11 and 12 of KU's Notes to Financial Statements, under item 8 for further discussion on ownership.

        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.

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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

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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.

a)

LG&E's and KU's Annual Meetings of Shareholders were held on December 19, 2001.



b)

Not Applicable



c)

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



1.

LG&E



i)

The shareholders voted to elect LG&E's nominees for election to the Board of Directors as follows:

        Sydney Gillibrand CBE—21,294,223 common shares and 125,955 preferred shares cast in favor of election and 4,118 preferred shares withheld.

        Nicholas P. Baldwin—21,294,223 common shares and 127,114 preferred shares cast in favor of election and 2,959 preferred shares withheld.

        Victor A. Staffieri—21,294,223 common shares and 126,596 preferred shares cast in favor of election and 3,477 preferred shares withheld.

        Edmund A. Wallis—21,294,223 common shares and 125,850 preferred shares cast in favor of election and 4,223 preferred shares withheld.

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        Dr. David K-P Li—21,294,223 common shares and 125,813 preferred shares cast in favor of election and 4,260 preferred shares withheld.

        Sir Frederick Crawford—21,294,223 common shares and 125,285 preferred shares cast in favor of election and 4,788 preferred shares withheld.

        David J. Jackson—21,294,223 common shares and 126,935 preferred shares cast in favor of election and 3,138 preferred shares withheld.

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

ii)

The shareholders voted 21,294,223 common shares and 126,532 preferred shares in favor of and 896 preferred shares against the approval of PricewaterhouseCoopers LLP as independent accountants for 2001. Holders of 2,645 preferred shares abstained from voting on this matter.

2.    KU

i)

The sole shareholder voted to elect KU's nominees for election to the Board of Directors as follows:

        37,817,878 common shares cast in favor of election and no shares withheld for each of Sydney Gillibrand CBE, Nicholas P. Baldwin, Victor A. Staffieri, Edmund A. Wallis, Dr. David K-P Li, Sir Frederick Crawford and David J. Jackson, respectively.

ii)

The sole shareholder voted 37,817,878 common shares in favor of and no shares withheld for approval of PricewaterhouseCoopers LLP as independent accountants for 2001.

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

d)

Not applicable.

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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		2000
First quarter	$	0	$	23,000
Second quarter		0		16,500
Third quarter		0		16,500
Fourth 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		2000
First quarter	$	0	$	19,000
Second quarter		0		25,000
Third quarter		0		25,000
Fourth quarter		30,500		25,500

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ITEM 6. Selected Financial Data.

		Years Ended December 31 (Thousands of $)
		2001			2000			1999			1998			1997
LG&E:
Operating revenues:
Revenues		$	997,420		$	985,947		$	969,984		$	854,556		$	845,543
Provision for rate refunds			(720	)		(2,500	)		(1,735	)		(4,500	)		—
	Total operating revenues		996,700			983,447			968,249			850,056			845,543
Net operating income			141,773			148,870			140,091			135,523			148,186
Net income:
Before unusual items			106,781			110,573			106,270			101,697			113,273
Merger costs			—			—			—			(23,577	)		—
Net income			106,781			110,573			106,270			78,120			113,273
Net income available for common stock			102,042			105,363			101,769			73,552			108,688
Total assets			2,448,354			2,226,084			2,171,452			2,104,637			2,055,641
Long-term obligations (including amounts due within one year)		$	616,904		$	606,800		$	626,800		$	626,800		$	646,800

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        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 $)
			2001			2000		1999			1998			1997
KU:
Operating revenues:
Revenues			$	860,426		$	851,941	$	943,210		$	831,614		$	716,437
Provision for rate refunds				(954	)		—		(5,900	)		(21,500	)		—
	Total operating revenues			859,472			851,941		937,310			810,114			716,437
Net operating income:
Before unusual items				125,465			128,136		136,016			125,388			118,408
Non-recurring charge				(4,095	)		—		—			—			—
	Net operating income			121,370			128,136		136,016			125,388			118,408
Net income:
Before unusual items				100,509			95,524		106,558			94,428			85,713
Non-recurring charge				(4,095	)		—		—			—			—
Merger costs				—			—		—			(21,664	)		—
		Net income		96,414			95,524		106,558			72,764			85,713
Net income available for common stock				94,158			93,268		104,302			70,508			83,457
Total assets				1,826,902			1,739,518		1,785,090			1,761,201			1,679,880
Long-term obligations (including amounts due within one year)			$	488,506		$	484,830	$	546,330		$	546,330		$	546,351

        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.

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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.

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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 Period
			Electric Revenues						Gas Revenues
Cause
			2001			2000			2001			2000
Retail sales:
	Fuel and gas supply adjustments, etc.		$	(394	)	$	(9,027	)	$	79,627		$	57,156
	LG&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			4,221
	Variation in sales volumes, etc.			4,429			5,759			(64,817	)		23,576
		Total retail sales		102			(23,520	)		30,007			84,953
	Wholesale sales			(5,674	)		(56,256	)		(11,642	)		9,226
	Gas transportation—net			—			—			(880	)		572
	Other			(1,241	)		829			801			159
		Total	$	(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

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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.

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        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 Electricity was 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 Combinations and SFAS No. 142, Goodwill and Other Intangible Assets were 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 Obligations and 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 Of and 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.

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        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	Fitch
First mortgage bonds	A1	A-	A+
Unsecured debt	A2	BBB	A
Preferred stock	a2	BBB-	A-
Commercial paper	P-1	A-2	F-1

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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
Contractual cash Obligations	2002		2003- 2004		2005- 2006		After 2006		Total
Long-term debt(a)	$	246,200	$	42,600	$	—	$	328,104	$	616,904
Operating leases		3,594		7,014		1,754		—		12,362
Unconditional purchase obligations(b)		12,805		25,997		26,518		201,164		266,484
Other long-term obligations(c)		112,900		10,000		—		—		122,900
Total contractual cash obligations	$	375,499	$	85,611	$	28,272	$	529,268	$	1,018,650

(a)

Long-term debt of $246.2 million is classified as current liabilities because these 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. Maturity dates for these bonds range from 2017 to 2027.

(b)

Represents future minimum payments under purchased power agreements through 2020.

(c)

Represents construction commitments.

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.

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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 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, and SFAS 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. 133 and SFAS No. 138 and 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		3,441
	Contracts 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 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.

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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.

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

        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

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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.

Environmental Cost Recovery

        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.

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, 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.

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.

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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 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.

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. 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

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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.

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. 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.

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 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.

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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. 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.

Environmental Matters

        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.

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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.

Deferred Income Taxes

        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

Competition and Customer Choice

        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.

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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

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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

Net Income

        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.

Revenues

        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 Period
Cause
			2001			2000
Retail sales:
	Fuel clause adjustments, etc.		$	10,220		$	6,893
	KU/LG&E Merger surcredit			(3,856	)		(2,327	)
	Environmental cost recovery surcharge			1,458			(4,994	)
	Performance based rate			1,747			3,439
	Electric rate reduction			(5,395	)		(28,343	)
	VDT surcredit			(372	)		—
	Variation in sales volumes, etc.			(1,627	)		20,187
		Total retail sales		2,175			(5,145	)
Wholesale sales				5,108			(88,522	)
Other				1,202			2,398
	Total		$	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.

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Expenses

        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).

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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

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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 Combinations and SFAS No. 142, Goodwill and Other Intangible Assets were 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 Obligations and 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 Of and 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.

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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.

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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	Fitch
First 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
Contractual cash Obligations	2002		2003- 2004		2005- 2006		After 2006		Total
Long-term debt (a)	$	54,000	$	62,000	$	36,000	$	332,830	$	484,830
Unconditional purchase obligations (b)		37,788		76,401		83,584		603,286		801,059
Other long-term obligations (c)		144,000		125,000		—		—		269,000
Total contractual cash obligations	$	235,788	$	263,401	$	119,584	$	936,116	$	1,554,889

(a)

Long-term debt of $54 million is classified as current liabilities because the bond is subject to tender for purchase at the option of the holder and to mandatory tender for purchase upon the occurrence of certain events. Maturity date for this bond is 2024.

(b)

Represents future minimum payments under purchased power agreements through 2020.

(c)

Represents construction commitments.

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.

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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 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, and SFAS 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. 133 and SFAS No. 138 and 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		3,441
	Contracts 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

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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.

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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.

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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,

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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

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,

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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.

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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

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

			Years Ended December 31
			2001			2000			1999
OPERATING REVENUES:
	Electric		$	706,645		$	713,458		$	792,405
	Gas			290,775			272,489			177,579
	Provision for rate refunds (Note 3)			(720	)		(2,500	)		(1,735	)
		Total operating revenues (Note 1)		996,700			983,447			968,249
OPERATING EXPENSES:
	Fuel for electric generation			159,231			159,418			159,129
	Power purchased			81,475			96,894			169,573
	Gas supply expenses			206,165			196,912			114,745
	Other operation expenses			167,818			135,943			154,667
	Maintenance			58,687			63,709			58,119
	Depreciation and amortization (Note 1)			100,356			98,291			97,221
	Federal and state income taxes (Note 8)			63,452			64,425			57,774
	Property and other taxes			17,743			18,985			16,930
		Total operating expenses		854,927			834,577			828,158
Net operating income				141,773			148,870			140,091
Other income—net (Note 9)				2,930			4,921			4,141
Interest charges				37,922			43,218			37,962
Net income				106,781			110,573			106,270
Preferred stock dividends				4,739			5,210			4,501
Net income available for common stock			$	102,042		$	105,363		$	101,769

Consolidated Statements of Retained Earnings
(Thousands of $)

		Years Ended December 31
		2001		2000		1999
Balance January 1		$	314,594	$	259,231	$	247,462
Add net income			106,781		110,573		106,270
			421,375		369,804		353,732
Deduct:	Cash dividends declared on stock:
	5% cumulative preferred		1,075		1,075		1,075
	Auction rate cumulative preferred		2,195		2,666		1,957
	$5.875 cumulative preferred		1,469		1,469		1,469
	Common		23,000		50,000		90,000
			27,739		55,210		94,501
Balance December 31		$	393,636	$	314,594	$	259,231

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

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

	Years Ended December 31
	2001			2000		1999
Net income	$	106,781		$	110,573	$	106,270
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		—			—		(402	)
Income tax benefit related to items of other comprehensive income		13,416			—		163
Comprehensive income	$	86,881		$	110,573	$	106,031

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

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

			December 31
			2001		2000
ASSETS:
Utility plant, at original cost (Note 1):
	Electric		$	2,598,152	$	2,459,206
	Gas			409,994		389,371
	Common			159,817		148,530
				3,167,963		2,997,107
	Less: reserve for depreciation			1,381,874		1,296,865
				1,786,089		1,700,242
	Construction work in progress			255,074		189,218
				2,041,163		1,889,460
Other property and investments—less reserve				1,176		1,357
Current assets:
	Cash and temporary cash investments			2,112		2,495
	Marketable securities (Note 6)			—		4,056
	Accounts receivable—less reserve of $1,575 in 2001 and $1,286 in 2000			85,667		170,852
	Materials and supplies—at average cost:
		Fuel (predominantly coal)		22,024		9,325
		Gas stored underground (Note 1)		46,395		54,441
		Other		29,050		31,685
	Prepayments and other			4,688		1,317
				189,936		274,171
Deferred debits and other assets:
	Unamortized debt expense (Note 1)			5,921		5,784
	Regulatory assets (Note 3)			197,142		54,439
	Other			13,016		873
				216,079		61,096
			$	2,448,354	$	2,226,084
CAPITAL AND LIABILITIES:
Capitalization (see statements of capitalization):
	Common equity		$	838,070	$	778,928
	Cumulative preferred stock			95,140		95,140
	Long-term debt (Note 10)			370,704		360,600
				1,303,914		1,234,668
Current liabilities:
	Current portion of long-term debt (Note 10)			246,200		246,200
	Notes payable (Note 11)			94,197		114,589
	Accounts payable			149,070		134,392
	Accrued taxes			20,257		8,073
	Accrued interest			5,818		6,350
	Other			12,840		19,693

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			528,382		529,297
Deferred credits and other liabilities:
	Accumulated deferred income taxes (Notes 1 and 8)		298,143		289,232
	Investment tax credit, in process of amortization		58,689		62,979
	Accumulated provision for pensions and related benefits (Note 7)		167,526		31,257
	Customers' advances for construction		9,745		9,578
	Regulatory liabilities (Note 3)		65,349		61,013
	Other		16,606		8,060
			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.

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

			Years Ended December 31
			2001			2000			1999
CASH FLOWS FROM OPERATING ACTIVITIES:
	Net income		$	106,781		$	110,573		$	106,270
	Items not requiring cash currently:
		Depreciation and amortization		100,356			98,291			97,221
		Deferred income taxes—net		3,021			31,020			(5,279	)
		Investment tax credit—net		(4,290	)		(4,274	)		(4,289	)
		Other		(528	)		8,481			6,924
	Change in certain net current assets:
		Accounts receivable		43,185			(56,993	)		28,721
		Materials and supplies		(2,018	)		(4,311	)		(559	)
		Accounts payable		14,678			21,384			(20,665	)
		Accrued taxes		12,184			(15,686	)		(8,170	)
		Accrued interest		(532	)		(2,915	)		1,227
		Prepayments and other		(9,968	)		(4,901	)		(4,306	)
	Sale of accounts receivable (Note 1)			42,000			—			—
	Other			(17,806	)		(24,431	)		(16,602	)
		Net cash flows from operating activities		287,063			156,238			180,493
CASH FLOWS FROM INVESTING ACTIVITIES:
	Purchases of securities			—			(708	)		(1,144	)
	Proceeds from sales of securities			4,237			4,089			11,662
	Construction expenditures			(252,958	)		(144,216	)		(194,644	)
		Net cash flows used for investing activities		(248,721	)		(140,835	)		(184,126	)
CASH FLOWS FROM FINANCING ACTIVITIES:
	Short-term borrowings and repayments			(20,392	)		(5,508	)		120,097
	Issuance of pollution control bonds			9,662			106,545			—
	Retirement of first mortgage bonds and pollution control bonds			—			(130,627	)		—
	Additional paid-in capital			—			40,000			—
	Payment of dividends			(27,995	)		(78,079	)		(93,433	)
		Net cash flows from financing activities		(38,725	)		(67,669	)		26,664
Change in cash and temporary cash investments				(383	)		(52,266	)		23,031
Cash and temporary cash investments at beginning of year				2,495			54,761			31,730
Cash and temporary cash investments at end of year			$	2,112		$	2,495		$	54,761
Supplemental disclosures of cash flow information:
	Cash paid during the year for:
		Income taxes	$	35,546		$	46,562		$	76,761
		Interest on borrowed money		30,989			42,958			33,507

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

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

		December 31
		2001			2000
COMMON EQUITY:
	Common stock, without par value—     Authorized 75,000,000 shares, outstanding 21,294,223 shares	$	425,170		$	425,170
	Common stock expense		(836	)		(836	)
	Additional paid-in capital		40,000			40,000
	Accumulated other comprehensive income		(19,900	)		—
	Retained earnings		393,636			314,594
			838,070			778,928

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			21,507
	Without par value, 6,750,000 shares     authorized—Auction rate				500,000		100.00		50,000			50,000
	$5.875 series				250,000		102.35		25,000			25,000
	Preferred stock expense								(1,367	)		(1,367	)
									95,140			95,140
LONG-TERM DEBT (Note 10):
	First mortgage bonds—     Series due August 15, 2003, 6%								42,600			42,600
		Pollution control series:
			R due November 1, 2020, 6.55%						41,665			41,665
			S due September 1, 2017, variable						31,000			31,000
			T due September 1, 2017, variable						60,000			60,000
			U due August 15, 2013, variable						35,200			35,200
			V due August 15, 2019, 5 5/8%						102,000			102,000
			W due October 15, 2020, 5.45%						26,000			26,000
			X due April 15, 2023, 5.90%						40,000			40,000
			Y due May 1, 2027, variable						25,000			25,000
			Z due August 1, 2030, variable						83,335			83,335
			AA due September 1, 2027, variable						10,104			—
				Total first mortgage bonds					496,904			486,800
	Pollution control bonds (unsecured)—
		Series due September 1, 2026, variable							22,500			22,500
		Series due September 1, 2026, variable							27,500			27,500
		Series due November 1, 2027, variable							35,000			35,000
		Series due November 1, 2027, variable							35,000			35,000
			Total unsecured pollution control bonds						120,000			120,000
		Total bonds outstanding							616,904			606,800
		Less current portion of long-term debt							246,200			246,200
		Long-term debt							370,704			360,600
		Total capitalization						$	1,303,914		$	1,234,668

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

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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 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. Management has not determined the impact this issue will have on its results of operations and financial position.

        SFAS No. 141, Business Combinations and SFAS No. 142, Goodwill and Other Intangible Assets were 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 Obligations and 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 Of and 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			2000
VDT Costs	$	127,529		$	—
Gas supply adjustments due from customers		30,135			12,324
Unamortized loss on bonds		17,902			19,036
LGE/KU merger costs		5,444			9,073
Manufactured gas sites		2,062			2,368
One utility costs		3,643			6,331
Other		10,427			5,307
Total regulatory assets		197,142			54,439
Deferred 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
		Cost		Fair Value			Cost		Fair Value
Marketable securities		$	—	$	—		$	4,403	$	4,056
Long-term investments—
	Not practicable to estimate fair value		490		490			564		564
Preferred stock subject to mandatory redemption			25,000		25,125			25,000		25,275
Long-term debt (including current portion)			616,904		620,504			606,800		606,236
Interest-rate swaps			—		(8,604	)		—		(5,998	)

        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, and SFAS 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. 133 and SFAS No. 138 and 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:		Equity
Cost		$	4,403
Realized losses			(347	)
Fair values		$	4,056
Fair values:
	No maturity	$	4,056
	Total 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		$	311,935
	Service cost		1,311			3,408			5,005
	Interest cost		25,361			22,698			21,014
	Plan amendments		1,550			17,042			(2,397	)
	Curtailment loss		24,563			—			—
	Special termination benefits		53,610			—			—
	Benefits paid		(53,292	)		(16,656	)		(15,471	)
	Actuarial (gain) or loss and other		(7,632	)		1,063			(36,819	)
	Benefit obligation at end of year	$	356,293		$	310,822		$	283,267
Change in plan assets
	Fair value of plan assets at beginning of year	$	333,378		$	360,095		$	308,660
	Actual return on plan assets		(27,589	)		(6,150	)		51,995
	Employer contributions and plan transfers		(17,134	)		(1,804	)		16,142
	Benefits paid		(53,292	)		(16,656	)		(15,471	)
	Administrative expenses		(1,419	)		(2,107	)		(1,231	)
	Fair value of plan assets at end of year	$	233,944		$	333,378		$	360,095
Reconciliation of funded status
	Funded status	$	(122,349	)	$	22,556		$	76,828
	Unrecognized actuarial (gain) or loss		18,800			(74,086	)		(126,554	)
	Unrecognized transition (asset) or obligation		(4,215	)		(5,853	)		(6,965	)
	Unrecognized prior service cost		35,435			47,984			35,588
	Net amount recognized at end of year	$	(72,329	)	$	(9,399	)	$	(21,103	)
Other Benefits:
Change in benefit obligation
	Benefit obligation at beginning of year	$	56,981		$	44,997		$	44,964
	Service cost		358			822			1,205
	Interest cost		5,865			4,225			3,270
	Plan amendments		1,487			5,826			2,377
	Curtailment loss		8,645			—			—
	Special termination benefits		18,089			—			—
	Benefits paid		(4,877	)		(4,889	)		(3,050	)
	Actuarial (gain) or loss		3,398			6,000			(3,769	)
	Benefit obligation at end of year	$	89,946		$	56,981		$	44,997
Change in plan assets
	Fair value of plan assets at beginning of year	$	7,166		$	10,526		$	6,062
	Actual return on plan assets		(765	)		(92	)		1,776
	Employer contributions and plan transfers		1,282			1,621			4,681
	Benefits paid		(4,881	)		(4,889	)		(1,993	)
	Fair value of plan assets at end of year	$	2,802		$	7,166		$	10,526

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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		$	6,466
	Accrued benefit liability		(108,977	)		(28,279	)		(27,569	)
	Intangible asset		11,936			—			—
	Accumulated other comprehensive income		24,712			—			—
	Net amount recognized at year-end	$	(72,329	)	$	(9,399	)	$	(21,103	)
Additional year-end information for plans with accumulated benefit obligations in excess of plan assets(1):
	Projected benefit obligation	$	356,293		$	4,088		$	4,845
	Accumulated benefit obligation		352,477			3,501			4,327
	Fair value of plan assets		233,944			—			—

(1)

2001 includes all plans. 2000 and 1999 include SERPs only.

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

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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	$	1,311		$	3,408		$	5,005
	Interest cost		25,361			22,698			21,014
	Expected return on plan assets		(26,360	)		(33,025	)		(28,946	)
	Amortization of prior service cost		3,861			4,646			3,462
	Amortization of transition (asset) or obligation		(1,000	)		(1,112	)		(1,112	)
	Recognized actuarial (gain) or loss		(777	)		(6,856	)		(2,621	)
	Net periodic benefit cost	$	2,396		$	(10,241	)	$	(3,198	)
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		$	1,205
	Interest cost		5,865			4,225			3,270
	Expected return on plan assets		(420	)		(683	)		(401	)
	Amortization of prior service cost		951			1,158			473
	Amortization of transition (asset) or obligation		719			1,114			1,114
	Recognized actuarial gain		(32	)		(485	)		(183	)
	Net periodic benefit cost	$	7,441		$	6,151		$	5,478
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.

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        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% Increase
Effect on total of service and interest cost components for 2001	$	(189	)	$	212
Effect 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		$	53,981
		—	state		8,668			5,018			13,680
	Deferred	—	federal—net		12,310			24,272			(4,818	)
		—	state—net		3,767			6,797			(780	)
Amortization of investment tax credit					(4,290	)		(4,274	)		(4,289	)
	Total				63,452			64,425			57,774
Included in other income—net:
	Current	—	federal		(1,870	)		(2,187	)		217
		—	state		(483	)		(568	)		(30	)
	Deferred	—	federal—net		285			(39	)		254
		—	state—net		73			(10	)		65
	Total				(1,995	)		(2,804	)		506
Total income tax expense				$	61,457		$	61,621		$	58,280

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

		2001		2000
Deferred tax liabilities:
Depreciation and other plant-related items		$	334,914	$	329,836
Other liabilities			77,611		22,621
			412,525		352,457
Deferred tax assets:
	Investment tax credit		23,713		25,444
	Income taxes due to customers		19,709		22,086
	Pension overfunding		6,621		5,595
	Accrued liabilities not currently deductible and other		64,339		10,100
			114,382		63,225
Net 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		1999
Statutory federal income tax rate	35.0	%	35.0	%	35.0	%
State income taxes, net of federal benefit	4.7		4.3		5.1
Amortization 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		1999
Interest and dividend income	$	748	$	3,103	$	4,086
Gains on fixed asset disposals		1,217		1,014		2,394
Income 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	$	370,704
Current portion (pollution control bonds)	Variable	2.33	%	2013-2027		246,200

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        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	$	3,594
2003		3,507
2004		3,507
2005		1,754
Total	$	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.

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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	$	12,805
2003		12,934
2004		13,063
2005		13,193
2006		13,325
Total	$	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.

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        The following data represent shares of the jointly owned property:

	Trimble County
	LG&E			IMPA		IMEA		Total
Ownership interest		75	%	12.88	%	12.12	%	100	%
Mw capacity		371.25		63.75		60.00		495.00
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			TOTAL
Paddy's Run 13	Ownership %		53	%		47	%		100	%
	Mw capacity		84			74			158
	Cost	$	33,844		$	29,908		$	63,752
	Depreciation		563			491			1,054
	Net book Value	$	33,281		$	29,417		$	62,698
E.W. Brown 5	Ownership %		53	%		47	%		100	%
	Mw capacity		70			63			133
	Cost	$	23,941		$	21,078		$	45,019
	Depreciation		394			342			736
	Net book Value	$	23,547		$	20,736		$	44,283
E.W. Brown 6	Ownership %		38	%		62	%		100	%
	Mw capacity		62			102			164
	Cost	$	23,696		$	36,253		$	59,949
	Depreciation		953			2,955			3,908
	Net book Value	$	22,743		$	33,298		$	56,041
E.W. Brown 7	Ownership %		38	%		62	%		100	%
	Mw capacity		62			102			164
	Cost	$	23,607		$	44,785		$	68,392
	Depreciation		3,268			3,033			6,301
	Net 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		Total
2001
Operating revenues	$	705,925	(a)	$	290,775	$	996,700
Depreciation and amortization		85,572			14,784		100,356
Interest income		616			132		748
Interest expense		31,295			6,627		37,922
Operating income taxes		55,527			7,925		63,452
Net income		94,996			11,768		106,764
Total assets		1,985,252			463,102		2,448,354
Construction expenditures		227,107			25,851		252,958
2000
Operating revenues	$	710,958	(b)	$	272,489	$	983,447
Depreciation and amortization		84,761			13,530		98,291
Interest income		2,551			552		3,103
Interest expense		35,604			7,614		43,218
Operating income taxes		57,869			6,556		64,425
Net income		100,395			10,178		110,573
Total assets		1,760,305			465,779		2,226,084
Construction expenditures		109,798			34,418		144,216
1999
Operating revenues	$	790,670	(c)	$	177,579	$	968,249
Depreciation and amortization		83,619			13,602		97,221
Interest income		3,435			651		4,086
Interest expense		31,558			6,404		37,962
Operating income taxes		56,883			891		57,774
Net income		104,853			1,417		106,270
Total assets		1,775,498			395,954		2,171,452
Construction expenditures		160,844			33,800		194,644

(a)

Net of provision for rate refunds of $.7 million.


(b)

Net of provision for rate refunds of $2.5 million.


(c)

Net of provision for rate refunds of $1.7 million.

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 Ended
	March			June		September		December
	(Thousands of $)
2001
Operating revenues	$	313,271		$	228,841	$	231,885	$	222,703
Net operating income (loss)		(43,732	)		37,624		49,092		98,789
Net income (loss)		(54,115	)		28,467		40,270		92,159
Net income (loss) available for common stock		(55,413	)		27,247		39,160		91,048
2000
Operating revenues	$	249,642		$	209,731	$	229,640	$	294,434
Net operating income		26,592			37,285		48,161		36,832
Net income		17,421			28,009		38,117		27,026
Net income available for common stock		16,256			26,692		36,756		25,659

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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 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

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

			Years Ended December 31
			2001			2000		1999
OPERATING REVENUES:
	Electric (Note 1)		$	860,426		$	851,941	$	943,210
	Provision for rate refunds (Note 3)			(954	)		—		(5,900	)
		Total operating revenues		859,472			851,941		937,310
OPERATING EXPENSES:
	Fuel for electric generation			236,985			219,923		219,883
	Power purchased			157,161			166,918		242,315
	Other operation expenses			118,359			108,072		116,521
	Non-recurring charge (Note 3)			6,867			—		—
	Maintenance			57,021			61,643		57,318
	Depreciation and amortization (Note 1)			90,299			98,256		89,922
	Federal and state income taxes (Note 7)			57,482			51,963		60,380
	Property and other taxes			13,928			17,030		14,955
		Total operating expenses		738,102			723,805		801,294
Net operating income				121,370			128,136		136,016
Other income — net (Note 8)				8,932			6,843		9,437
Interest charges				34,024			39,455		38,895
Net income before cumulative effect of a change in accounting principle				96,278			95,524		106,558
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			95,524		106,558
Preferred stock dividends				2,256			2,256		2,256
Net income available for common stockholders			$	94,158		$	93,268	$	104,302

Consolidated Statements of Retained Earnings
(Thousands of $)

	Years Ended December 31
	2001		2000		1999
Balance January 1	$	347,238	$	329,470	$	299,167
Add net income		96,414		95,524		106,558
		443,652		424,994		405,725

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

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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
	2001			2000		1999
Net income	$	96,414		$	95,524	$	106,558
Cumulative effect of change in accounting principle — Accounting for derivative instruments and hedging activities (Note 1)		2,647			—		—
Income tax expense related to items of other comprehensive income		(1,059	)		—		—
Comprehensive income	$	98,002		$	95,524	$	106,558

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

			December 31
			2001		2000
ASSETS:
Utility plant, at original cost (Note 1)			$	2,960,818	$	2,826,383
Less: reserve for depreciation				1,457,754		1,378,283
				1,503,064		1,448,100
Construction work in progress				103,402		106,380
				1,606,466		1,554,480
Other property and investments—less reserve				9,629		14,538
Current assets:
	Cash and temporary cash investments			3,295		314
	Accounts receivable-less reserve of $800 in 2001 and 2000			45,291		90,419
	Materials and supplies—at average cost:
		Fuel (predominantly coal)		43,382		12,495
		Other		26,188		25,812
	Prepayments and other			4,942		1,899
				123,098		130,939
Deferred debits and other assets:
	Unamortized debt expense (Note 1)			4,316		4,651
	Regulatory assets (Note 3)			66,467		26,441
	Other			16,926		8,469
				87,709		39,561
			$	1,826,902	$	1,739,518
CAPITAL AND LIABILITIES:
Capitalization (see statements of capitalization):
	Common equity		$	735,029	$	669,783
	Cumulative preferred stock			40,000		40,000
	Long-term debt (Note 9)			434,506		430,830
				1,209,535		1,140,613
Current liabilities:
	Current portion of long-term debt (Note 9)			54,000		54,000
	Notes payable to parent (Note 10)			47,790		61,239
	Accounts payable			85,149		76,339
	Accrued taxes			20,520		19,622
	Accrued interest			5,668		6,373
	Other			16,482		18,767
				229,609		236,340
Deferred credits and other liabilities:
	Accumulated deferred income taxes (Notes 1 and 7)			239,204		246,680
	Investment tax credit, in process of amortization			11,455		14,901
	Accumulated provision for pensions and related benefits (Note 6)			91,235		47,495
	Customers' advances for construction			1,526		1,540
	Regulatory liabilities (Note 3)			33,889		38,392
	Other			10,449		13,557
				387,758		362,565
Commitments and contingencies (Note 11)
			$	1,826,902	$	1,739,518

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

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

			Years Ended December 31
			2001			2000			1999
CASH FLOWS FROM OPERATING ACTIVITIES:
	Net income		$	96,414		$	95,524		$	106,558
	Items not requiring cash currently:
		Depreciation and amortization		90,299			98,256			89,922
		Deferred income taxes—net		(12,088	)		(2,449	)		(3,763	)
		Investment tax credit—net		(3,446	)		(3,674	)		(3,727	)
		Other		11,776			(8,136	)		(8,010	)
	Change in certain net current assets and liabilities:
		Accounts receivable		28			(1,870	)		17,576
		Materials and supplies		(31,263	)		18,131			(8,263	)
		Accounts payable		8,810			(40,207	)		6,514
		Provision for rate refunds		—			(20,567	)		(933	)
		Accrued taxes		898			9,120			(6,231	)
		Accrued interest		(705	)		(956	)		(781	)
		Prepayments and other		(5,328	)		1,806			(3,042	)
	Sale of accounts receivable (Note 1)			45,100			—			—
	Other			(12,364	)		31,272			18,356
		Net cash flows from operating activities		188,131			176,250			204,176
CASH FLOWS FROM INVESTING ACTIVITIES:
	Proceeds from sales of securities			3,480			—			—
	Construction expenditures			(142,425	)		(100,328	)		(181,135	)
		Net cash flows used for investing activities		(138,945	)		(100,328	)		(181,135	)
CASH FLOWS FROM FINANCING ACTIVITIES:
	Short-term borrowings and repayments			(13,449	)		61,239			—
	Retirement of long-term debt			—			(74,784	)		—
	Issuance of long-term debt			—			12,900			—
	Additional paid-in capital			—			15,000			—
	Payment of dividends			(32,756	)		(96,756	)		(75,197	)
		Net cash flows used for financing activities		(46,205	)		(82,401	)		(75,197	)
Change in cash and temporary cash investments				2,981			(6,479	)		(52,156	)
Cash and temporary cash investments at beginning of year				314			6,793			58,949
Cash and temporary cash investments at end of year			$	3,295		$	314		$	6,793
Supplemental disclosures of cash flow information:
	Cash paid during the year for:
		Income taxes	$	72,432		$	49,871		$	71,258
		Interest on borrowed money		39,829			35,196			35,508

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

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

			December 31
			2001			2000
COMMON EQUITY:
	Common stock, without par value—
		outstanding 37,817,878 shares	$	308,140		$	308,140
	Additional paid-in-capital			15,000			15,000
	Retained earnings			410,896			347,238
	Accumulated other comprehensive income			1,588			—
	Other			(595	)		(595	)
				735,029			669,783

CUMULATIVE PREFERRED STOCK:

				Shares Outstanding	Current Redemption Price
	Without par value, 5,300,000 shares     authorized—
		4.75% series, $100 stated     value
			Redeemable on 30 days notice by KU	200,000	$101.00		20,000		20,000
		6.53% series, $100 stated value		200,000	Not redeemable		20,000		20,000
							40,000		40,000
LONG-TERM DEBT—first mortgage     bonds (Note 9):
	Q due June 15, 2003, 6.32%						62,000		62,000
	S due January 15, 2006, 5.99%						36,000		36,000
	P due May 15, 2007, 7.92%						53,000		53,000
	R due June 1, 2025, 7.55%						50,000		50,000
	P due May 15, 2027, 8.55%						33,000		33,000
	Pollution control series:
		1B due February 1, 2018, 6.25%					20,930		20,930
		2B due February 1, 2018, 6.25%					2,400		2,400
		3B due February 1, 2018, 6.25%					7,200		7,200
		4B due February 1, 2018, 6.25%					7,400		7,400
		8, due September 15, 2016, 7.45%					96,000		96,000
		9, due December 1, 2023, 5.75%					50,000		50,000
		10, due November 1, 2024, variable					54,000		54,000
		A, due May 1, 2023, variable					12,900		12,900
	Long-term debt marked to market     (Note 4)						3,676		—
		Total bonds outstanding					488,506		484,830
		Less current portion of long-term     debt					54,000		54,000
		Long-term debt					434,506		430,830
		Total capitalization				$	1,209,535	$	1,140,613

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

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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 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. Management has not determined the impact this issue will have on its results of operations and financial position.

        SFAS No. 141, Business Combinations and SFAS No. 142, Goodwill and Other Intangible Assets were 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 Obligations and. 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 Of and 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			7,011
LG&E/KU merger costs		6,139			10,232
One utility costs		4,365			8,273
Other		1,010			925
Total regulatory assets		66,467			26,441
Deferred income taxes—net		(32,872	)		(37,484	)
Other		(1,017	)		(908	)
Total regulatory liabilities		(33,889	)		(38,392	)
Regulatory assets/(liabilities)—net	$	32,578		$	(11,951	)

        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

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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.

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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				2000
	Cost		Fair Value		Cost		Fair Value
Long-term debt (including current portion)	$	484,830	$	499,618	$	484,830	$	491,277
Interest-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, and SFAS 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. 133 and SFAS No. 138 and 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-

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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			1999
Pension Plans:
Change in benefit obligation
	Benefit obligation at beginning of year	$	233,034		$	219,628		$	233,288
	Service cost		2,761			4,312			6,210
	Interest cost		17,534			17,205			15,564
	Plan 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		$	219,628
Change in plan assets
	Fair value of plan assets at beginning of year	$	244,677		$	274,109		$	238,124
	Actual return on plan assets		18,155			(10,943	)		49,883
	Employer 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		$	274,109
Reconciliation of funded status
	Funded status	$	(27,525	)	$	11,643		$	54,481
	Unrecognized 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			3,564
	Net amount recognized at end of year	$	(37,743	)	$	(11,463	)	$	(17,522	)

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Other Benefits:
Change in benefit obligation
	Benefit obligation at beginning of year	$	64,213		$	54,201		$	79,650
	Service cost		495			757			1,596
	Interest cost		5,433			4,781			3,837
	Plan 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		$	54,201
Change in plan assets
	Fair value of plan assets at beginning of year	$	23,762		$	28,720		$	24,337
	Actual return on plan assets		(4,404	)		(1,162	)		5,322
	Employer contributions and plan transfers		473			522			3,520
	Benefits paid net of retiree contributions		(5,501	)		(4,318	)		(4,459	)
	Fair value of plan assets at end of year	$	14,330		$	23,762		$	28,720
Reconciliation of funded status
	Funded 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			23,694
	Unrecognized 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	)	$	(17,522	)
Additional year-end information for plans with accumulated benefit obligations in excess of plan assets (1):
	Projected benefit obligation	$	244,472		$	1,505		$	1,132
	Accumulated benefit obligation		224,261			336			40
	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	)	$	(30,763	)
Additional year-end information for plans with benefit obligations in excess of plan assets:
	Projected benefit obligation	$	83,223		$	64,213		$	54,201
	Fair value of plan assets		14,330			23,762			28,720

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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		$	6,211
	Interest cost		17,534			17,205			15,564
	Expected return on plan assets		(19,829	)		(25,170	)		(21,957	)
	Amortization of transition (asset) or obligation		(136	)		(141	)		(141	)
	Amortization of prior service cost		962			1,145			410
	Recognized actuarial (gain) or loss		(120	)		(3,410	)		(319	)
	Net periodic benefit cost	$	1,172		$	(6,059	)	$	(232	)
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		$	1,596
	Interest cost		5,433			4,781			3,837
	Expected return on plan assets		(1,313	)		(1,768	)		(1,897	)
	Amortization of prior service cost		740			1,018			—
	Amortization of transition (asset) or obligation		1,193			1,823			1,823
	Recognized actuarial (gain) or loss		(40	)		(820	)		(445	)
	Net periodic benefit cost	$	6,508		$	5,791		$	4,914
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		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.

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        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% Increase
Effect on total of service and interest cost components for 2001	$	(340	)	$	385
Effect 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		$	50,969
			—	state		13,465			9,333			13,459
	Deferred		—	federal—net		(12,980	)		(3,254	)		(4,833	)
			—	state—net		(1,340	)		957			785
		Total				57,482			51,963			60,380
Included in other income—net:
	Current		—	federal		(948	)		349			1,028
			—	state		(268	)		67			54
	Deferred		—	federal—net		863			(122	)		182
			—	state—net		222			(30	)		102
	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

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

		2001		2000
Deferred tax liabilities:
	Depreciation and other plant-related items	$	269,752	$	279,047
Other liabilities			33,376		13,718
			303,128		292,765
Deferred tax assets:
	Investment tax credit		4,623		6,014
	Income taxes due to customers		13,263		15,124
	Pension overfunding		4,595		3,974
	Accrued liabilities not currently deductible and other		41,443		20,973
			63,924		46,085
Net 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		1999
Statutory federal income tax rate	35.0	%	35.0	%	35.0	%
State income taxes, net of federal benefit	5.4		4.9		5.7
Amortization 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		1999
Equity in earnings—subsidiary company	$	1,803	$	2,242	$	2,334
Interest and dividend income		1,368		1,206		4,293
Gains on fixed asset disposals		1,844		5		759
Income taxes and other		3,917		3,390		2,051
Other 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	2003-2027
Noncurrent portion	$434,506
Current portion	$54,000

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        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

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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

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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	$	37,788
2003		34,665
2004		41,736
2005		41,777
2006		41,807
Total	$	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	%		100	%
	Mw capacity		84			74			158
	Cost	$	33,844		$	29,908		$	63,752
	Depreciation		563			491			1,054
	Net book Value	$	33,281		$	29,417		$	62,698
E.W. Brown 5	Ownership %		53	%		47	%		100	%
	Mw capacity		70			63			133
	Cost	$	23,941		$	21,078		$	45,019
	Depreciation		394			342			736
	Net book Value	$	23,547		$	20,736		$	44,283
E.W. Brown 6	Ownership %		38	%		62	%		100	%
	Mw capacity		62			102			164
	Cost	$	23,696		$	36,253		$	59,949
	Depreciation		953			2,955			3,908
	Net book Value	$	22,743		$	33,298		$	56,041
E.W. Brown 7	Ownership %		38	%		62	%		100	%
	Mw capacity		62			102			164
	Cost	$	23,607		$	44,785		$	68,392
	Depreciation		3,268			3,033			6,301
	Net book Value	$	20,339		$	41,752		$	62,091

        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
	March			June		September		December
	(Thousands of $)
2001
Revenues	$	211,793		$	219,360	$	216,370	$	211,949
Operating income (loss)		(344	)		28,422		30,253		63,039
Net income (loss)		(7,995	)		22,080		26,340		55,989
Net income (loss) available for common stock		(8,559	)		21,516		25,776		55,425
2000
Revenues	$	217,778		$	205,324	$	215,984	$	212,855
Operating income		28,753			28,912		37,161		33,310
Net income		20,174			21,532		28,483		25,335
Net income available for common stock		19,610			20,968		27,919		24,771

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

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

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

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

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

2.	Financial Statement Schedules (included in Part IV):
	Schedule II	Valuation and Qualifying Accounts for the three years ended December 31, 2001, for LG&E (page 138), and KU (page 140).
	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
			Description
Exhibit No.	LG&E	KU
2.01	x	x	Copy of Agreement and Plan of Merger, dated as of February 27, 2000, by and among Powergen plc, LG&E Energy Corp., US Subholdco2 and Merger Sub, including certain exhibits thereto. [Filed as Exhibit 1 to LG&E's and KU's Current Report on Form 8-K filed February 29, 2000 and incorporated by reference herein]
2.02	x	x	Amendment No. 1 to Agreement and Plan of merger, dated as of December 8, 2000, among LG&E Energy Corp., Powergen plc, Powergen US Investments Corp. and Powergen Acquisition Corp. [Filed as Exhibit 2.01 to LG&E's and KU's Current Report on Form 8-K filed December 11, 2000 and incorporated by reference herein]
2.03	x	x	Copy of Agreement and Plan of Merger, dated as of May 20, 1997, by and between LG&E Energy and KU Energy, including certain exhibits thereto. [Filed as Exhibit 2 to LG&E's and KU's Current Report on Form 8-K filed May 30, 1997 and incorporated by reference herein]
3.01	x		Copy of Restated Articles of Incorporation of LG&E, dated November 6, 1996. [Filed as Exhibit 3.06 to LG&E Quarterly Report on Form 10-Q for the quarter ended September 30, 1996, and incorporated by reference herein]
3.02	x		Copy of By-Laws of LG&E, as amended through June 2, 1999 [Filed as Exhibit 3.02 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1999, and incorporated by reference herein]
3.03		x	Copy of Amended and Restated Articles of Incorporation of KU [Filed as Exhibits 4.03 and 4.04 to Form 8-K Current Report of KU, dated December 10, 1993, and incorporated by reference herein]
3.04		x	Copy of By-laws of KU, as amended through June 2, 1999. [Filed as Exhibit 3.04 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1999, and incorporated by reference herein]
4.01	x		Copy of Trust Indenture dated November 1, 1949, from LG&E to Harris Trust and Savings Bank, Trustee. [Filed as Exhibit 7.01 to LG&E's Registration Statement 2-8283 and incorporated by reference herein]
4.02	x		Copy of Supplemental Indenture dated February 1, 1952, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.05 to LG&E's Registration Statement 2-9371 and incorporated by reference herein]

122

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

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

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

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

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

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

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

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

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

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

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.

(b)

Executive Compensation Plans and Arrangements:

Exhibits preceded by an asterisk ("*") above are management contracts, compensation plans or arrangements required to be filed as an exhibit pursuant to Item 14(c) of Form 10-K.

135

(c)

Reports on Form 8-K:

On May 7, 2001, a report on Form 8-K was filed announcing a change in certifying accountants.

On February 21, 2002, a report on Form 8-K was filed announcing LG&E and KU's financial results for year ended December 31, 2001.

There were no Form 8-K filings during the fourth quarter of 2001.

(d)

The following instruments defining the rights of holders of certain long- term debt of KU have not been filed with the Securities and Exchange Commission but will be furnished to the Commission upon request.

1.

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

2.

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

3.

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

4.

Loan Agreement dated as of August 1, 1992 between KU and the County of Muhlenberg, Kentucky, in connection with $7,200,000 County of Muhlenberg, Kentucky, Collateralized Pollution Control Revenue Bonds (KU Project) 1992 Series A, due February 1, 2018.

5.

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

6.

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

7.

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

8.

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

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

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	$	1,399
Additions:
	Charged to costs and expenses		—		1,925
Deductions:
	Net charges of nature for which reserves were created		—		2,091
Balance December 31, 1999			63		1,233
Additions:
	Charged to costs and expenses		—		2,803
Deductions:
	Net charges of nature for which reserves were created		—		2,750
Balance December 31, 2000			63		1,286
Additions:
	Charged to costs and expenses		—		4,953
Deductions:
	Net charges of nature for which reserves were created		—		4,664
Balance December 31, 2001		$	63	$	1,575

138

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	$	520
Additions:
	Charged to costs and expenses		111		1,707
Deductions:
	Net charges of nature for which reserves were created		—		1,427
Balance December 31, 1999			687		800
Additions:
	Charged to costs and expenses		64		1,430
Deductions:
	Net charges of nature for which reserves were created		—		1,430
Balance December 31, 2000			751		800
Additions:
	Charged to costs and expenses		9		1,528
Deductions:
	Net charges of nature for which reserves were created		630		1,528
Balance December 31, 2001		$	130	$	800

140

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

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

QuickLinks

TABLE OF CONTENTS
PART I
PART II
PART III
PART IV
PART I.
KENTUCKY UTILITIES COMPANY
EMPLOYEES AND LABOR RELATIONS
Louisville Gas and Electric Company and Subsidiary Consolidated Statements of Comprehensive Income (Thousands of $)
Louisville Gas and Electric Company and Subsidiary Consolidated Statements of Capitalization (Thousands of $)
Louisville Gas and Electric Company and Subsidiary Notes to Consolidated Financial Statements
Louisville Gas and Electric Company Report of Management
Louisville Gas and Electric Company and Subsidiary Report of Independent Accountants
Louisville Gas and Electric Company Report of Independent Public Accountants
INDEX OF ABBREVIATIONS
Kentucky Utilities Company and Subsidiary Consolidated Statements of Income (Thousands of $)
Consolidated Statements of Retained Earnings (Thousands of $)
Kentucky Utilities Company and Subsidiary Consolidated Statements of Comprehensive Income (Thousands of $)
Kentucky Utilities Company and Subsidiary Consolidated Statements of Cash Flows (Thousands of $)
Kentucky Utilities Company and Subsidiary Notes to Consolidated Financial Statements
Kentucky Utilities Company Report of Management
Kentucky Utilities Company and Subsidiary Report of Independent Accountants
Kentucky Utilities Company Report of Independent Public Accountants
PART III
PART IV
REPORT OF INDEPENDENT ACCOUNTANTS ON FINANCIAL STATEMENT SCHEDULES
Louisville Gas and Electric Company Schedule II—Valuation and Qualifying Accounts For the Three Years Ended December 31, 2001 (Thousands of $)
Report of Independent Accountants on Financial Statement Schedules
Kentucky Utilities Company Schedule II—Valuation and Qualifying Accounts For the Three Years Ended December 31, 2001 (Thousands of $)
SIGNATURES—LOUISVILLE GAS AND ELECTRIC COMPANY
SIGNATURES—KENTUCKY UTILITIES COMPANY

EX-10.74

                                                                   EXHIBIT 10.74

                                                                  EXECUTION COPY


                       EMPLOYMENT AND SEVERANCE AGREEMENT


     THIS AGREEMENT made February 25, 2000, by and between LG&E Energy
Corporation, a Kentucky corporation (the "Company"), Powergen, plc, a United
Kingdom public limited company ("Parent"), and Victor A. Staffieri (the
"Executive").

     WHEREAS, Parent, Company, a Delaware corporation to be formed as an
indirect wholly owned subsidiary of Parent ("US Subholdco 2") and a Kentucky
corporation to be formed as a direct wholly owned subsidiary of US Subholdco 2
("Merger Sub"), have executed a merger agreement (the "Merger Agreement") which
will become effective at the Effective Time (as defined in the Merger
Agreement);

     WHEREAS, the Merger will constitute a "Change in Control" for purposes of
the Change-in-Control Agreement between the Company and the Executive dated
January 5, 1998 (the "Change-In-Control Agreement");

     WHEREAS, Parent and the Company have determined that it is essential and in
the best interest of Parent, the Company and their stockholders to retain the
services of the Executive as President and Chief Operating Officer of the
Company on and after the Effective Time, and provide the Executive with
compensation and other benefits on the terms and conditions set forth in this
Agreement, and to ensure his continued dedication and efforts in such event
without undue concern for his personal financial and employment security in the
event of a Change in Control after the Merger; and

     WHEREAS, the Executive is willing to accept such employment and perform
services for the Company on the terms and conditions hereinafter set forth;

     NOW THEREFORE, in consideration of the respective agreements of the parties
contained herein, it is agreed as follows:

     1. EFFECTIVENESS; EFFECT ON PRIOR AGREEMENTS; ADDITIONAL PAYMENTS.

     1.1 This Agreement shall become effective at the Effective Time, provided
the Executive is employed by the Company on that date. As of the Effective Time,
the Change-in-Control Agreement shall, except as otherwise provided herein,
terminate and become null and void. In consideration of the services rendered by
the Executive to the Company prior to the Effective Time, the Executive's
willingness to enter into this Agreement, and the satisfaction of all of the
Company's obligations under the Change-in-Control Agreement, the Company shall
pay the Executive in cash 60% of the amount calculated and payable under
Sections 3.1(b) and 6 of the Change-in-Control Agreement (the "Initial
Change-in-Control Payment") within 10 days following the Effective Time
conditioned upon delivery by the Executive of an executed form of release of all
claims against the Company with respect to the Change-in-Control Agreement
(other than with respect to Section 6 of such Agreement) (on a form to be
provided by the Company).





The balance of the amount calculated under Sections 3.1(b) and 6 of the
Change-in-Control Agreement (the "Deferred Change-in-Control Payment") shall be
credited to Executive's account under the Deferred Compensation Plan of the
Company (or such other plan or arrangement as may be mutually agreed upon by the
parties hereto) and shall be payable in a lump sum cash payment (including
adjustment for any increases or decreases in Executive's account under the
Deferred Compensation Plan), if the Executive so elects, within ten (10) days
after the earliest to occur of (i) a termination of employment, other than a
termination by the Executive without Good Reason, which occurs at any time
during the eighteen consecutive months immediately following the Effective Time
(the "Transition Period"), (ii) a Change in Control that occurs during the
Transition Period, so long as the Executive is still employed by the Company
immediately prior to the Change in Control, and (iii) the end of the Transition
Period, so long as the Executive is still employed on such date. In the event
that Executive elects not to receive the foregoing lump sum payment, Executive
may otherwise elect to defer receipt of such payment and have such payment
continue to be held in his Deferred Compensation Plan account (which account
shall continue to be adjusted in accordance with the terms of the Deferred
Compensation Plan, or such other plan or arrangement as may be mutually agreed
upon by the parties hereto).

     1.2 Parent shall, or shall cause the Company to pay to the Executive a lump
sum cash payment in an amount equal to 25% of the Deferred Change-in-Control
Payment (without adjustment for any increases or decreases in Executive's
account under the Deferred Compensation Plan)(the "Premium Payment") within ten
(10) days after the earliest to occur of (i) the date that Executive's
employment is terminated by the Company without Cause, by Executive for Good
Reason, or as a result of Executive's death or Disability, at any time during
the eighteen consecutive months immediately following the Effective Time (the
"Transition Period"), (ii) a Change in Control that occurs during the Transition
Period, so long as the Executive is still employed by the Company immediately
prior to the Change in Control, and (iii) the end of the Transition Period, so
long as the Executive is still employed on such date. In the event that
Executive elects not to receive the foregoing lump sum payment, Executive may
otherwise elect to defer receipt of such payment and have such payment continue
to be held in his Deferred Compensation Plan account (which account shall
continue to be adjusted in accordance with the terms of the Deferred
Compensation Plan, or such other plan or arrangement as may be mutually agreed
upon by the parties hereto).

     1.3 As of the Effective Time, Parent shall grant to the Executive the
number of American Depository Shares of Parent, each of which represents four
Ordinary Shares of the Parent (the "ADS's"), that are equivalent in value, as of
the Effective Time, to the amount of the Premium Payment (the "Premium ADS's"),
which shall be subject to a risk of forfeiture and in which the Executive shall
become vested upon the earliest to occur of (i) the date that Executive's
employment is terminated by the Company without Cause, by Executive for Good
Reason, or as a result of Executive's death or Disability, at any time during
the Transition Period, (ii) a Change in Control that occurs during the
Transition Period, so long as the Executive is still employed immediately prior
to the


                                      -2-





Change in Control, and (iii) the end of the Transition Period, so long as the
Executive is still employed on such date. In addition, in the event that during
the Transition Period, Parent pays dividends in respect of ADS's (or Ordinary
Shares, as applicable) to its holders thereof, the Executive shall have a right,
subject to the Executive's ultimate vesting in the Premium ADS's pursuant to the
preceding sentence, to receive a payment, in cash or ADS's (as the Executive
shall elect), equal to the amount of any dividends actually paid on the number
of Premium ADS's (or Ordinary Shares, as applicable) held by the Executive.

     2. TERM OF AGREEMENT. This Agreement shall commence as of the Effective
Time, and shall continue in effect until the second anniversary of the Effective
Time; PROVIDED, HOWEVER, that commencing on the second anniversary of the
Effective Time, and on each anniversary of the Effective Time thereafter, the
term of this Agreement shall automatically be extended for one (1) year unless
the Company or the Executive shall have given written notice to the other at
least ninety days prior thereto (if such notice is given following the second
anniversary of the Effective Time, otherwise such notice period shall be one
hundred and eighty days) that the term of this Agreement shall not be so
extended; and PROVIDED, FURTHER, HOWEVER, that notwithstanding any such notice
by the Company not to extend, the term of this Agreement shall not expire prior
to the expiration of twenty-four (24) months after any Change in Control which
occurs while this Agreement is in effect.

     3. EMPLOYMENT.

     3.1 The Company agrees to employ Executive, and Executive agrees to serve
during the term hereof as President and Chief Operating Officer of the Company.
Executive shall report to the Chief Executive Officer of the Company (the
"CEO").

     3.2 Executive agrees to devote his full working time and efforts, to the
best of his ability, experience and talent, to the performance of services,
duties and responsibilities in connection with the position named above.
Executive shall perform such duties and exercise such powers, commensurate with
his position, as the CEO and the Board of Directors of the Company (the "Board")
shall from time to time assign to him on such terms and conditions and subject
to such restrictions as the CEO and the Board may reasonably from time to time
impose.

     3.3 Nothing in this Agreement shall preclude Executive from (a) engaging in
charitable and community affairs so long as, in the reasonable determination of
the Company, such activities do not interfere with his duties and
responsibilities hereunder, (b) managing any passive investment made by him in
publicly traded equity securities or other property (provided that no such
investment may exceed 5% of the equity of any entity, without the prior approval
of the Company, which approval shall not be unreasonably withheld) or (c)
serving, subject to the prior approval of the Company, which approval shall not
be unreasonably withheld, as a member of boards of directors or as a trustee of
any other corporation, association or entity.


                                      -3-



     3.4 The Executive will perform his services at the Company's headquarters
in Louisville, Kentucky, with the understanding that he will be required to
travel as reasonably required (including travel to the United Kingdom) for the
performance of his duties under this Agreement.

     4. COMPENSATION.

     4.1 SALARY. The Company shall pay Executive a base salary ("Base Salary")
of not less than the rate in effect immediately prior to the Effective Time. The
Base Salary shall be payable in accordance with the ordinary payroll practices
of the Company. The Base Salary shall be reviewed by the Board as of July 1 of
each year during the term of this Agreement and may be increased in the
discretion of the Board and, as so increased, shall constitute "Base Salary"
hereunder. At no time shall the Board be able to decrease the Base Salary.

     4.2 ANNUAL BONUS. In addition to his Base Salary, Executive shall be
eligible to participate in any annual incentive plan or program maintained by
the Company in which other senior executives of the Company participate (the
"Bonus Plan"). Such participation shall be on terms commensurate with
Executive's position and level of responsibility. The Executive's target bonus
under the Bonus Plan in respect of each twelve-month period of the term of this
Agreement (as provided for in Section 2)(each, a "Contract Year") shall be not
less than the target bonus opportunity to which the Executive is entitled as of
the date hereof (60% of the Base Salary); PROVIDED, HOWEVER, that with respect
to the first and second Contract Years, Executive's annual bonus amount shall
not be less than 75% of the Executive's target bonus for each such Contract
Year. Except as set forth in the preceding sentence, nothing in this Section 4.2
will guarantee to the Executive any specific amount of incentive compensation,
or prevent a Remuneration Committee appointed by the Board of Directors of
Parent from establishing reasonable performance goals and compensation targets,
after consultation with the Executive, applicable only to the Executive.

     4.3 COMPENSATION PLANS AND PROGRAMS. Executive shall be eligible to
participate in any compensation plan or program maintained by the Company in
which other senior executives of the Company participate on terms commensurate
with his position and level of responsibility, and to receive equity-based
incentive awards based upon achievement of performance goals based partially
upon Parent's and partially on the Company's performance in accordance with the
general terms of the long-term incentive plan contained on Exhibit A.

     4.4 OTHER COMPENSATION. Nothing in this Section 4 will preclude the Board
from authorizing such additional compensation to the Executive, in cash or in
property, as the Board may determine in its sole discretion to be appropriate.

     4.5 EXISTING STOCK OPTIONS. In addition to any provision in the Merger
Agreement, prior to the Effective Time, Executive may elect in writing delivered


                                      -4-



to Parent to convert each Company stock option he holds (each, a "Company
Option"), whether vested or unvested, into an option to acquire, on the same
terms and conditions as were applicable under such Company Option, the number of
ADS's, equal to the result (rounded down to the nearest whole ADS) of
multiplying the number of shares subject to the Company Option immediately prior
to the Effective Time by the Conversion Ratio (as defined in the Merger
Agreement), at an exercise price per share equal to the result (rounded up to
the nearest whole cent) of dividing the per share exercise price of such Company
Option immediately prior to the Effective Time by the Conversion Ratio (it being
understood that the exercise price shall be converted into dollars at the rate
prevailing at the close of business on the business day prior to the Effective
Time). If Executive makes such election and holds the Company Option or the
ADS's acquired upon the exercise of such Company Option for two years after the
Effective Time, then upon the later of (i) the end of the 24th month after the
Effective Time, or (ii) the exercise of such Company Option, the Parent shall
issue Executive one additional ADS for every 4 ADS's acquired as a result of
such exercise; PROVIDED, HOWEVER in the event that either (i) a Change in
Control occurs within the two years after the Effective Time and the Executive
is still employed by the Company immediately prior to the Change in Control,
immediately prior to such time, the Executive shall receive one additional ADS
for every 4 ADS's (A) acquired by the Executive as a result of the exercise of
any Company Option during the period prior to such Change in Control and (B)
underlying each unexercised Company Option held by the Executive immediately
prior to such Change in Control or (ii) the Executive's employment is terminated
for any reason (other than by the Company for Cause or by the Executive without
Good Reason (other than as a result of death or Disability)) at any time during
the two years after the Effective Time and prior to any Change in Control, the
Executive shall receive, within 10 days after the termination of employment, one
additional ADS for every 4 ADS's (A) acquired by the Executive as a result of
the exercise of any Company Option during the period prior to such termination
of employment and (B) underlying each unexercised Company Option held by the
Executive immediately prior to such termination of employment.

     5. EMPLOYEE BENEFITS.

     5.1 EMPLOYEE BENEFIT PROGRAMS, PLANS AND PRACTICES. The Company shall
provide Executive during the term of his employment hereunder with coverage
under all employee pension and welfare benefit programs, plans and practices
including, but not limited to, those specified in Exhibit B attached hereto
(commensurate with his positions and level of responsibility in the Company and
to the extent permitted under any employee benefit plan) in accordance with the
terms thereof, which the Company makes available to its senior executives.

     5.2 VACATION AND FRINGE BENEFITS. Executive shall be eligible to
participate in the Company's vacation plan; PROVIDED, HOWEVER, that in no event
shall Executive receive fewer vacation days than Executive is entitled to
receive under the Company's vacation policy as in effect immediately prior to
the Effective Time. In addition, Executive shall be entitled to perquisites and
other fringe benefits that are


                                      -5-



comparable to those perquisites and fringe benefits to which Executive is
entitled immediately prior to the Effective Time.

     5.3 EXPENSES. Executive is authorized to incur reasonable expenses in
carrying out his duties and responsibilities under this Agreement, including,
without limitation, expenses for travel and similar items related to such duties
and responsibilities. The Company will reimburse Executive for all such expenses
upon presentation by Executive from time to time of appropriately itemized and
approved (consistent with the Company's policy) accounts of such expenditures.

     6. DEFINITIONS.

     6.1 BASE AMOUNT; BONUS AMOUNT. For purposes of this Agreement, "Base
Amount" shall mean the greater of the Executive's annual base salary from the
Company (a) at the rate in effect on the Termination Date (as hereinafter
defined) or (b) at the highest rate in effect at any time during the ninety (90)
day period prior to the Effective Time or the Change in Control, as applicable,
and shall include all amounts of base salary that are deferred under any
qualified and non-qualified employee benefits plans of the Company or any
Subsidiary (as hereinafter defined) or under any other agreement or arrangement.
For purposes of this Agreement; "Bonus Amount" shall mean the greater of (a) the
most recent annual bonus paid or payable to the Executive (which may include a
bonus amount paid or payable in respect of any Contract Year), (b) the annual
bonus paid or payable to the Executive under the Bonus Plan for the full fiscal
year ended prior to the fiscal year during which the Effective Time, or the
Change in Control, as applicable, occurred or (c) the Executive's target award
under the Bonus Plan for the full fiscal year ended prior to the fiscal year
during which the Effective Time, or the Change in Control, as applicable,
occurred.

     6.2 CAUSE. For purposes of this Agreement, a termination for "Cause" is a
termination evidenced by a resolution adopted in good faith by at least
seventy-five percent (75%) of the Board of Directors of the Company that (i)
there has been repeated willful misconduct by the Executive in performing the
reasonably assigned duties on behalf of the Company required by and in
accordance with his employment by the Company, or (ii) the Executive has been
convicted of a felony in the course of performing those duties. Notwithstanding
anything contained in this Agreement to the contrary, no failure to perform by
the Executive after a Notice of Termination (as hereinafter defined) is given by
the Executive shall constitute Cause for purposes of this Agreement. No act, or
failure to act, on Executive's part shall be deemed to be "repeated" unless the
Executive shall have received a written notice from the Company setting forth in
detail the particulars of the act, or the failure to act, which the Company
contends would constitute Cause when repeated and Executive then repeats such
act or failure to act and does not resolve or otherwise cure such behavior
within thirty (30) days of receipt of such notice.


                                      -6-



     6.3 CHANGE IN CONTROL. For purposes of this Agreement, a "Change in
Control" shall mean the occurrence during the term of this Agreement of any of
the following events:

          (a) An acquisition (other than directly from Parent) of any securities
of Parent entitled generally to vote on the election of directors (the "Voting
Securities") by any "Person" (as the term person is used for purposes of Section
13(d) or 14(d) of the Securities Exchange Act of 1934, as amended (the "1934
Act")) immediately after which such Person has "Beneficial Ownership" (within
the meaning of Rule 13d-3 promulgated under the 1934 Act) of fifteen percent
(15%) or more of the combined voting power of Parent's then outstanding Voting
Securities; PROVIDED, HOWEVER, in determining whether a Change in Control has
occurred, Voting Securities which are acquired in a "Non-Control Acquisition"
(as hereinafter defined) shall not constitute an acquisition which would cause a
Change in Control. A "Non-Control Acquisition" shall mean an acquisition by (1)
an employee benefit plan (or a trust forming a part thereof) maintained by (a)
Parent or (b) any corporation or other Person of which a majority of its voting
power or its equity securities or equity interest is owned directly and
indirectly by Parent (a "Subsidiary") or (2) Parent or any Subsidiary.

          (b) The individuals who, as of the date this Agreement was approved by
the Board, are members of the Board (the "Incumbent Board"), cease for any
reason to constitute at least two-thirds of the Board; PROVIDED, HOWEVER, that
if the election, or nomination for election by Parent's stockholders, of any new
director was approved by a vote of at least two-thirds of the Incumbent Board,
such new director shall, for purposes of the Agreement, be considered as a
member of the Incumbent Board; or

          (c) Approval by stockholders of Parent of:

               (1) A merger, consolidation or reorganization involving Parent;
unless

                    (i) the stockholders of Parent immediately before such
merger, consolidation or reorganization, own, directly or indirectly immediately
following such merger, consolidation or reorganization, at least seventy-five
percent (75%) of the combined voting power of the outstanding voting securities
of the corporation resulting from such merger or consolidation or reorganization
(the "Surviving Corporation") in substantially the same proportion to each other
as their ownership of the Voting Securities immediately before such merger,
consolidation or reorganization, and

                    (ii) the individuals who were members of the Incumbent Board
immediately prior to the execution of the agreement providing for such merger,
consolidation or reorganization constitute at least two-thirds of the members of
the board of directors of the Surviving Corporation;


                                      -7-



               (2) A complete liquidation or dissolution of Parent or the
Company; unless, in the case of the Company, Parent continues to own directly or
indirectly all or substantially all of the Company's assets;

               (3) An agreement for the sale or other disposition of all or
substantially all of the assets of Parent or the Company to any Person (other
than a transfer to a Subsidiary);

               (4) A merger or other combination involving the Company as a
result of which Parent ceases to beneficially own more than 50% of the
outstanding Voting Securities of the successor to the Company, unless Parent
continues to own directly or indirectly all or substantially all of the
Company's assets; or

               (5) Any Person acquires Beneficial Ownership of a greater
percentage of the Voting Securities of the Company than the percentage of such
Voting Securities then held, directly or indirectly, by Parent.

Notwithstanding the foregoing clauses (a), (b), and (c), a Change in Control
shall not be deemed to occur solely because any Person Beneficially Owned by the
Subject Person (the "Subject Person") acquired Beneficial Ownership of more than
the permitted amount of the outstanding Voting Securities as a result of the
acquisition of Voting Securities by Parent which, by reducing the number of
Voting Securities outstanding, increases the proportional number of shares,
provided that if a Change in Control would occur (but for the operation of this
sentence) as a result of the acquisition of Voting Securities by Parent, and
after such share acquisition by Parent, the Subject Person or entity becomes the
Beneficial Owner of any additional Voting Securities which increases the
percentage of the then outstanding Voting Securities Beneficially Owned by the
Subject Person, then a Change in Control shall occur.

          (d) Notwithstanding anything contained in this Agreement to the
contrary, if the Executive's employment is terminated during the term of this
Agreement and the Executive reasonably demonstrates that such termination (i)
was at the request of a third party who has indicated an intention or taken
steps reasonably calculated to effect a Change in Control and who effectuates a
Change in Control (a "Third Party") or (ii) otherwise occurred in connection
with, or in anticipation of, a Change in Control which actually occurs, then for
all purposes of this Agreement, the date of a Change in Control with respect to
the Executive shall mean the date immediately prior to the date of such
termination of the Executive's employment.

     6.4 DISABILITY. For purposes of this Agreement, "Disability" shall mean a
physical or mental infirmity which impairs the Executive's ability to
substantially perform his duties with the Company which continues for a period
of at least one hundred eighty (180) consecutive days.


                                      -8-


     6.5 GOOD REASON.

          (a) For purposes of this Agreement, "Good Reason" shall mean the
occurrence of any of the events or conditions described in subsections (1)
through (8) hereof:

               (1) a reduction by the Company in the Executive's Base Salary or
annual target bonus opportunity as in effect prior to such reduction or any
failure to pay the Executive any compensation or benefits to which the Executive
is entitled within thirty days of the applicable due date, provided that the
Company may correct such reduction or failure within thirty (30) days of its
commission;

               (2) Parent or the Company require the Executive to be relocated
anywhere in excess of fifty (50) miles of his present office location, except
for required travel on Parent or Company business consistent with his business
travel obligations as in effect prior to the Effective Time and as provided in
Section 3.4 of this Agreement;

               (3) a failure by Parent or the Company to maintain plans
providing benefits at least as beneficial in the aggregate as those provided by
any benefit or compensation plan, retirement or pension plan, stock option plan,
bonus plan, long-term incentive plan, life insurance plan, health and accident
plan or disability plan in which the Executive is participating prior to the
Effective Time, or the Change in Control, as applicable, or if the Company or
Parent has taken any action which would adversely affect the Executive's
participation in or materially reduce the Executive's benefits under any of such
plans or deprive him of any material fringe benefit enjoyed by him prior to the
Effective Time, or the Change in Control, as applicable, or if the Company or
Parent has failed to provide him with the number of paid vacation days to which
he would be entitled in accordance with the Company's normal vacation policy
immediately prior to the Effective Time, or the Change in Control, as
applicable;

               (4) Parent or the Company materially reduces, individually or in
the aggregate, the Executive's title, job authorities or responsibilities as in
effect prior to such reduction;

               (5) Parent or the Company fails to obtain the assumption of the
obligations contained in this Agreement by any successor as contemplated in
Section 11 hereof;

               (6) any purported termination of the Executive's employment by
Parent or the Company which is not effected pursuant to a Notice of Termination
satisfying the requirements of Section 8 below; and, for purposes of this
Agreement, no such purported termination shall be effective;

               (7) any material breach by Parent or the Company of any provision
of this Agreement;


                                      -9-



               (8) any purported termination of the Executive's employment for
Cause by Parent or the Company which does not comply with the terms of Section
6.2 of this Agreement; or

          (b) Until the Executive's Disability, the Executive's rights to
terminate his employment pursuant to this Section 6.5 shall not be affected by
his incapacity due to physical or mental illness.

     7. TERMINATION OF EMPLOYMENT.

     7.1 If, during the term of this Agreement, the Executive's employment with
the Company shall be terminated within twenty-four months after the effective
time of any Change in Control, then the Executive shall be entitled to the
following compensation and benefits:

          (a) If the Executive's employment with the Company shall be terminated
(1) by Parent or the Company for Cause or (2) by the Executive (other than for
Good Reason or as a result of death or Disability), the Company shall pay the
Executive all amounts earned or accrued for or on behalf of the Executive
through the Termination Date (as hereinafter defined) but not paid as of the
Termination Date, including (i) Base Salary, (ii) reimbursement for reasonable
and necessary expenses incurred by the Executive on behalf of the Company during
the period ending on the Termination Date and (iii) vacation pay (collectively,
"Accrued Compensation").

          (b) If the Executive's employment with the Company shall be terminated
(1) as a result of the Executive's death or (2) as a result of the Executive's
Disability, the Executive shall be entitled to the following: (i) The Company
shall pay the Executive all Accrued Compensation; (ii) the Company shall pay, as
a severance amount to the Executive (or his or her personal representative or
estate, as applicable) after the Termination Date, an amount equal to the
Executive's annual target bonus for the year in which such Termination Date
occurs; and (iii) the Company shall provide the Executive with a cash lump sum
payment of any long-term incentive award granted to the Executive at the target
level, prorated for Executive's actual period of service.

          (c) If the Executive's employment with the Company shall be terminated
(1) by the Company for any reason (including as a result of the Company's notice
not to extend the term of this Agreement) other than as specified in clause (1)
of Section 7.1(a) or (2) by the Executive for Good Reason, the Executive shall
be entitled to the following:

               (i) The Company shall pay the Executive all Accrued Compensation;

               (ii) The Company shall pay, as a severance amount to the
Executive after the Termination Date, an amount equal to 2.99 times the sum of
(a) the Base Amount and (b) the Bonus Amount;


                                      -10-



               (iii) For a period of thirty-six months (the "Continuation
Period"), the Company shall at its expense continue on behalf of the Executive
and his dependents and beneficiaries (to the same extent provided to the
dependents and beneficiaries prior to the Executive's termination) the life
insurance, disability, medical, dental, and hospitalization benefits provided
(x) to the Executive by the Company at any time within ninety (90) days
preceding a Change in Control or at any time thereafter, or (y) to other
similarly situated executives who continue in the employ of the Company during
the Continuation Period. The coverage and benefits (including deductibles and
costs) provided in this Section 7.1(c) (iii) during the Continuation Period
shall be no less favorable to the Executive and his dependents and
beneficiaries, than the most favorable of such coverages and benefits set forth
in clauses (x) and (y) above. The Company's obligation hereunder with respect to
the foregoing benefits shall be limited to the extent that the Executive obtains
any such benefits pursuant to a subsequent employer's benefit plans, in which
case the Company may reduce the coverage of any benefits it is required to
provide the Executive hereunder as long as the aggregate coverages and benefits
of the combined benefit plans are no less favorable to the Executive than the
coverages and benefits required to be provided hereunder. This Subsection
(c)(iii) shall not be interpreted so as to limit any benefits to which the
Executive or his dependents may be entitled under any of the Company's or any
Subsidiary's employee benefit plans, programs or practices following the
Executive's termination of employment, including without limitation, retiree
medical and life insurance benefits; and

               (iv) The Company shall provide to the Executive an amount equal
to twenty percent (20%) of the Base Amount to be used for outplacement services.

     7.2 If, during the term of this Agreement, but prior to a Change in
Control, the Executive's employment with the Company shall be terminated, the
Executive shall be entitled to the following:

          (a) If the Executive's employment with the Company shall be terminated
(1) by Parent or the Company for Cause or (2) by the Executive (other than for
Good Reason or as a result of death or Disability), the Company shall pay the
Executive all Accrued Compensation.

          (b) If the Executive's employment with the Company shall be terminated
(1) as a result of the Executive's death or (2) as a result of the Executive's
Disability, the Executive shall be entitled to the following: (i) The Company
shall pay the Executive all Accrued Compensation; (ii) the Company shall pay, as
a severance amount to the Executive (or his or her personal representative or
estate, as applicable) after the Termination Date, an amount equal to the
Executive's annual target bonus for the year in which such Termination Date
occurs; and (iii) the Company shall provide the Executive with a cash lump sum
payment of any long-term incentive award granted to the Executive at the target
level, prorated for Executive's actual period of service.



                                      -11-



          (c) If the Executive's employment with the Company shall be terminated
(1) by the Company for any reason (including as a result of the Company's notice
not to extend the term of this Agreement) other than as specified in clause (1)
of Section 7.2(a) or (2) by the Executive for Good Reason, the Executive shall
be entitled to the following:

                 (i)   The Company shall pay the Executive all Accrued
Compensation;

                 (ii)  The Company shall pay, as a severance amount to the
Executive after the Termination Date, an amount equal to the sum of (a) the Base
Amount and (b) the Bonus Amount, divided by twelve, the quotient of which shall
be multiplied by the greater of (x) twelve and (y) the number of months
remaining in the term of this Agreement;

                 (iii) For a period of twenty-four (24) months (the
"Continuation Period"), the Company shall at its expense continue on behalf
of the Executive and his dependents and beneficiaries (to the same extent
provided to the dependents and beneficiaries prior to the Executive's
termination) the life insurance, disability, medical, dental, and
hospitalization benefits provided to other similarly situated executives who
continue in the employ of the Company during the Continuation Period. The
Company's obligation hereunder with respect to the foregoing benefits shall
be limited to the extent that the Executive obtains any such benefits
pursuant to a subsequent employer's benefit plans, in which case the Company
may reduce the coverage of any benefits it is required to provide the
Executive hereunder as long as the aggregate coverages and benefits of the
combined benefit plans are no less favorable to the Executive than the
coverages and benefits required to be provided hereunder. This Subsection
(c)(iii) shall not be interpreted so as to limit any benefits to which the
Executive or his dependents may be entitled under any of the Company's or any
Subsidiary's employee benefit plans, programs or practices following the
Executive's termination of employment, including without limitation, retiree
medical and life insurance benefits; and

                 (iv) The Company shall provide to the Executive an amount equal
to twenty percent (20%) of the Base Amount to be used for outplacement services.

     7.3 The amounts provided for in Section 7.1(a), 7.1(b) (i) and (ii), 7.1(c)
(i), (ii) and (iv), 7.2(a), 7.2(b)(i) and (ii) and 7.2(c) (i), (ii) and (iv)
shall be paid in cash in a lump sum within thirty (30) days after the
Executive's Termination Date.

     7.4 The Executive shall not be required to mitigate the amount of any
payments provided for in this Agreement by seeking other employment or otherwise
and no such payment shall be offset or reduced by the amount of any compensation
or


                                      -12-



benefits provided to the Executive in any subsequent employment except as
provided in Sections 7.1(c) (iii) and 7.2(c)(iii).

     7.5 The provisions of this Agreement, and any payment provided for
hereunder, shall not reduce any amounts otherwise payable, or in any way
diminish the Executive's existing rights, or rights which would accrue solely as
a result of the passage of time, under any benefit plan, incentive plan, or
securities plan, employment agreement or other contract, plan or arrangement
with the Company, any Subsidiary or any other party, including, but not limited
to, those specified in Exhibit B attached hereto, PROVIDED, HOWEVER, the Company
shall not be required to make duplicative payments of Accrued Compensation, and
provided further that, upon execution of this Agreement, Executive shall not
have any rights under his prior Change-In-Control Agreement (other than with
respect to Section 6 of such Agreement), as previously amended, which agreement
(as stated in Sections 1 and 22 hereof) is superseded by this Agreement.

     8.  NOTICE OF TERMINATION. Any purported termination by Parent or the
Company or by the Executive shall be communicated by written Notice of
Termination to the other. For purposes of this Agreement, a "Notice of
Termination" shall mean a notice which indicates the specific termination
provision in this Agreement relied upon and shall set forth in reasonable detail
the facts and circumstances claimed to provide a basis for termination of the
Executive's employment under the provision so indicated. For purposes of this
Agreement, no such purported termination shall be effective without such Notice
of Termination.

     9.  TERMINATION DATE. "Termination Date" shall mean, in the case of the
Executive's death, his date of death and, in all other cases, the date specified
in the Notice of Termination subject to the following:

         (a) If the Executive's employment is terminated by Parent or the
Company for Cause or due to Disability, the date specified in the Notice of
Termination shall be at least thirty (30) days from the date the Notice of
Termination is given to the Executive, provided that, in the case of Disability,
the Executive shall not have returned to the full-time performance of his duties
during such period of at least (30) days; and

         (b) If the Executive's employment is terminated for Good Reason, the
date specified in the Notice of Termination shall not be more than sixty (60)
days from the date the Notice of Termination is given to Parent or the Company.

     10. CERTAIN ADDITIONAL PAYMENTS.

         (a) Notwithstanding anything in the Agreement to the contrary, in the
event that it is determined (as hereafter provided) that any payment or
distribution by the Company or any affiliates to or for the benefit of the
Executive, whether paid or payable or distributed or distributable pursuant to
the terms of this Agreement or otherwise pursuant to or by reason of any other
agreement, policy, plan, program or arrangement, including without limitation
any stock option, stock appreciation right or similar right, or


                                      -13-



the lapse or termination of any restriction on or the vesting or
exercisability of any of the foregoing (individually and collectively a
"Payment"), would be subject to the excise tax imposed by Section 4999(or any
successor provision thereto) of the Internal Revenue Code of 1986, as amended
(the "Code") by reason of being considered "contingent on a change in
ownership or control" of the Company or Parent, within the meaning of Section
280G of the Code (or any successor provision thereto), or to any similar tax
imposed by state or local law, or any interest or penalties with respect to
any such taxes (such taxes, together with any such interest and penalties,
being hereafter collectively referred to as the "Excise Tax"), then the
Executive shall be entitled to receive an additional payment or payments
(individually and collectively, a "Gross-Up Payment"). The Gross-Up Payment
shall be in an amount such that, after payment by the Executive of all taxes
(including any interest or penalties imposed with respect to such taxes),
including any Excise Tax imposed upon the Gross-Up Payment, the Executive
retains an amount of the Gross-Up Payment equal to the Excise Tax imposed
upon the Payment.

         (b) Subject to the provisions of Section 10(f) hereof, all
determinations required to be made under this Section 10, including whether an
Excise Tax is payable by the Executive and the amount of such Excise Tax and
whether a Gross-Up Payment is required to be paid to the Executive and the
amount of such Gross-Up Payment, if any, shall be made by a nationally
recognized accounting firm (the "Accounting Firm") selected by the Executive in
his sole discretion. The Executive shall direct the Accounting Firm to submit
its determination and detailed supporting calculations to both the Company and
the Executive within thirty (30) calendar days after the Termination Date, if
applicable, and any such other time or times as may be requested by the Company
or the Executive. If the Accounting Firm determines that any Excise Tax is
payable by the Executive, the Company shall pay or cause to be paid the required
Gross-Up Payment in cash to the Executive within five (5) business days after
receipt of such determination and calculations with respect to any Payment to
the Executive. If the Accounting Firm determines that no Excise Tax is payable
by the Executive, it shall, at the same time as it makes such determination,
furnish the Company and the Executive an opinion that the Executive has
substantial authority not to report any Excise Tax on his federal, state or
local income or other tax return. As a result of the uncertainty in the
application of Section 4999 of the Code (or any successor provision thereto) at
the time of any determination by the Accounting Firm hereunder, it is possible
that Gross-Up Payments which will not have been made by the Company should have
been made (an "Underpayment"), consistent with the calculations required to be
made hereunder. In the event that the Company exhausts or fails to pursue its
remedies pursuant to Section 10(f) hereof and the Executive thereafter is
required to make a payment of any Excise Tax, the Executive shall direct the
Accounting Firm to determine the amount of the Underpayment that has occurred
and to submit its determination and detailed supporting calculations to both the
Company and the Executive as promptly as possible. Any such Underpayment shall
be promptly paid by the Company in cash to, or for the benefit of, the Executive
within five (5) business days after receipt of such determination and
calculations.


                                      -14-



         (c) The Company and the Executive shall each provide the Accounting
Firm access to and copies of any books, records and documents in the possession
of the Company or the Executive, as the case may be, reasonably requested by the
Accounting Firm, and otherwise cooperate with the Accounting Firm in connection
with the preparation and issuance of the determinations and calculations
contemplated by Section 10(b) hereof. Any determination by the Accounting Firm
as to the amount of the Gross-Up Payment will be binding on the Company and the
Executive.

         (d) The federal, state, and local income or other tax returns filed by
the Executive will be prepared and filed on a consistent basis with the
determination of the Accounting Firm with respect to the Excise Tax payable by
the Executive. The Executive will make proper payment of the amount of any
Excise Payment and, at the request of the Company, provide to the Company true
and correct copies (with any amendments) of the Executive's federal income tax
return as filed with the Internal Revenue Service and corresponding state and
local tax returns, if relevant, as filed with the applicable taxing authority,
and such other documents reasonably requested by the Company, evidencing such
payment. If prior to the filing of the Executive's federal income tax return, or
corresponding state or local tax return, if relevant, the Accounting Firm
determines that the amount of the Gross-Up Payment should be reduced, the
Executive will within five (5) business days pay to the Company the amount of
such reduction.

         (e) The fees and expenses of the Accounting Firm for its services in
connection with the determinations and calculations contemplated by Section
10(b) hereof shall be borne by the Company. If such fees and expenses are
initially paid by the Executive, the Company shall reimburse the Executive the
full amount of such fees and expenses within five (5) business days after
receipt from the Executive of a statement therefor and reasonable evidence of
his payment thereof.

         (f) The Executive shall notify the Company in writing of any claim by
the Internal Revenue Service or any other taxing authority that, if successful,
would require the payment by the Company of a Gross-Up Payment. Such
notification shall be given as promptly as practicable but no later than ten
(10) business days after the Executive actually receives notice of such claim
and the Executive shall further apprise the Company of the nature of such claim
and the date on which such claim is requested to be paid (in each case, to the
extent known by the Executive). The Executive shall not pay such claim prior to
the earlier of (i) the expiration of the thirty (30) calendar-day period
following the date on which he gives such notice to the Company and (ii) the
date that any payment of amount with respect to such claim is due. If the
Company notifies the Executive in writing prior to the expiration of such period
that it desires to contest such claim, the Executive shall:

                 (1) provide the Company with any written records or documents
in his possession relating to such claim reasonably requested by the Company;


                                      -15-



               (2) take such action in connection with contesting such claim as
the Company shall reasonably request in writing from time to time, including
without limitation accepting legal representation with respect to such claim by
an attorney competent in respect of the subject matter and reasonably selected
by the Company;

               (3) cooperate with the Company in good faith in order effectively
to contest such claim; and

               (4) permit the Company to participate in any proceedings relating
to such claim;

PROVIDED, HOWEVER, that the Company shall bear and pay directly all costs and
expenses (including interest and penalties) incurred in connection with such
contest and shall indemnify and hold harmless the Executive, on an after-tax
basis, for and against any Excise Tax or income tax, including interest and
penalties with respect thereto, imposed as a result of such representation and
payment of costs and expenses. Without limiting the foregoing provisions of this
Section 10(f), the Company shall control all proceedings taken in connection
with the contest of any claim contemplated by this Section 10(f) and, at its
sole option, may pursue or forego any and all administrative appeals,
proceedings, hearings and conferences with the taxing authority in respect of
such claim (PROVIDED, HOWEVER, that the Executive may participate therein at his
own cost and expense) and may, at its option, either direct the Executive to pay
the tax claimed and sue for a refund or contest the claim in any permissible
manner, and the Executive agrees to prosecute such contest to a determination
before any administrative tribunal, in a court of initial jurisdiction and in
one or more appellate courts, as the Company shall determine; PROVIDED, HOWEVER,
that if the Company directs the Executive to pay the tax claimed and sue for a
refund, the Company shall advance the amount of such payment to the Executive on
an interest-free basis and shall indemnify and hold the Executive harmless, on
an after-tax basis, from any Excise Tax or income tax, including interest or
penalties with respect thereto, imposed with respect to such advance; and
provided further, however, that any extension of the statute of limitations
relating to payment of taxes for the taxable year of the Executive with respect
to which the contested amount is claimed to be due is limited solely to such
contested amount. Furthermore, the Company's control of any such contested claim
shall be limited to issues with respect to which a Gross-Up Payment would be
payable hereunder and the Executive shall be entitled to settle or contest, as
the case may be, any other issue raised by the Internal Revenue Service or any
other taxing authority.

               (g) If, after the receipt by the Executive of an amount advanced
by the Company pursuant to Section 10(f) hereof, the Executive receives any
refund with respect to such claim, the Executive shall (subject to the Company's
complying with the requirements of Section 10(f) hereof) promptly pay the
Company the amount of such refund (together with any interest paid or credited
thereon after any taxes applicable thereto). If, after the receipt by the
Executive of an amount advanced by the Company pursuant to Section 10(f) hereof,
a determination is made that the Executive shall not be



                                      -16-



entitled to any refund with respect to such claim and the Company does not
notify the Executive in writing of its intent to contest such denial or refund
prior to the expiration of thirty (30) calendar days after such determination,
then such advance shall be forgiven and shall not be required to be repaid and
the amount of any such advance shall offset, to the extent thereof, the amount
of Gross-Up Payment required to be paid by the Company to the Executive pursuant
to this Section 10.

     11.  SUCCESSORS; BINDING AGREEMENT.

          (a) This Agreement shall be binding upon and shall inure to the
benefit of Parent, the Company, their successors and assigns and, at the time of
any such succession or assignment, Parent or the Company (as applicable) shall
require any successor or assign to expressly assume and agree to perform this
Agreement in the same manner and to the same extent that Parent or the Company
would be required to perform it if no such succession or assignment had taken
place. The terms "Parent", "the Company" as used herein shall include such
successors and assigns. The term "successors and assigns" as used herein shall
mean a corporation or other entity acquiring ownership, directly or indirectly,
of all or substantially all the assets and business of the Company (including
this Agreement) whether by operation of law or otherwise.

          (b) Neither this Agreement nor any right or interest hereunder shall
be assignable or transferable by the Executive, his beneficiaries or legal
representatives, except by will or by the laws of descent and distribution. This
Agreement shall inure to the benefit of and be enforceable by the Executive's
legal personal representative.

     12.  FEES AND EXPENSES. The Company shall pay all legal fees and related
expenses (including the cost of experts, evidence and counsel) incurred by the
Executive involving (a) the Executive's termination of employment (including all
such fees and expenses, if any, incurred in contesting or disputing any such
termination of employment), or (b) the Executive seeking to obtain or enforce
any right or benefit provided by this Agreement.

     13.  NOTICE. For the purpose of this Agreement, notices and all other
communications provided for in the Agreement (including the Notice of
Termination) shall be in writing and shall be deemed to have been duly given
when personally delivered or sent by certified mail, return receipt requested,
postage prepaid, addressed to the respective addresses last given by each party
to the other, provided that all notices to Parent or the Company shall be
directed to the attention of the Board with a copy to the Secretary of Parent or
the Company. All notices and communications shall be deemed to have been
received on the date of delivery thereof or on the third business day after the
mailing thereof, except that notice of change of address shall be effective only
upon receipt.

     14.  NON-EXCLUSIVITY OF RIGHTS. Nothing in this Agreement shall prevent or
limit the Executive's continuing or future participation in any benefit, bonus,


                                      -17-



incentive or other plan or program provided by the Company and for which the
Executive may qualify, nor shall anything herein limit or reduce such rights as
the Executive may have under any other agreements with the Company. Amounts
which are vested benefits or which the Executive is otherwise entitled to
receive under any plan or program of the Company shall be payable in accordance
with such plan or program.

     15.  SETTLEMENT OF CLAIMS. The Company's obligation to make the payments
provided for in this Agreement and otherwise to perform its obligations
hereunder shall not be affected by any circumstances, including, without
limitation, any set-off, counterclaim, recoupment, defense or other right which
the Company may have against the Executive or others.

     16.  MISCELLANEOUS. No provision of this Agreement may be modified, waived
or discharged unless such waiver, modification or discharge is agreed to in
writing and signed by the Executive, Parent and the Company. No waiver by either
party hereto at any time of any breach by the other party hereto of, or
compliance with, any condition or provision of this Agreement to be performed by
such other party shall be deemed a waiver of similar or dissimilar provisions or
conditions at the same or at any prior or subsequent time. No agreement or
representations, oral or otherwise, express or implied, with respect to the
subject matter hereof have been made by either party which are not expressly set
forth in this Agreement. No additional compensation provided under any benefit
or compensation plans to the Executive shall be deemed to modify or otherwise
affect the terms of this Agreement or any of the Executive's entitlements
hereunder.

     17.  GOVERNING LAW. This Agreement shall be governed by and construed and
enforced in accordance with the laws of the Commonwealth of Kentucky, without
reference to principles of conflicts of laws.

     18.  SEVERABILITY. The provisions of this Agreement shall be deemed
severable and the invalidity or unenforceability of any provision shall not
affect the validity or enforceability of the other provisions hereof.

     19.  NONSOLICITATION.

          (a) The Executive hereby covenants and agrees that, at all times
during the period of his employment and during the Restricted Period (as
hereinafter defined) immediately following termination for any reason (unless
such termination occurs after a Change in Control), the Executive shall not,
without the prior written consent of the Board, (i) solicit or take any action
to willfully and intentionally cause the solicitation of any person who as of
that date is a client, customer, ("Client") of the Parent or the Company or any
of their subsidiaries to transact any business with a Competitive Enterprise (as
hereinafter defined) or discontinue business, in whole or in part with the
Parent or the Company; or (ii) willfully or intentionally interfere with or
damage any relationship between a Client and the Parent or the Company.


                                      -18-



          (b) The Executive hereby covenants and agrees that, at all times
during the period of his employment and during the Restricted Period immediately
following the termination thereof for any reason (unless such termination occurs
after a subsequent Change in Control), the Executive shall not, without the
prior written consent of the Board, solicit any person employed at that time by
the Parent, the Company or any of their subsidiaries to apply for or accept
employment with a Competitive Enterprise or otherwise encourage or entice such
person to leave his position with the Parent, the Company or any of their
subsidiaries.

          (c) For purposes of this Agreement, (i) the term "Restricted Period"
shall equal one year, provided that if Executive's employment is terminated
within eighteen months of the Effective Time for any reason other than a
termination for Cause, the Restricted Period shall equal six months and (ii) the
term "Competitive Enterprise" shall mean any business which is in competition
with a business engaged in by the Parent, the Company or any of its subsidiaries
or affiliates in any state of the United States or in any foreign country in
which any of them are engaged in business at the time of such termination of
employment for as long as they carry on a business therein. Notwithstanding the
preceding sentence, the Executive shall not be prohibited from owning less than
five (5%) percent of any publicly traded corporation, and if Executive's
termination of employment shall occur within eighteen months of the Effective
Time for any reason other than a termination for Cause, "Competitive Enterprise"
shall mean any business which is in competition with a business engaged in by
the Parent, the Company or any of its subsidiaries or affiliates in any state in
which any of them are engaged in business at the time of such termination of
employment for as long as they carry on a business therein or in any state
contiguous to such state.

          (d) It is the intention of the parties hereto that the restrictions
contained in this Section be enforceable to the fullest extent permitted by
applicable law. Therefore, to the extent any court of competent jurisdiction
shall determine that any portion of the foregoing restrictions is excessive,
such provision shall not be entirely void, but rather shall be limited or
revised only to the extent necessary to make it enforceable. Specifically, if
any court of competent jurisdiction should hold that any portion of the
foregoing description is overly broad as to one or more states of the United
States or one or more foreign jurisdictions, then that state or states or
foreign jurisdiction or jurisdictions shall be eliminated from the territory to
which the restrictions of paragraph (a) of this Section applies and the
restrictions shall remain applicable in all other states of the United States
and foreign jurisdictions.

     20.  CONFIDENTIAL INFORMATION.

          The Executive agrees to keep secret and retain in the strictest
confidence all confidential matters which relate to the Parent, the Company, its
subsidiaries and affiliates, including, without limitation, customer lists,
client lists, trade secrets, pricing policies and other business affairs of the
Parent, the Company, its subsidiaries and affiliates learned by him from the
Parent, the Company or any such subsidiary or affiliate


                                      -19-



or otherwise before or after the date of this Agreement, and not to disclose any
such confidential matter to anyone outside the Parent, the Company or any of its
subsidiaries or affiliates, whether during or after his period of service with
the Company, except (i) as such disclosure may be required or appropriate in
connection with his work as an employee of the Company or (ii) when required to
do so by a court of law, by any governmental agency having supervisory authority
over the business of the Parent or the Company or by any administrative or
legislative body (including a committee thereof) with apparent jurisdiction to
order him to divulge, disclose or make accessible such information. The
Executive agrees to give the Parent and the Company advance written notice of
any disclosure pursuant to clause (ii) of the preceding sentence and to
cooperate with any efforts by the Parent or the Company to limit the extent of
such disclosure. Upon request by the Parent or the Company, the Executive agrees
to deliver promptly to the Parent or the Company upon termination of his
services for the Company, or at any time thereafter as the Parent, the Company
may request, all Parent, Company, subsidiary or affiliate memoranda, notes,
records, reports, manuals, drawings, designs, computer files in any media and
other documents (and all copies thereof) relating to the Parent or the Company's
or any subsidiary's or affiliate's business and all property of the Parent or
the Company or any subsidiary or affiliate associated therewith, which he may
then possess or have under his direct control, other than personal notes,
diaries, rolodexes and correspondence.

     21.  REMEDY.

     Should the Executive engage in or perform, either directly or indirectly,
any of the acts prohibited by Sections 19 or 20 hereof, it is agreed that the
Parent and the Company shall be entitled to full injunctive relief, to be issued
by any competent court of equity, enjoining and restraining the Executive and
each and every other person, firm, organization, association, or corporation
concerned therein, from the continuance of such violative acts. The foregoing
remedy available to the Parent and the Company shall not be deemed to limit or
prevent the exercise by the Parent or the Company of any or all further rights
and remedies which may be available to the Parent or the Company hereunder or at
law or in equity.

     22.  ENTIRE AGREEMENT. This Agreement constitutes the entire agreement
between the parties hereto and supersedes all prior agreements, if any,
understandings and arrangements, oral or written, between the parties hereto
with respect to the subject matter hereof, including, without limiting the
foregoing, his prior Change-In-Control Agreement, as previously amended, which
shall cease to be of any further effect.


                                      -20-



     IN WITNESS WHEREOF, the Company has caused this Agreement to be executed by
its duly authorized representative and the Executive has executed this Agreement
as of the day and year first above written.


                                       POWERGEN PLC


                                       By:
                                          ------------------------------------
                                          Name:
                                          Title:


                                       LG&E ENERGY CORPORATION


                                       By:
                                          ------------------------------------
                                          Name:
                                          Title:


                                       ----------------------------------
                                       VICTOR A. STAFFIERI






                                      -21-



                                    EXHIBIT B

                                       TO

                           CHANGE-IN-CONTROL AGREEMENT


     1.  Omnibus Long-Term Incentive Plan

     2.  Short-Term Incentive Plan

     3.  Qualified Thrift Plan

     4.  Nonqualified Thrift Plan

     5.  LG&E Energy Corporation Retirement Income Plan for Employees Who Are
         Not Members of a Bargaining Unit

     6.  LG&E Energy Corporation Supplemental Executive Retirement Plan






                             FIRST AMENDMENT TO THE
                       EMPLOYMENT AND SEVERANCE AGREEMENT
                                       OF
                               VICTOR A. STAFFIERI


WHEREAS, Victor A. Staffieri (the "Executive") and LG&E Energy Corp., a Kentucky
corporation (the "Company") and Powergen, plc, a United Kingdom public limited
company (the "Parent") entered into an Employment and Severance Agreement, dated
February 25, 2000 (the "Agreement");

WHEREAS, Parent, Company, a Delaware corporation to be formed as an indirect
wholly owned subsidiary of Parent ("US Subholdco 2") and a Kentucky corporation
to be formed as a direct wholly owned subsidiary of US Subholdco 2 ("Merger
Sub"), have executed a merger agreement (the "Merger Agreement") which will
become effective at the Effective Time (as defined in the Merger Agreement);

WHEREAS, Company and the Parent have determined that it is desirable to amend
the Agreement to provide greater retention incentives to the Executive as a
further inducement for the Executive to remain in the employment of the Company;

WHEREAS, An amendment to the Merger Agreement has necessitated a corresponding
amendment to the Agreement; and

WHEREAS, the parties wish to correct the definition of a Change in Control
contained in the Agreement.

NOW THEREFORE, in consideration of the respective agreements of the parties
contained herein, it is agreed as follows:

1. Section 1.1 shall be deleted and replaced in its entirety to read as follows:

"This Agreement shall become effective at the Effective Time, provided the
Company employs the Executive on that date. As of the Effective Time, the
Change-in-Control Agreement shall, except as otherwise provided herein,
terminate and become null and void. In consideration of the services rendered by
the Executive to the Company prior to the Effective Time, the Executive's
willingness to enter into this Agreement which provides additional retention
value to the Company, and the satisfaction of all of the Company's obligations
under the Change-in-Control Agreement, the Company shall pay the Executive in
cash $600,000 on the Effective Date, if said time occurs prior to January 1,
2001. Additionally, if the Effective Time occurs prior to January 1, 2001 the
Company shall pay the Executive in cash the following: $809,000 on the six month
anniversary of the Effective Time, $809,000 on the twelve month anniversary of
the Effective Time, and $774,330 on the eighteen month anniversary of the
Effective Time, collectively the "Retention Payments", so long as the Executive
is still employed by the Company on such dates. The Retention Payments shall be
credited to Executive's account under the





Deferred Compensation Plan of the Company (or such other plan or arrangement as
may be mutually agreed upon by the parties hereto) at the Effective Time and
shall be payable in a lump sum cash payment (including adjustment for any
increases or decreases in Executive's account under the Deferred Compensation
Plan), if the Executive so elects, within ten (10) days after the earliest to
occur of (i) a termination of employment, other than a termination by the
Executive without Good Reason, which occurs at any time during the eighteen
consecutive months immediately following the Effective Time (the "Transition
Period"), (ii) a Change in Control that occurs during the Transition Period, so
long as the Executive is still employed by the Company immediately prior to the
Change in Control, and (iii) the scheduled six, twelve, and eighteen month
anniversaries. In the event that Executive elects not to receive the foregoing
lump sum payments, Executive may otherwise elect to defer receipt of such
payments and have such payments continue to be held in his Deferred Compensation
Plan account (which account shall continue to be adjusted in accordance with the
terms of the Deferred Compensation Plan, or such other plan or arrangement as
may be mutually agreed upon by the parties hereto). If the Effective Date occurs
on or after January 1, 2001, the Company shall pay the Executive in cash 60% of
the amount calculated and payable under Sections 3.1(b) and 6 of the
Change-in-Control Agreement (the "Initial Change-in-Control Payment") within 10
days following the Effective Time conditioned upon delivery by the Executive of
an executed form of release of all claims against the Company with respect to
the Change-in-Control Agreement (other than with respect to Section 6 of such
Agreement) (on a form to be provided by the Company). Additionally, if the
Effective Date Occurs on or after January 1, 2001, the balance of the amount
calculated under Sections 3.1(b) and 6 of the Change-in-Control Agreement (the
"Deferred Change-in-Control Payment") shall be credited to Executive's account
under the Deferred Compensation Plan of the Company (or such other plan or
arrangement as may be mutually agreed upon by the parties hereto) and shall be
payable in a lump sum cash payment (including adjustment for any increases or
decreases in Executive's account under the Deferred Compensation Plan), if the
Executive so elects, within ten (10) days after the earliest to occur of (i) a
termination of employment, other than a termination by the Executive without
Good Reason, which occurs at any time during the eighteen consecutive months
immediately following the Effective Time (the "Transition Period"), (ii) a
Change in Control that occurs during the Transition Period, so long as the
Executive is still employed by the Company immediately prior to the Change in
Control, and (iii) the end of the Transition Period, so long as the Executive is
still employed on such date. In the event that Executive elects not to receive
the foregoing lump sum payment, Executive may otherwise elect to defer receipt
of such payment and have such payment continue to be held in his Deferred
Compensation Plan account (which account shall continue to be adjusted in
accordance with the terms of the Deferred Compensation Plan, or such other plan
or arrangement as may be mutually agreed upon by the parties hereto).

Parent shall, or shall cause the Company to pay to the Executive a lump sum cash
payment in an amount equal to $262,835 if the closing occurs prior to January 1,
2001 or an amount equal to 25% of the Deferred Change-in-Control Payment if the
closing occurs on or after January 1, 2001 (without adjustment for any increases
or decreases in Executive's account under the Deferred Compensation Plan) in
either event (the "Premium Payment") within ten (10) days after the earliest to
occur of (i) the date that





Executive's employment is terminated by the Company without Cause, by Executive
for Good Reason, or as a result of Executive's death or Disability, at any time
during the eighteen consecutive months immediately following the Effective Time
(the "Transition Period"), (ii) a Change in Control that occurs during the
Transition Period, so long as the Executive is still employed by the Company
immediately prior to the Change in Control, and (iii) the end of the Transition
Period, so long as the Executive is still employed on such date. In the event
that Executive elects not to receive the foregoing lump sum payment, Executive
may otherwise elect to defer receipt of such payment and have such payment
continue to be held in his Deferred Compensation Plan account (which account
shall continue to be adjusted in accordance with the terms of the Deferred
Compensation Plan, or such other plan or arrangement as may be mutually agreed
upon by the parties hereto)."

2. Section 4.5 shall be deleted and replaced in its entirety to read as follows:

"4.5 EXISTING STOCK OPTIONS. In accordance with the Merger Agreement and any
amendments thereto, Executive may elect in writing delivered to Parent to
convert each Company stock option he holds (each, a "Company Option"), whether
vested or unvested, into an option to acquire, on the same terms and conditions
as were applicable under such Company Option, the number of ADS's, equal to the
result (rounded down to the nearest whole ADS) of multiplying the number of
shares subject to the Company Option immediately prior to the Effective Time by
the Conversion Ratio (as defined in the Merger Agreement), at an exercise price
per share equal to the result (rounded up to the nearest whole cent) of dividing
the per share exercise price of such Company Option immediately prior to the
Effective Time by the Conversion Ratio (it being understood that the exercise
price shall be converted into dollars at the rate prevailing at the close of
business on the business day prior to the Effective Time). If Executive makes
such election and holds the Company Option or the ADS's acquired upon the
exercise of such Company Option for two years after the Effective Time, then
upon the later of (i) the end of the 24th month after the Effective Time, or
(ii) the exercise of such Company Option, the Parent shall issue Executive one
additional ADS for every 4 ADS's acquired as a result of such exercise;
PROVIDED, HOWEVER in the event that either (i) a Change in Control occurs within
the two years after the Effective Time and the Executive is still employed by
the Company immediately prior to the Change in Control, immediately prior to
such time, the Executive shall receive one additional ADS for every 4 ADS's (A)
acquired by the Executive as a result of the exercise of any Company Option
during the period prior to such Change in Control and (B) underlying each
unexercised Company Option held by the Executive immediately prior to such
Change in Control or (ii) the Executive's employment is terminated for any
reason (other than by the Company for Cause or by the Executive without Good
Reason (other than as a result of death or Disability)) at any time during the
two years after the Effective Time and prior to any Change in Control, the
Executive shall receive, within 10 days after the termination of employment, one
additional ADS for every 4 ADS's (A) acquired by the Executive as a result of
the exercise of any Company Option during the period prior to such termination
of employment and (B) underlying each unexercised Company Option held by the
Executive immediately prior to such termination of employment."




3. Section 6.3(c)(5) shall be deleted and replaced in its entirety to read as
follows:

(5)  Any Person acquires Beneficial Ownership of a greater percentage of the
     Voting Securities of the Company than the percentage of such Voting
     Securities then held, directly or indirectly, by Parent.

4. A new Section 6.3(d) shall be added to read as follows:

"6.3(d) Notwithstanding the foregoing clauses (a), (b), and (c), a Change in
Control shall not be deemed to occur solely because any Person (the "Subject
Person") acquired Beneficial Ownership of more than the permitted amount of the
outstanding Voting Securities as a result of the acquisition of Voting
Securities by Parent which, by reducing the number of Voting Securities
outstanding, increases the proportional number of shares Beneficially Owned by
the Subject Person, provided that if a Change in Control would occur (but for
the operation of this sentence) as a result of the acquisition of Voting
Securities by Parent, and after such share acquisition by Parent, the Subject
Person or entity becomes the Beneficial Owner of any additional Voting
Securities which increases the percentage of the then outstanding Voting
Securities Beneficially Owned by the Subject Person, then a Change in Control
shall occur."

5. Section 6.3(d) of the existing Agreement shall be renumbered as Section
6.3(e) to read as follows:

"6.3(e) Notwithstanding anything contained in this Agreement to the contrary, if
the Executive's employment is terminated during the term of this Agreement and
the Executive reasonably demonstrates that such termination (i) was at the
request of a third party who has indicated an intention or taken steps
reasonably calculated to effect a Change in Control and who effectuates a Change
in Control (a "Third Party") or (ii) otherwise occurred in connection with, or
in anticipation of, a Change in Control which actually occurs, then for all
purposes of this Agreement, the date of a Change in Control with respect to the
Executive shall mean the date immediately prior to the date of such termination
of the Executive's employment."

                                       -----------------------------------
                                       Victor A. Staffieri

                                       -----------------------------------
                                       Date

                                       LG&E Energy Corp.

                                       By:
                                          --------------------------------

                                       Powergen,plc


                                       By:
                                          --------------------------------






                                     RELEASE


     THIS RELEASE ("Release") is made and entered into on this 8th day of
December, 2000, by and among Victor A. Staffieri (the "Executive"), and LG&E
Energy Corp. and Powergen,plc, by and for itself and their present and former
agents, directors, shareholders, officers, employees, representatives,
divisions, parents, subsidiaries and affiliates, and their predecessors,
successors, heirs, executors, administrators and assigns (collectively,
"Released Parties").

RECITALS:

     A. The Executive has become eligible for certain change in control benefits
under the pursuant to a Change in Control Agreement between the Executive and
the Company dated January 5, 1998 (the "Agreement") as a result of the proposed
merger between LG&E Energy Corp. and Powergen, plc.

     B. The Released Parties and the Executive have entered into an Employment
and Severance Agreement dated February 25, 2000, as amended as of the date
hereof (the "Employment Agreement") under terms and conditions agreeable to the
Executive.

     C. The Executive and the Released Parties desire to enter into this Release
in order to fully settle and discharge all claims which are or might have been
asserted by the Executive against the Released Parties for benefits under the
Agreement, upon the terms and conditions set forth herein.

AGREEMENT:

     The Parties hereby agree as follows:

RELEASE:

     In consideration of employment under the terms and conditions outlined in
the Employment Agreement, the Executive hereby completely releases and forever
discharges the Released Parties, and any and all other persons, firms, insurers
and/or corporations whatsoever that might have any liability through the
Released Parties, of and from any and all past, present, or future claims,
actions, causes of action, rights, damages, costs, and all other expenses and
compensation of any nature whatsoever, whether based on contract, or other
theory of recovery and whether for compensation or punitive damages, which
Executive now has, or which may hereafter accrue or otherwise be acquired, on
account of all injuries to him, which have resulted under the terms of the
Agreement, other than those arising pursuant to Section 6 of the Agreement. This
Release, on the part of Executive, shall be a fully binding and a complete
settlement between the Executive, his heirs, assigns and successors and the
Released Parties for all benefits under the Agreement, except those arising
pursuant to Section 6 of the Agreement.





ENTIRE AGREEMENT AND SUCCESSORS IN INTEREST

     This Release contains the entire agreement between the Executive and the
Released Parties, with regard to the matters set forth herein and shall be
binding upon and inure to the benefit of the executors, administrators, personal
representatives, heirs, successors and assigns of each.

REPRESENTATION OF COMPREHENSION OF DOCUMENT

     In entering into this Release, the Executive represents that he has relied
upon the legal advice of his attorney, who is the attorney of his own choice and
that the terms of this Release have been completely read and explained to him by
his attorney, and that those terms are fully understood and voluntarily accepted
by him.

GOVERNING LAW

     This Release shall be construed and interpreted in accordance with the laws
of the Commonwealth of Kentucky, and in no event will the documents be construed
in a manner inconsistent with Kentucky law.

CONFIDENTIALITY

     The Executive and the Released Parties hereby agree for themselves and
their representatives, including attorneys, to hold the terms of this Release,
confidential, and the parties further agree not to disclose the terms of this
Release to any person, firm or corporation, including legal industry
publications, who is not a party to this Release.





EFFECTIVENESS

     This Release shall become effective upon the closing of the merger of LG&E
Energy Corp. and Powergen, plc or its subsidiary.


                                       ------------------------------------
                                       Victor A. Staffieri

                                       ------------------------------------
                                       Date


STATE OF KENTUCKY          )
                           ) SS:
COUNTY OF JEFFERSON        )

     Subscribed and sworn to before me by Victor A. Staffieri, this _____ day of
_____________, 2000, in Louisville, Jefferson County, Kentucky.

     My Commission expires:______________________________________


                                       ------------------------------------
                                       NOTARY PUBLIC
                                       State at Large, Kentucky



LG&E Energy Corp.


By:
   ---------------------------



                              SECOND AMENDMENT TO THE
                       EMPLOYMENT AND SEVERANCE AGREEMENT
                                      OF
                              VICTOR A. STAFFIERI

WHEREAS, Victor A. Staffieri (the "Executive") and LG&E Energy Corp., a Kentucky
corporation (the "Company") and Powergen, plc, a United Kingdom public limited
company (the "Parent") entered into an Employment and Severance Agreement, dated
February 25, 2000 (the "Agreement");

WHEREAS, the Agreement was previously amended by the Executive, the Company and
the Parent in a document dated December 8, 2000 (the "First Amendment");

WHEREAS, the Executive, the Company and the Parent have determined that it is
now desirable to amend the Agreement to reflect certain changes resulting from
the Executive's promotion to Chief Executive Officer of the Company;

NOW THEREFORE, in consideration of the respective agreements of the parties
contained herein, it is agreed as follows:

1. Section 3.1 shall be deleted and replaced in its entirety to read as follows:

"3.1 The Company agrees to employ Executive, and Executive agrees to serve
during the term hereof as Chief Executive Officer of the Company. Executive
shall report to the Chief Executive Officer of the Parent. In addition, Parent
shall (i) cause the Executive to be elected as a member of the Board of
Directors of the Company (the "Board") and (ii) use its best efforts to secure
Executive's election as a member of the Board of Directors of Parent (the
"Parent Board") to serve for a period determined by the Parent's Articles of
Association, and Executive agrees to serve in such capacities."

2. Section 3.2 shall be deleted and replaced in its entirety to read as follows:

"3.2 Executive agrees to devote his full working time and efforts, to the best
of his ability, experience and talent, to the performance of services, duties
and responsibilities in connection with the position named above. Executive
shall perform such duties and exercise such powers, commensurate with his
position, as Chief Executive Officer of the Company, as the Chief Executive
Officer of the Parent shall from time to time delegate to him on such terms and
conditions and subject to such restrictions as Chief Executive Officer of the
Parent may reasonably from time to time impose.

3. Section 4.1 shall be deleted and replaced in its entirety to read as follows:





"4.1. SALARY. The Company shall pay Executive an annual base salary ("Base
Salary") of not less than $600,000.00. The Base Salary shall be payable in
accordance with the ordinary payroll practices of the Company. The Base Salary
shall be reviewed by the Board in July of each year during the term of this
Agreement and may be increased in the discretion of the Board at that or any
other time and, as so increased, shall constitute "Base Salary" hereunder,
however, the first such review will take place in July 2002. At no time shall
the Board be able to decrease the Base Salary."

4. Section 4.2 shall be deleted and replaced in its entirety to read as follows:

"4.2. ANNUAL BONUS. In addition to his Base Salary, Executive shall be eligible
to participate in any annual incentive plan or program maintained by the Company
in which other senior executives of the Company participate (the "Bonus Plan").
Such participation shall be on terms commensurate with Executive's position and
level of responsibility. The Executive's target bonus under the Bonus Plan in
respect of year 2001 shall be not less than 60% of Base Salary for that portion
of the year prior to the effective date of this Second Amendment and 70% of Base
Salary for that portion of the year after the effective date of the Second
Amendment and succeeding years under this Agreement. Notwithstanding the
foregoing, with respect to 2001 and 2002, Executive's annual bonus shall not be
less than 75% of the Executive's target bonus. Except as set forth in the
preceding sentence, nothing in this Section 4.2 will guarantee to the Executive
any specific amount of incentive compensation, or prevent a Remuneration
Committee appointed by the Parent Board from establishing reasonable performance
goals and compensation targets, after consultation with the Executive,
applicable only to the Executive."

5. Section 4.3 shall be amended by adding to the end thereof the following:

"The Parent and the Company acknowledge that, as of the effective date of this
Second Amendment, the current value of the Executive's long-term incentive plan
participation is 175% of Base Salary."

6. A new Section 5.4 shall be added to the end of Article 5 to read as follows:

"5.4. LIFE INSURANCE. The amount of Executive's term life insurance shall be
determined as follows: (a) for the period commencing as of the effective date of
this Second Amendment through the date of the Executive's 50th birthday - not
less than $5,000,000.00, (b) for the period commencing on the day following the
Executive's 50th birthday through the date of the Executive's 55th birthday -
not less than $3,000,000.00, (c) for the period commencing on the day following
the Executive's 55th birthday - not less than $2,000,000.00. The premiums for
such life insurance shall be paid by the Company, regardless of Executive's
employment status. The Company shall also pay Executive an additional payment
such that, after payment by Executive of all taxes imposed as a result of the
life insurance benefit, the Executive retains an amount equal to the taxes
imposed upon the Executive as a result of the life insurance benefit."

7. Subsection 6.5(a) shall be deleted and replaced in its entirety to read as
follows:

"(a) For purposes of this Agreement, "Good Reason" shall mean the occurrence of
any of the events or conditions described in subsections (1) through (10)
hereof:

          (1)  a reduction by the Company in the Executive's Base Salary
or annual




target bonus opportunity as in effect prior to such reduction or any failure
to pay the Executive any compensation or benefits to which the Executive is
entitled within thirty days of the applicable due date, provided that the
Company may correct such reduction or failure within thirty (30) days of its
commission;

          (2)  Parent or the Company require the Executive to be relocated
anywhere in excess of fifty (50) miles of his present office location, except
for required travel on Parent or Company business consistent with his
business travel obligations as in effect prior to the Effective Time and as
provided in Section 3.4 of this Agreement;

          (3)  a failure by Parent of the Company to maintain plans providing
benefits at least as beneficial in the aggregate as those provided by any
benefit or compensation plan, retirement or pension plan, stock option plan,
bonus plan, long-term incentive plan, life insurance plan, health and
accident plan or disability plan in which the Executive is participating
prior to the Effective Time, the Change in Control, or this Second Amendment,
as applicable, or if the Company or Parent has taken any action which would
adversely affect the Executive's participation in or materially reduce the
Executive's benefits under any of such plans or deprive him of any material
fringe benefit enjoyed by him prior to the Effective Time, the Change in
Control, or this Second Amendment, as applicable, or if the Company or Parent
has failed to provide him with the number of paid vacation days to which he
would be entitled in accordance with the Company's normal vacation policy
immediately prior to the Effective Time, the Change in Control, or this
Second Amendment, as applicable;

          (4)  Parent or the Company materially reduces, individually or in
the aggregate, the Executive's title, job authorities or responsibilities as
in effect prior to such reduction;

          (5)  Parent or the Company fails to obtain the assumption of the
obligations contained in this Agreement by any successor as contemplated in
Section 11 hereof;

          (6)  any purported termination of the Executive's employment by
Parent or the Company which is not effected pursuant to a Notice of
Termination satisfying the requirements of Section 8, hereof; and, for
purposes of this Agreement, no such purported termination shall be effective;

          (7)  any material breach by Parent or the Company of any provision
of this Agreement;

          (8)  any purported termination of the Executive's employment for
Cause by Parent or the Company which does not comply with the terms of
Section 6.2 of this Agreement;

          (9)  any removal of the Executive from the position of Chief Executive
Officer of the Company, except for Cause; or

          (10) any removal of Executive from, the Board or the Parent Board;
except for Cause."




8. Subsection 7.2(c)(ii) shall be deleted and replaced in its entirety to read
as follows:

         "(ii) The Company shall pay, as a severance amount to the Executive
after the Termination Date, an amount equal to the sum of (a) the Base Amount
and (b) the Bonus Amount, divided by twelve, the quotient of which shall be
multiplied by twenty-four."

9. A new Section 7.6 shall be added to the end of Article 7 to read as follows:

"7.6 DISABILITY. If the Executive's employment with the Company shall be
terminated as a result of Disability, the Parent or Executive may terminate
Executive's employment on written notice thereof, and Executive shall, in
addition to the benefits provided pursuant to Section 7.1(b) or Section 7.2(b),
receive until age 65 a benefit equal to 60 percent of the Base Salary, less 100%
of the Social Security disability benefit and any amounts payable pursuant to
the terms of a disability insurance policy or similar arrangement which the
Company maintains during the term hereof."

10. A new Section 7.7 shall be added to the end of Article 7 to read as follows:

"7.7 DEATH. If the Executive's employment with the Company shall be terminated
as a result of death, in addition to the benefits provided pursuant to Section
7.1(b) or Section 7.2(b) for a period of thirty-six (36) months, the Company
shall at its expense continue on behalf of the Executive's dependents and
beneficiaries (to the same extent provided to the dependents and beneficiaries
prior to the Executive's death) the life insurance, medical, dental and
hospitalization benefits under such plans offered by the Company to active
employees."




         IN WITNESS WHEREOF, the Company and the Parent have caused this Second
Amendment to be executed by it duly authorized representative and the Executive
has executed this Second Amendment as of the date set forth below, but which
shall be effective as of the 30th day of April, 2001, provided the Executive is
employed by the Company on that date. Except as provided herein, nothing
contained in this Second Amendment shall alter the terms and conditions of the
Agreement or the First Amendment.

LG&E ENERGY CORP.


By:
       ------------------------------
       Name
       Title

Date:
       ------------------------------


POWERGEN, PLC


By:
       ------------------------------
       Name
       Title

Date:
       ------------------------------

EXECUTIVE

       -----------------------------
       VICTOR A. STAFFIERI


Date
       ------------------------------

EX-10.75

                                                                   EXHIBIT 10.75


                                 FIRST AMENDMENT TO THE
                           EMPLOYMENT AND SEVERANCE AGREEMENT
                                           OF
                                [____________________]


WHEREAS, [________________](the "Executive") and LG&E Energy Corp., a Kentucky
corporation (the "Company") and Powergen, plc, a United Kingdom public
limited company (the "Parent") entered into an Employment and Severance
Agreement, dated February 25, 2000 (the "Agreement");

WHEREAS, Parent, Company, a Delaware corporation to be formed as an indirect
wholly owned subsidiary of Parent ("US Subholdco 2") and a Kentucky
corporation to be formed as a direct wholly owned subsidiary of US Subholdco
2 ("Merger Sub"), have executed a merger agreement (the "Merger Agreement")
which will become effective at the Effective Time (as defined in the Merger
Agreement);

WHEREAS, Company and the Parent have determined that it is desirable to amend
the Agreement to provide greater retention incentives to the Executive as a
further inducement for the Executive to remain in the employment of the
Company;

WHEREAS, An amendment to the Merger Agreement has necessitated a
corresponding amendment to the Agreement; and

WHEREAS, the parties wish to correct the definition of a Change in Control
contained in the Agreement.

NOW THEREFORE, in consideration of the respective agreements of the parties
contained herein, it is agreed as follows:

1. Section 1.1 shall be deleted and replaced in its entirety to read as follows:

"This Agreement shall become effective at the Effective Time, provided the
Company employs the Executive on that date.  As of the Effective Time, the
Change-in-Control Agreement shall, except as otherwise provided herein,
terminate and become null and void.  In consideration of the services rendered
by the Executive to the Company prior to the Effective Time, the Executive's
willingness to enter into this Agreement which provides additional retention
value to the Company, and the satisfaction of all of the Company's obligations
under the Change-in-Control Agreement, the Company shall pay the Executive in
cash $[______] on the Effective Date, if said time occurs prior to January 1,
2001. Additionally, if the Effective Time occurs prior to January 1, 2001 the
Company shall pay the Executive in cash the following: $[_________] on the
six month anniversary of the Effective Time, $[_________]on the twelve month
anniversary of the Effective Time, and $[__________] on the eighteen month
anniversary of the Effective Time, collectively the "Retention Payments", so
long as the Executive is still employed by the Company on such dates.  The
Retention Payments shall be credited to Executive's




account under the Deferred Compensation Plan of the Company (or such other
plan or arrangement as may be mutually agreed upon by the parties hereto) at
the Effective Time and shall be payable in a lump sum cash payment (including
adjustment for any increases or decreases in Executive's account under the
Deferred Compensation Plan), if the Executive so elects, within ten (10) days
after the earliest to occur of (i) a termination of employment, other than a
termination by the Executive without Good Reason, which occurs at any time
during the eighteen consecutive months immediately following the Effective
Time (the "Transition Period"), (ii) a Change in Control that occurs during
the Transition Period, so long as the Executive is still employed by the
Company immediately prior to the Change in Control, and (iii) the scheduled
six, twelve, and eighteen month anniversaries.  In the event that Executive
elects not to receive the foregoing lump sum payments, Executive may
otherwise elect to defer receipt of such payments and have such payments
continue to be held in his Deferred Compensation Plan account (which account
shall continue to be adjusted in accordance with the terms of the Deferred
Compensation Plan, or such other plan or arrangement as may be mutually
agreed upon by the parties hereto).

If the Effective Date occurs on or after January 1, 2001, the Company shall
pay the Executive in cash 60% of the amount calculated and payable under
Sections 3.1(b) and 6 of the Change-in-Control Agreement (the "Initial
Change-in-Control Payment") within 10 days following the Effective Time
conditioned upon delivery by the Executive of an executed form of release of
all claims against the Company with respect to the Change-in-Control
Agreement (other than with respect to Section 6 of such Agreement) (on a form
to be provided by the Company).  Additionally, if the Effective Date Occurs
on or after January 1, 2001, the balance of the amount calculated under
Sections 3.1(b) and 6 of the Change-in-Control Agreement (the "Deferred
Change-in-Control Payment") shall be credited to Executive's account under
the Deferred Compensation Plan of the Company (or such other plan or
arrangement as may be mutually agreed upon by the parties hereto) and shall
be payable in a lump sum cash payment (including adjustment for any increases
or decreases in Executive's account under the Deferred Compensation Plan), if
the Executive so elects, within ten (10) days after the earliest to occur of
(i) a termination of employment, other than a termination by the Executive
without Good Reason, which occurs at any time during the eighteen consecutive
months immediately following the Effective Time (the "Transition Period"),
(ii) a Change in Control that occurs during the Transition Period, so long as
the Executive is still employed by the Company immediately prior to the
Change in Control, and (iii) the end of the Transition Period, so long as the
Executive is still employed on such date.  In the event that Executive elects
not to receive the foregoing lump sum payment, Executive may otherwise elect
to defer receipt of such payment and have such payment continue to be held in
his Deferred Compensation Plan account (which account shall continue to be
adjusted in accordance with the terms of the Deferred Compensation Plan, or
such other plan or arrangement as may be mutually agreed upon by the parties
hereto).

Parent shall, or shall cause the Company to pay to the Executive a lump sum
cash payment in an amount equal to $[_________] if the closing occurs prior
to January 1, 2001 or an amount equal to 25% of the Deferred Change-in-Control
Payment if the closing occurs on or after January 1, 2001 (without adjustment
for any increases or decreases in Executive's account under the Deferred
Compensation Plan) in either event




(the "Premium Payment") within ten (10) days after the earliest to occur of
(i) the date that Executive's employment is terminated by the Company without
Cause, by Executive for Good Reason, or as a result of Executive's death or
Disability, at any time during the eighteen consecutive months immediately
following the Effective Time (the "Transition Period"), (ii) a Change in
Control that occurs during the Transition Period, so long as the Executive is
still employed by the Company immediately prior to the Change in Control, and
(iii) the end of the Transition Period, so long as the Executive is still
employed on such date.  In the event that Executive elects not to receive the
foregoing lump sum payment, Executive may otherwise elect to defer receipt of
such payment and have such payment continue to be held in his Deferred
Compensation Plan account (which account shall continue to be adjusted in
accordance with the terms of the Deferred Compensation Plan, or such other
plan or arrangement as may be mutually agreed upon by the parties hereto)."

2.  Section 4.5 shall be deleted and replaced in its entirety to read as
follows:

"4.5  EXISTING STOCK OPTIONS.  In accordance with the Merger Agreement and
any amendments thereto, Executive may elect in writing delivered to Parent to
convert each Company stock option he holds (each, a "Company Option"),
whether vested or unvested, into an option to acquire, on the same terms and
conditions as were applicable under such Company Option, the number of ADS's,
equal to the result (rounded down to the nearest whole ADS) of multiplying
the number of shares subject to the Company Option immediately prior to the
Effective Time by the Conversion Ratio (as defined in the Merger Agreement),
at an exercise price per share equal to the result (rounded up to the nearest
whole cent) of dividing the per share exercise price of such Company Option
immediately prior to the Effective Time by the Conversion Ratio (it being
understood that the exercise price shall be converted into dollars at the
rate prevailing at the close of business on the business day prior to the
Effective Time).  If Executive makes such election and holds the Company
Option or the ADS's acquired upon the exercise of such Company Option for two
years after the Effective Time, then upon the later of (i) the end of the
24th month after the Effective Time, or (ii) the exercise of such Company
Option, the Parent shall issue Executive one additional ADS for every 4 ADS's
acquired as a result of such exercise; PROVIDED, HOWEVER in the event that
either (i) a Change in Control occurs within the two years after the
Effective Time and the Executive is still employed by the Company immediately
prior to the Change in Control, immediately prior to such time, the Executive
shall receive one additional ADS for every 4 ADS's (A) acquired by the
Executive as a result of the exercise of any Company Option during the period
prior to such Change in Control and (B) underlying each unexercised Company
Option held by the Executive immediately prior to such Change in Control or
(ii) the Executive's employment is terminated for any reason (other than by
the Company for Cause or by the Executive without Good Reason (other than as
a result of death or Disability)) at any time during the two years after the
Effective Time and prior to any Change in Control, the Executive shall
receive, within 10 days after the termination of employment, one additional
ADS for every 4 ADS's (A) acquired by the Executive as a result of the
exercise of any Company Option during the period prior to such termination of




employment and (B) underlying each unexercised Company Option held by the
Executive immediately prior to such termination of employment."


3.  Section 6.3(c)(5) shall be deleted and replaced in its entirety to read as
follows:

(5) Any Person acquires Beneficial Ownership of a greater percentage of the
    Voting Securities of the Company than the percentage of such Voting
    Securities then held, directly or indirectly, by Parent.

4.  A new Section 6.3(d) shall be added to read as follows:

"6.3(d)  Notwithstanding the foregoing clauses (a), (b), and (c), a Change
in Control shall not be deemed to occur solely because any Person (the
"Subject Person") acquired Beneficial Ownership of more than the permitted
amount of the outstanding Voting Securities as a result of the acquisition of
Voting Securities by Parent which, by reducing the number of Voting
Securities outstanding, increases the proportional number of shares
Beneficially Owned by the Subject Person, provided that if a Change in
Control would occur (but for the operation of this sentence) as a result of
the acquisition of Voting Securities by Parent, and after such share
acquisition by Parent, the Subject Person or entity becomes the Beneficial
Owner of any additional Voting Securities which increases the percentage of
the then outstanding Voting Securities Beneficially Owned by the Subject
Person, then a Change in Control shall occur."

5. Section 6.3(d) of the existing Agreement shall be renumbered as Section
6.3(e) to read as follows:

"6.3(e)  Notwithstanding anything contained in this Agreement to the
contrary, if the Executive's employment is terminated during the term of this
Agreement and the Executive reasonably demonstrates that such termination (i)
was at the request of a third party who has indicated an intention or taken
steps reasonably calculated to effect a Change in Control and who effectuates
a Change in Control (a "Third Party") or (ii) otherwise occurred in
connection with, or in anticipation of, a Change in Control which actually
occurs, then for all purposes of this Agreement, the date of a Change in
Control with respect to the Executive shall mean the date immediately prior
to the date of such termination of the Executive's employment."

                                         [_______________________]


                                         -----------------------------------
                                         Date

                                         LG&E Energy Corp.

                                         By:
                                            --------------------------------




                                         Powergen,plc


                                         By:
                                            --------------------------------

EX-10.76

                                                                   EXHIBIT 10.76


                                                                          [LOGO]

                                                      LG&E ENERGY CORP.
                                                      220 WEST MAIN STREET
                                                      P.O. BOX 302030
                                                      LOUISVILLE, KENTUCKY 40282
                                                      502-627-2000


November 29, 2000


[NAME]
[TITLE]

Dear [NAME]:

On behalf of LG&E Energy Corp., I am pleased to offer you the position of
Senior Vice President, Finance effective upon the closing of the merger
between LG&E Energy Corp. and Powerglen, plc. (the "Effective Date"). In this
capacity, you will report to me and will be responsible for the ____________
functions of the Company.

The terms and conditions of our offer are described below.

I.       COMPENSATION

         A.   Effective January 1, 2001 a base salary of $_____ per year. We
              review base salaries annually and would review your base salary
              in December 2001; however, your salary will not be reduced.

         B.   Effective January 1, 2001 an annual Short-Term Incentive award
              targeted at $______, ___% of your annual base salary. The
              Short-Term Incentive Plan payout is based on LG&E Energy
              financial performance and personal performance measures and can
              range from 0-150% of the targeted amount.

II.      LONG-TERM INCENTIVES

         You will be eligible to participate in a new Powergen Long-Term
         Incentive Plan. Like the current long-term plan the annual grants
         will be comprised of stock options and performance units. Your
         annualized Long-Term Incentive Grants have an expected present value
         of 60% of your base salary.




III.     RETENTION BONUS

         An initial bonus of $_______ will be paid to you in a lump sum (less
         applicable withholdings) on February 1, 2001. A second retention
         bonus of $______ will be paid to you on January 2, 2002. A final
         retention bonus of $_______ will be paid to you on January 2, 2003.
         The second and third retention bonuses will be credited to your
         account in the LG&E Energy Corp. Nonqualified Savings Plan on the
         Effective Date, with accumulations under the normal provisions of
         the plan. In the event of your death prior to the payment date, all
         unpaid retention amounts with their corresponding accumulations
         shall be immediately paid to your designated beneficiary or estate.
         Otherwise, any unearned retention bonuses and corresponding
         accumulations will be forfeited if the Company does not employ you
         at the time the payments become due.

IV.      LG&E ENERGY SUPPLEMENTAL RETIREMENT BENEFIT

         You will continue to participate in the LG&E Energy Supplemental
         Executive Retirement Plan.

V.       RETIREMENT BENEFITS

         You will continue to participate in the LG&E Energy Corp. Retirement
         Plan and continue to be eligible for post-retirement medical
         coverage as provided to retirees at the time of your retirement.

VI.      OFFICER BENEFITS

         A.   A Company full-sized car and related services with tax gross-up
              (value up to $35,000.00) through the Company's Executive Motor
              Vehicle Program. This Program will provide you a leased, four
              door domestic, non-luxury sedan or sport-utility vehicle as
              well as full maintenance, insurance, and a cellular phone.

         B.   Initiation fees and dues at a luncheon club of your choice
              subject to club provisions of nondiscrimination.

         C.   Income tax preparation services provided through a qualified
              outside provider.

         D.   Personal financial planning services of up $4,000, annually.

         E.   $400,000 of supplemental life insurance (upon meeting insurability
              requirements) in addition to the standard life insurance coverage
              provided by the Company.

         F.   Annual executive physical examination.

         G.   Company paid parking.

         H.   Five weeks of vacation per year.



         I.   Further participation in the LG&E Energy Non-Qualified Savings
              Plan. (401(k) excess contributions and Company match.)

         J.   Enrollment in the full range of LG&E Energy general employee
              benefits.

VII.     CHANGE IN CONTROL AGREEMENT

         Powergen will provide you a new Change in Control Agreement which
         provides for severance benefits of up to 2.99 times annual base pay
         and Short-Term Targeted Incentive plus gross-up for excise taxes as
         well as accelerated vesting of all Long-Term Incentive Awards in the
         event of constructive or a Company initiated termination (except for
         Cause, as defined therein) within two years of a post-merger change
         in control. In the event of a change in control within the first 24
         months following the Effective Date, the severance benefits shall be
         limited to one times the Compensation amounts defined in Sections 1(A)
         and 1(B). A revised agreement is attached.

VIII.    TERMINATION AND SEVERANCE

         To avoid any misunderstanding, we believe it is important to specify
         that employment with the Company is on an "at will" basis and may be
         terminated by either party at any time, with or without cause. The
         Company, however, will provide you a cash severance benefit should
         it terminate you without Cause, as defined in the Change of Control
         agreement described in Section VIII, within two years of the
         Effective Date. For purposes of this Section VIII, a reduction in the
         compensation in Section I, a reduction in the compensation in
         Section II, or if you do not accept a relocation of your employment
         in excess of fifty (50) miles shall each be deemed to be a
         termination without Cause. The severance benefit payable hereunder
         shall be an amount equal to 2.99 times the Compensation amounts
         defined in Sections I(A) and I(B), plus an additional 20% of the
         amount defined in Section I(A). The benefits, if any, under this
         Section VIII shall be offset by benefits paid under Section III.

As noted above, this offer is effective only upon the Effective Date. Finally,
this offer of employment is conditioned upon the execution of the attached
Release. The Release acknowledges the termination of your existing Change in
Control agreement at the Effective Date in exchange for the compensation and
benefits offered herein.

[NAME], I am pleased to present you this offer to continue to be part of the
LG&E Energy executive team. Your impressive record of personal achievement
makes you ideally suited for the role of [TITLE].



Please indicate your acceptance of our offer by signing and returning it to
me. This offer is extended until noon on November 30, 2000.


Yours very truly,



Attachment




Accepted By:



- -----------------------------------------


- ----------
Date

EX-99.02

                                                                   Exhibit 99.02

                       LOUISVILLE GAS AND ELECTRIC COMPANY
                                       AND
                           KENTUCKY UTILITIES COMPANY
                        DIRECTOR AND OFFICER INFORMATION

         The outstanding stock of Louisville Gas and Electric Company ("LG&E")
is divided into three classes: Common Stock, Preferred Stock (without par
value), and Preferred Stock, par value $25 per share. At the close of business
on April 22, 2002, the following shares of each were outstanding:

                                                                                         
Common Stock, without par value...............................................              21,294,223 shares
Preferred Stock, par value $25 per share, 5% Series...........................                 860,287 shares
Preferred Stock, without par value, $5.875 Series.............................                 250,000 shares
Auction Series A (stated value $100 per share)................................                 500,000 shares



        The outstanding stock of Kentucky Utilities Company ("KU") is divided
into three classes: Common Stock, without par value, Preferred Stock, without
par value, and Preference Stock, without par value. As of the close of business
on April 20, 2000, the following shares of each were outstanding

                                                                                         
Common Stock, without par value...............................................              37,817,878 shares
Preferred Stock, without par value (stated value $200 per share)
4.75% Series..................................................................                 200,000 shares
6.53% Series..................................................................                 200,000 shares



         All of the outstanding LG&E Common Stock and KU Common Stock is owned
by LG&E Energy Corp. ("LG&E Energy"). Based on information contained in a
Schedule 13G originally filed with the Securities and Exchange Commission in
October 1998, AMVESCAP PLC, a parent holding company, reported certain holdings
in excess of five percent of LG&E's Preferred Stock. AMVESCAP PLC, with offices
at 1315 Peachtree Street, N.W., Atlanta, Georgia 30309, and certain of its
subsidiaries reported sole voting and dispositive power as to no shares and
shared voting and dispositive power as to 43,000 shares of LG&E Preferred Stock,
without par value, $5.875 Series, representing 17.2% of that class of Preferred
Stock. The reporting companies indicated that they hold the shares on behalf of
other persons who have the right to receive or the power to direct the receipt
of dividends or the proceeds of sales of the shares. No other persons or groups
are known by management to be beneficial owners of more than five percent of
LG&E's Preferred Stock.

As of April 22, 2002, all directors, nominees for director and executive
officers of LG&E and KU as a group beneficially owned no shares of LG&E
Preferred Stock or KU Preferred Stock.

On December 11, 2000, Powergen plc, a public limited company with registered
offices in England and Wales ("Powergen") completed its acquisition of LG&E
Energy, the parent corporation of LG&E and KU. In connection with such
transaction, certain officers and directors of Powergen were appointed to fill
vacancies in the Board of Directors of LG&E and KU occurring by resignation of
prior directors

On April 9, 2001, E.ON AG ("E.ON") 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 of conditions precedent, including the
receipt of regulatory approvals from European and United States governmental
bodies, in form satisfactory to the parties. The parties anticipate that the
remaining approvals may be received by early 2002 to permit completion of the
transaction in 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.



                           INFORMATION ABOUT DIRECTORS

         On December 11, 2000, upon the closing of the merger transaction
involving Powergen and LG&E Energy, all members of the LG&E Board of Directors,
with the exception of Roger W. Hale, resigned, and the size of the Board of
Directors was fixed at nine. Six Powergen directors, Paul Myners, Sir Frederick
Crawford, Sydney Gillibrand, Edmund Wallis, Dr. David K-P Li, and Roberto
Quarta, and one Powergen officer, David Jackson, were appointed to fill all but
one of the vacancies created by the above resignations.

         In January 2001, Roger W. Hale announced his resignation as director of
Powergen and an officer and director of LG&E Energy, LG&E and KU, effective
April 30, 2001. Victor A. Staffieri and Peter Hickson were appointed to fill the
LG&E and KU vacancies created by the resignation of Mr. Hale and the
previously-existing vacancy. In August 2001, Paul Myners and Roberto Quarta
announced their resignations from the Boards of Directors of Powergen, LG&E and
KU and Peter Hickson resigned from the Boards of Directors of LG&E and KU.
Nicholas Baldwin, Chief Executive Officer of Powergen was then appointed to fill
the vacancy of Mr. Hickson.

         Messrs. Baldwin, Staffieri, Crawford, Gillibrand, Wallis and Dr. Li are
presently directors of Powergen. Messrs. Baldwin, Staffieri and Jackson are
presently directors of LG&E Energy.

         The composition of the Boards of Directors of LG&E and KU following the
completion of E.ON's acquisition of Powergen is not known, but such Boards are
likely to contain at least one current officer or director of LG&E Energy.
Accordingly, certain of the directors of LG&E Energy, LG&E or Ku may cease to
serve as directors of LG&E and KU in the event the E.ON-Powergen transaction is
completed.

         The following contains certain information as of April 22, 2002
concerning the directors of LG&E and KU:

DIRECTORS WITH TERMS EXPIRING AT THE 2002 ANNUAL MEETING OF SHAREHOLDERS

SYDNEY GILLIBRAND CBE (Age 67). Mr. Gillibrand was appointed a director of
Powergen plc on May 31, 1999. He is chairman of AMEC plc and TAG Aviation (UK)
and a non-executive director of ICL, and Messier-Dowty. He was previously
vice-chairman of British Aerospace plc. Mr. Gillibrand has been a director of
LG&E and KU since December 2000.

NICHOLAS P. BALDWIN (Age 49). Chief Executive of Powergen since February 21,
2001. Mr. Baldwin was appointed a director of Powergen plc on October 22, 1998,
having been a director of Powergen UK plc since February 1998. Until his
appointment as Chief Executive in February 2001, he was previously Executive
Director, UK Operations of Powergen. He joined the CEGB, the predecessor of
Powergen in 1980. In the United Kingdom, he is also a director of the
Electricity Association and a Director and Trustee of Midlands Excellence and is
a representative on the IEA's Coal Industry Advisory Board. Mr. Baldwin has been
a director of LG&E Energy, LG&E and KU since August 2001.

VICTOR A. STAFFIERI (Age 47). Chairman, President and Chief Executive Officer of
LG&E Energy, LG&E and KU, April 2001 to present. He served as President and
Chief Operating Officer of LG&E Energy, LG&E and KU from February 1999 to April
2001; Chief Financial Officer of Energy and LG&E, May 1997 to February 2000;
Chief Financial Officer of Kentucky Utilities May 1998 to February 2000.
President, Distribution Services Division of Energy December 1995 to May 1997;
Senior Vice President, General Counsel and Public Policy of Energy and LG&E From
November 1992 to December 1993. Mr. Staffieri has been a director of Powergen,
LG&E Energy, LG&E and KU since April 2001.



DIRECTORS WITH TERMS EXPIRING AT THE 2003 ANNUAL MEETING OF SHAREHOLDERS

EDMUND A. WALLIS (Age 62). Mr. Wallis is Chairman of Powergen plc. He was
appointed to the Powergen Board on October 22, 1998, serving as Chairman of such
Board since that date. He was also Chief Executive of Powergen until February
21, 2001. He had been Chief Executive of Powergen UK plc since March 1990 and
Chairman since July 1996. He is a non-executive director of Mercury European
Privatisation Trust plc and a non-executive director of London Transport. He was
also formerly non-executive chairman of LucasVarsity plc. Mr. Wallis has been on
the Board of Directors of LG&E and KU since December 2000.

DR. DAVID K-P LI (Age 63). Dr. Li was appointed a director of Powergen plc on
October 22, 1998, having been a non-executive director of Powergen UK plc since
January 1998. He is chairman and chief executive of The Bank of East Asia
Limited, having been a director since 1977, and holds directorships of numerous
companies in the Far East and elsewhere, including The Hong Kong and China Gas
Company Limited. Dr. Li has been a director of LG&E and KU since December 2000.

DIRECTORS WITH TERMS EXPIRING AT THE 2004 ANNUAL MEETING OF SHAREHOLDERS

SIR FREDERICK CRAWFORD (Age 70). Sir Frederick was appointed to the Powergen plc
Board on October 22, 1998, having been a non-executive director of Powergen UK
plc since June 1990. He is chairman of the Criminal Cases Review Commission and
a Fellow of the Royal Academy of Engineering. He has held appointments as
Professor of Electrical Engineering at Stanford University, and as
Vice-Chancellor of Aston University for 16 years. He was formerly a
non-executive director of Legal and General Group plc and Rexam plc. Mr.
Crawford has been a director of LG&E and of KU since December 2000.

DAVID J. JACKSON (Age 49). Mr. Jackson is General Counsel and Company Secretary
of Powergen plc. He has served on the Board of Directors of LG&E Energy, LG&E
and KU since December 2000.



                  INFORMATION CONCERNING THE BOARD OF DIRECTORS

         The Boards of Directors of LG&E and KU contain the same members.
Certain members are also directors of Powergen or LG&E Energy, as described
above. The committees of the Board of Directors of LG&E and KU include an Audit
Committee and a Compensation Committee. During 2001, the directors who are
members of these committees served in the same capacity for purposes of the LG&E
and KU Boards of Directors.

         During 2001, there were a total of twelve meetings of the LG&E and KU
Boards. All directors attended 75% or more of the total number of meetings of
the Board of Directors and committees of the Board on which they served.

COMPENSATION OF DIRECTORS

         Directors who are also officers of Powergen, LG&E Energy or its
subsidiaries receive no compensation in their capacities as directors of LG&E
and KU.

         As noted earlier, since the completion of the Powergen-LG&E Energy
merger, certain members of the LG&E and KU boards serve on the Board of
Directors of Powergen plc. In that capacity, these members received or will
receive certain compensation. Information regarding such compensation is
incorporated by reference from



Powergen's Annual Report on Form 20-F for the year ended December 31, 2001 to be
filed with the Securities and Exchange Commission.

AUDIT COMMITTEE

         The Audit Committee of the Board is composed of Mr. Sydney Gillibrand
and Sir Frederick Crawford, with one vacancy. During 2001, the Audit Committee
maintained direct contact with the independent auditors and LG&E's and KU's
Internal Auditor to review the following matters pertaining to LG&E and KU: the
adequacy of accounting and financial reporting procedures; the adequacy and
effectiveness of internal accounting controls; the scope and results of the
annual audit and any other matters relative to the audit of these companies'
accounts and financial affairs that the Committee, the Internal Auditor, or the
independent auditors deemed necessary. The Audit Committee met two times during
2001.

REMUNERATION COMMITTEE

         The Remuneration Committee, composed of non-employee directors,
performs certain in connection with the compensation of the executive officers
of LG&E and KU. The Committee also makes recommendations regarding benefits
provided to executive officers and the establishment of various employee benefit
plans. Dr. David K-P Li is the current member of the Remuneration Committee. The
Remuneration Committee met two times during 2001.



                      REPORT OF THE REMUNERATION COMMITTEE

         The Remuneration Committee was comprised wholly of non-employee
directors of LG&E and KU and made all decisions regarding the compensation of
LG&E's and KU's executive officers, including the setting of base pay and the
administration of the Powergen Long-Term Incentive Plan (the "Long-Term Plan")
and Short-Term Incentive Plan (the "Short-Term Plan") as applicable to LG&E and
KU. The LG&E and KU Remuneration Committee generally conducted its deliberations
in parallel with the Remuneration Committee of Powergen.

         The Companies' executive compensation program and the target awards and
opportunities for executives are designed to be competitive with the
compensation and pay programs of comparable companies, including utilities,
utility holding companies and companies in general industry nationwide. The
executive compensation program has been developed and implemented over time
through consultation with, and upon the recommendations of, recognized executive
compensation consultants. The Remuneration Committee and the Board of Directors
have continued access to such consultants as desired, and are provided with
independent compensation data for their review.

         Set forth below is a report addressing LG&E's and KU's compensation
policies during 2001 for their officers, including the executive officers named
in the following tables. In many cases, the executive officers also serve in
similar capacities for affiliates of LG&E and KU, including LG&E Energy. For
each of the executive officers of LG&E and KU, the policies and amounts
discussed below are for all services to LG&E, KU and their affiliates, during
the relevant period.

COMPENSATION PHILOSOPHY

         During 2001, LG&E's and KU's executive compensation program had three
major components: (1) base salary; (2) short-term or annual incentives; and (3)
long-term incentives. The Companies developed their executive compensation
program to focus on both short-term and long-term business objectives that are
designed to enhance overall shareholder value. The short-term and long-term
incentives were premised on the belief that the interests of executives should
be closely aligned with those of the Companies' SHAREHOLDERS. Based on this
philosophy, these two portions of each executive's total compensation package
were linked to the accomplishment of specific results that were designed to
benefit the Companies' shareholders in both the short-term and long-term.

         The executive compensation program also recognized that the Companies'
compensation practices must be competitive not only with utilities and utility
holding companies, but also with companies in general industry to ensure that a
stable and successful management team can be recruited and retained. As the
Companies' most direct competitors for executive talent are not limited to the
utilities, the various compensation peer groups as discussed below, are not the
same as the utility industry index in the Comparison of Five-Year Total Return
graph included in any applicable proxy statement.

         Pursuant to this competitive market positioning philosophy, in
establishing compensation levels for all executive positions for 2001, the
Remuneration Committee reviewed competitive compensation information for United
States general industry companies with revenue between $2 - $3 billion (the
"Survey Group") and established targeted total direct compensation (base salary
plus short-term incentives and long-term incentives) for each executive for 2001
to approach the 50th percentile of the competitive range from the Survey Group.
Salaries, short-term incentives and long-term incentives for 2001 are described
below.

         The 2001 compensation information set forth in other sections of this
document, particularly with respect to the tabular information presented,
reflects the considerations set forth in this report. The Base Salary,
Short-Term



Incentives, and Long-Term Incentives sections that follow address the
compensation philosophy for 2001 for all executive officers except those serving
as Chief Executive Officer. (See "Chief Executive Officer Compensation").

BASE SALARY

         The base salaries for LG&E and KU executive officers for 2000 were
designed to be competitive with the Survey Group at approximately the 50th
percentile of the base salary range for executives in similar positions with
companies in the Survey Group. Actual base salaries were determined based on
individual performance and experience.

SHORT-TERM INCENTIVES

         The Short-Term Plan provided for Company Performance Awards and
Individual Performance Awards, each of which is expressed as a percentage of
base salary and each of which is determined independent of the other. The
Remuneration Committee established the performance goals for the Company
Performance Awards and Individual Performance Awards at the beginning of the
2001 performance year. Payment of Company Performance Awards for executive
officers was based on varying performance measures tied to each officer's
responsible areas. These measures and goals included, among others, Powergen
earnings per share targets, LG&E Energy operating profit targets and LG&E/KU
operating profits targets, with any adjustments deemed appropriate by the
Committee. Payment of Individual Performance Awards was based 100% on Management
Effectiveness, which includes a customer satisfaction element for certain
participants. As stated, the awards varied within the executive officer group
based upon the nature of each individual's functional responsibilities.

         For 2001 the Company Performance Award targets for named executive
officers ranged from 29% to 31% of base salary, and the Individual Performance
Award targets ranged from 19% to 20% of base salary. Both awards were
established to be competitive with the 50th percentile of such awards granted to
comparable executives employed by companies in the Survey Group. The individual
officers were eligible to receive from 0% to 150% of their targeted amounts,
dependent upon Company performance as measured by the relevant performance
goals, with regard to Company Performance Awards, and were eligible to receive
from 0% to 175% of their targeted amounts dependent upon individual performance
as measured by management effectiveness ,with regard to Individual Performance
Awards.

         Using the relevant Powergen, LG&E Energy, LG&E/KU and other
subsidiaries' performance against goals in 2001, the Remuneration Committee
determined relative annual performance against targets for Company Performance
Awards. Based upon this determination, Company Performance Awards for 2001 to
the named executive officers were paid ranging from 34% to 43%, of base salary.
Payouts for Individual Performance Awards to the named executive officers ranged
from 22% to 29%, of base salary.

LONG-TERM INCENTIVES

         During 2001, the Long-Term Plan was administered by the Remuneration
Committee. The Long-Term Plan provides for the grant of any or all of the
following types of awards: stock options, stock appreciation rights, restricted
stock, performance units and performance shares. In 2001, the Remuneration
Committee chose to award stock options and performance units to executive
officers.

         The Remuneration Committee determined the competitive long-term grants
to be awarded for each executive based on the long-term awards for the 50th
percentile of the Survey Group. The aggregate expected value of the stock
options and performance units (delivered approximately 40% in the form of
performance units and 60% in the form of nonqualified stock options in 2001) was
intended to approach the expected value of long-term incentives payable to
executives in similar positions with companies in the 50th percentile of the
Survey Group, depending upon



achievement of targeted Company performance.

         Stock options were granted to executive officers and senior management
during the first quarter of 2001 at an exercise price equal to the fair market
value at the time of grant and were subject to a one-year vesting requirement.
During the year, newly hired or promoted officers were also eligible to receive
pro-rated stock option grants under the Long-Term Plan. Since options were
granted with an exercise price equal to the market value of Powergen's American
Depositary Shares ("ADS's") at the time of grant, they provide no value unless
Powergen's ADS price increases after the grants are awarded. Once the options
vest, they are exercisable over a nine-year term. These awards are thus tied to
ADS price appreciation in excess of the ADS's value at time of grant, rewarding
executives as if they shared in the ownership of Powergen. The estimated number
of ADS subject to options was determined by taking the expected value to be
provided in options, as determined above, and dividing that amount by the
estimated current value of an option using a variation of the Black-Scholes
option pricing methodology provided by the outside compensation consultant.
Prior awards were not considered when making new grants. The actual number of
options granted were then determined by approximating the average by officer
level within LG&E Energy.

         The number of performance units granted was determined by taking the
amount of the executive's long-term award to be delivered in performance units
(adjusted on a present value basis), as determined above, and dividing that
amount by the fair market value of Powergen ADS's on the date of the grant. The
future value of the performance units was substantially dependent upon the
changing value of Powergen ADS's in the marketplace. Each executive officer was
entitled to receive from 0% to 150% of the performance units contingently
awarded to the executive based on corporate performance measured in terms of the
achievement of certain cash flow targets by LG&E Energy during a three-year
performance period.

         No payouts of awards under the Long-Term Plan occurred during 2001 as
no three-year performance periods had been completed since the establishment of
the plan in December 2000 following Powergen's acquisition of LG&E Energy.
However, pursuant to the change in control provisions of the Long-Term Plan,
payouts of the two open performance period awards under the Long-Term Plan
occurred in April 2002 upon Powergen shareholder approval of the prospective
E.ON transaction. These payouts were based on LG&E Energy's performance through
that time for each of the partially completed 2001-2003 and 2002-2004
performance periods, respectively. For such periods, pursuant to the plan and
based upon LG&E Energy's performance through the change in control date, payouts
of performance units were made based upon their value as of grant date.

OTHER

         In connection with the LG&E Energy-Powergen merger, Messrs. Staffieri,
McCall and Newton entered into revised employment and severance agreements.
These agreements are discussed under "Employment Contracts and Termination of
Employment Arrangements and Change in Control Provisions". Pursuant to these
agreements and the relevant plans and following the change in control event
relating to the Powergen shareholder approval of the E.ON transaction, the
officers received payments described in that section. Certain of these payments
occurring in 2001 are included in the "All Other Compensation" column in the
Summary Compensation Table.

CHIEF EXECUTIVE OFFICER COMPENSATION

         Mr. Roger W. Hale served as Chief Executive Officer of LG&E and KU
during January-April 2001. The 2001 compensation of Mr. Hale is set forth in the
Summary Compensation Table, in the "Termination of Employment Agreements and
Change in Control Provisions" and in other sections of this document. Upon Mr.
Hale's retirement effective April 30, 2001, Mr. Victor A. Staffieri was
appointed Chief Executive Officer of LG&E and KU. Mr. Staffieri's compensation
was governed by the terms of an Employment and Severance Agreement entered into
on February 25, 2000 as amended (including upon his appointment as Chief
Executive Officer on April 30, 2001) (the



2000 Agreement. The 2000 Agreement is for an initial term of two years, with
automatic annual extensions thereafter unless the Companies or Mr. Staffieri
give notice of non-renewal.

         The 2000 Agreement established the minimum levels of Mr. Staffieri's
2001 compensation, although the Remuneration Committee retains discretion to
increase such compensation. Upon his appointment as Chief Executive Officer in
April 2001, the Remuneration Committee established Mr. Staffieri's compensation
and long-term awards using comparisons to relevant officer of companies in the
Survey Group, including utilities, and survey data from various compensation
consulting firms. Mr. Staffieri also received Companies' contributions to the
savings plan, similar to those of other officers and employees. Details of Mr.
Staffieri's 2001 compensation are set forth below.

 BASE SALARY. Mr. Staffieri was paid a total base salary of $555,769 during
2001. This amount was based upon the $600,000 minimum salary amount provided in
the 2000 Agreement during his service as Chief Executive Officer commencing in
April 2001. The Remuneration Committee, in determining Mr. Staffieri's annual
salary, including the minimum, considered his individual performance in the
prior growth of LG&E Energy, the comparative compensation data described above
and the compensation provided to other Powergen, LG&E Energy, LG&E and KU
officers

 SHORT-TERM INCENTIVES. Mr. Staffieri's target short-term incentive award was
70% of his 2001 base salary. As with other executive officers receiving
short-term incentive awards, Mr. Hale was eligible to receive more or less than
the targeted amount, based on Company performance and individual performance.
His 2001 short-term incentive payouts were based 60% on achievement of Company
Performance Award targets and 40% on achievement of Individual Performance Award
targets.

         For 2001, the Company Performance Award payout for Mr. Staffieri was
42% of his 2001 base salary and the Individual Performance Award payout was 45%
of his 2000 base salary. As with the other executive officers, Mr. Staffieri's
Company Performance targets were based on measures including Powergen earnings
per share goals and LG&E Energy operating profit goals and his Company
Performance Award was calculated based upon annual Company performance all as
described under the heading "Short-Term Incentives." In determining the
Individual Performance Award, the Remuneration Committee considered Mr.
Staffieri's effectiveness in several areas including the financial and
operational performance of LG&E Energy, LG&E, KU and other subsidiaries,
customer satisfaction ratings, Company growth and other measures.

 LONG-TERM INCENTIVE GRANT. In 2001, Mr. Staffieri received 51,011 options and
9,710 performance units for the 2001-2003 performance period. These amounts were
determined in accordance with the terms of his 2000 Agreement, as amended, with
expected value representing approximately 175% of his base salary. The terms of
the options and performance units (including the manner in which performance
units are earned) for Mr. Staffieri are the same as for other executive
officers, as described under the heading "Long-Term Incentives."

 LONG-TERM INCENTIVE PAYOUT. As with other executive officers, no payouts of
awards under the Long-Term Plan occurred in 2001 as no three-year performance
periods had yet been completed. As with other executive officers, pursuant to
the change in control provisions of the Long-Term Plan, payouts of the two open
performance period awards occurred in April 2002 upon Powergen shareholder
approval of the prospective E.ON transaction. Mr. Staffieri's Company
Performance Awards were paid out at value at grant date for the partially
completed 2001-2003 and 2002-2004 periods, respectively, as described under the
heading "Long-Term Incentives."

OTHER. During 2001, under the terms of the 2000 Agreement, Mr. Staffieri became
entitled to retention payments at six month intervals of $833,111 and $886,772,
which amounts were credited to his deferred compensation plan.

MEMBER OF THE REMUNERATION COMMITTEE

Dr. David K-P Li



EXECUTIVE COMPENSATION AND OTHER INFORMATION

         The following table shows the cash compensation paid or to be paid by
LG&E, KU or LG&E Energy, as well as certain other compensation paid or accrued
for those years, to the Chief Executive Officer and the next four highest
compensated executive officers of LG&E and KU who were serving as such at
December 31, 2001, as required, in all capacities in which they served LG&E
Energy or its subsidiaries during 1999, 2000 and 2001:

SUMMARY COMPENSATION TABLE



                                                                          LONG-TERM
                                                                         COMPENSATION
                                                                            AWARDS                PAYOUTS
                                                                            ------        ---------------------
                                      ANNUAL COMPENSATION      OTHER       RESTRICTED     SECURITIES                    ALL OTHER
                                      -------------------      ANNUAL        STOCK        UNDERLYING        LTIP         COMPEN-
           NAME AND                    SALARY     BONUS        COMP.         AWARDS      OPTIONS/SARS     PAYOUTS        SATION
      PRINCIPAL POSITION     YEAR       ($)        ($)          ($)         ($) (1)         (#) (2)       ($) (3)          ($)
      ------------------     ----      ------     -----         ---         -------         -------       -------      ------------
                                                                                              
Victor A. Staffieri            2001     555,769   529,330     45,704             --        51,011              0       1,811,703(4)
  Chairman of the Board,       2000     460,000   388,277     24,247        262,880(1)     90,000      1,051,694         640,160
  President and Chief          1999     400,000   324,600     22,730             --        53,050              0          20,604
  Executive Officer

John R. McCall                 2001     338,365   242,104      8,732             --        14,786              0         463,793(4)
  Executive Vice President,    2000     325,000   228,605     18,177        172,028(1)     40,000        570,565         677,097
  General Counsel and          1999     300,000   204,930      7,171             --        31,830              0          17,252
  Corporate Secretary

Frederick J. Newton III        2001     285,342   185,749      4,485             --        12,214              0         238,927(4)
  Senior Vice President        2000     272,000   191,325     14,970        143,974(1)     30,000        356,334         814,961
  and Chief Administrative     1999     255,000   171,641      6,731             --        12,219              0           8,712
  Officer

Paul W. Thompson               2001     245,193   142,650      9,970             --        10,714              0          30,292(4)
  Senior Vice President -
  Energy Services

S. Bradford Rives              2001     235,000   131,342      6,595             --         7,554              0         390,335(4)
  Senior Vice President -
  Finance and Controller

Roger W. Hale                  2001     301,523   255,582    109,142             --        76,519              0         565,524(4)
  Former Chairman of the       2000     816,200   803,761  3,546,581(6)          --       190,000      3,870,758       5,085,473
  Board and Chief Executive    1999     770,000   703,800     47,599      2,919,489(7)    102,122              0          55,596
  Officer (5)




- -------------

(1)      Amounts for year 2000 represents the dollar value of restricted
         Powergen ADS awards, determined by multiplying the number of ADSs in
         each award by the closing market price as of the effective date of
         the LG&E Energy-Powergen merger.. Pursuant to the terms of the named
         executives' employment agreements, the restricted Powergen ADS's
         vested upon occurrence of the change in control event associated
         with the Powergen shareholders' approval of the E.ON transaction in
         April 2002. Dividends on the restricted ADS's were payable upon
         vesting, without interest. Income tax was payable upon the awards at
         the time of vesting. At December 31, 2001, the restricted ADS
         holdings were Mr. Staffieri 7,688 ADS's ($335,581), Mr. McCall
         5,031ADS's ($219,603) and Mr. Newton 4,211 ADS's ($183,810),
         respectively.

(2)      Amounts for year 2001 reflect options for Powergen ADS's. Amounts for
         years 2000 and 1999 represent options for former LG&E Energy common
         stock.

(3)      No payouts under the Long-Term Plan were made during year 2001 as no
         three-year performance periods had yet been completed. As described
         in "Termination of Employment Arrangements and Change in Control
         Provisions" certain amounts have been accelerated during 2002 upon
         the change in control event resulting from the Powergen
         shareholders' approval of the E.ON transaction. Amounts for year 2000
         reflect acceleration of the 1998-2000, 1999-2001 and the 2000-2002
         open cycles upon a change in control event as a result of the LG&E
         Energy-Powergen merger.

(4)      Includes employer contributions to 401(k) plan, nonqualified thrift
         plan, employer paid life insurance premiums, and retention/termination
         payments in 2001 as follows: Mr. Staffieri $5,106, $23,135, $63,579 and
         $1,719,884, respectively; Mr. McCall $4,553, $29,905, $5,811 and
         $423,524 respectively; Mr. Newton $3,946, $12,327, $1,556 and $221,098,
         respectively; Mr. Thompson $2,365, $27,096, $830 and $0, respectively;
         Mr. Rives, $2,169, $4,881, $892 and $382,393, respectively; and Mr.
         Hale $4,544, $4,502, $0 and $556,478, respectively. The
         retention/termination payments are discussed in "Termination of
         Employment Arrangements and Change in Control Provisions".

(5)      Mr. Hale retired from service effective April 30, 2001.

(6)      Other Annual Compensation includes $63,693 for business spousal travel
         and personal use of corporate aircraft, and $3,470,524 in tax gross-up.

(7)      Amount for year 1999 represents dollar value of restricted stock
         awards, determined by multiplying the number of shares by the closing
         market price as of the receipt date of grant. After the effective date
         of the LG&E Energy-Powergen merger, pursuant to his 2000 Agreement, Mr.
         Hale's 147,382 restricted shares were converted to receive the merger
         consideration of $24.85 per share payable in respect of all outstanding
         shares of former LG&E Energy Common Stock. Income tax was payable upon
         the awards at the time of the satisfaction of this right.



                             OPTION/SAR GRANTS TABLE
                      OPTION/SAR GRANTS IN 2001 FISCAL YEAR

         The following table contains information at December 31, 2001, with
respect to grants of Powergen ADS options and stock appreciation rights (SARs)
to the named executive officers:



                                                                                                            POTENTIAL
                                                                                                       REALIZABLE VALUE AT
                          INDIVIDUAL GRANTS                                                              ASSUMED ANNUAL
                          -----------------                                                              RATES OF STOCK
                                                                                                       PRICE APPRECIATION
                                                                                                         FOR OPTION TERM
                            NUMBER OF          PERCENT OF                                                ---------------
                            SECURITIES           TOTAL           EXERCISE
                            UNDERLYING        OPTIONS/SARS        OR BASE
                           OPTIONS/SARS        GRANTED TO          PRICE
                             GRANTED          EMPLOYEES IN          ($/         EXPIRATION
         NAME                (#) (1)           FISCAL YEAR         SHARE)          DATE        0%($)        5% ($)         10%($)
         ----                -------           -----------         ------          ----        -----        ------         ------
                                                                                                     
Victor A. Staffieri                40,179              15.1%        39.225      03/02/2011          0        991,151      2,511,772
Victor A. Staffieri                10,832               4.1%        41.150      04/30/2011          0        246,356        656,306
John R. McCall                     14,786               5.6%        39.225      03/02/2011          0        364,747        924,340
Frederick J. Newton                12,214               4.6%        39.225      03/02/2011          0        301,300        763,553
Paul W. Thompson                   10,714               4.0%        39.225      03/02/2011          0        264,297        669,781
S. Bradford Rives                   7,554               2.8%        39.225      03/02/2011          0        186,345        472,235
Roger W. Hale                      76,519              28.8%        39.225      03/02/2011          0      1,887,601      4,783,551


- ---------------

(1)      Powergen ADS options were awarded at fair market value at time of
         grant.. The options are exercisable over a ten-year term from their
         original grant date.



                  OPTION/SAR EXERCISES AND YEAR-END VALUE TABLE
               AGGREGATED OPTION/SAR EXERCISES IN 2001 FISCAL YEAR
                          AND FY-END OPTION/SAR VALUES

         The following table sets forth information with respect to the named
executive officers concerning the exercise Powergen ADS options during 2001 and
the value of unexercised Powergen ADS options and SARs held by them as of
December 31, 2001:




                                                                                             NUMBER OF                VALUE OF
                                                                                             SECURITIES              UNEXERCISED
                                                                                             UNDERLYING              IN-THE-MONEY
                                                                 SHARES                      UNEXERCISED            OPTIONS/SARS AT
                                                                 ACQUIRED                    OPTIONS/SARS             FY-END
                                                                   ON        VALUE           AT FY-END (#)            ($)(1)
                                                                EXERCISE    REALIZED         EXERCISABLE/            EXERCISABLE/
NAME                                                               (#)        ($)            UNEXERCISABLE           UNEXERCISABLE
- ----                                                               ---        ---            -------------           -------------
                                                                                                     
Victor A. Staffieri                                                --          --          38,890 / 51,011       331,343 / 204,872
John R. McCall                                                     --          --          60,235 / 14,786       616,869 /  65,428
Frederick J. Newton                                                --          --          27,094 / 12,214       225,220 /  54,047
Paul W. Thompson                                                   --          --          13,244 / 10,714       106,839 /  47,409
S. Bradford Rives                                                  --          --          26,246 /  7,554       261,879 /  33,426
Roger W. Hale                                                      --          --          74,864 / 76,519       637,841 / 338,597


- ---------------

(1)      Dollar amounts reflect market value of Powergen ADS's at year-end,
         minus the exercise price.



                      LONG-TERM INCENTIVE PLAN AWARDS TABLE
               LONG-TERM INCENTIVE PLAN AWARDS IN 2001 FISCAL YEAR

         The following table provides information concerning awards of
performance shares made in 2001to the named executive officers under the
Long-Term Plan.




                                             ESTIMATED FUTURE PAYOUTS UNDER
                                               NON-STOCK PRICE BASED PLANS
                                                 (NUMBER OF SHARES) (1)
                                                 ----------------------

                                                NUMBER       PERFORMANCE OR
                                               OF SHARES,      OTHER PERIOD
                                               UNITS OR          UNTIL
                                                OTHER         MATURATION
                  NAME                          RIGHTS        OR PAYOUT(1)       THRESHOLD(#)        TARGET(#)       MAXIMUM(#)
                  ----                          ------        ------------       ------------        ---------       ----------
                                                                                                      
Victor A. Staffieri                               9,710         12/31/2003              4,855           9,710           14,565
John R. McCall                                    2,815         12/31/2003              1,408           2,815            4,223
Frederick J. Newton                               2,325         12/31/2003              1,163           2,325            3,488
Paul W. Thompson                                  2,040         12/31/2003              1,020           2,040            3,060
S. Bradford Rives                                 1,438         12/31/2003                719           1,438            2,157
Roger W. Hale                                    14,566         12/31/2003              7,283          14,566           21,849


- ----------------

(1)      Pursuant to the terms of the plan, the performance periods shown and
         subsequent grants were accelerated upon the change in control resulting
         from the Powergen shareholder approval of the E.ON transaction and were
         paid in cash after April 19, 2002.


         Each performance unit awarded represented the right to receive an
amount payable 50% in Powergen ADS's and 50% in cash on the date of payout, the
latter portion being payable in cash in order to facilitate the payment of taxes
by the recipient. The amount of the payout was to be determined by the then-fair
market value of Powergen ADS's. For awards made in 2001, the Long- Term Plan
awards were intended to reward executives on a three-year rolling basis
dependent upon the achievement of certain cash flow targets by LG&E Energy. The
Committee set a contingent award for each management level selected to
participate in the plan and such amount was the basis upon which incentive
compensation was to be determined. Depending on the level of achievement, the
participant would receive from zero to 150% of the contingent award amount. As a
result of the change in control event resulting from Powergen shareholder
approval of the E.ON transaction, awards were accelerated and paid out based
upon value on grant date. Payments made under the Long-Term Plan in 2001 are
reported in the summary compensation table for the year of payout.

EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT
ARRANGEMENTS AND CHANGE IN CONTROL PROVISIONS

         In connection with the LG&E Energy-Powergen merger, Messrs. Staffieri,
McCall and Newton entered into revised employment and severance agreements,
which were subsequently amended prior to the effectiveness of the merger, with
two year terms, each containing change in control provisions, which agreements
generally provide for the benefits described below. These officers of the
Companies shall be entitled to the following payments if they are terminated for
reasons other than cause or disability or death, or their employment
responsibilities are altered: (A) acceleration of any unpaid scheduled retention
payments in certain amounts, (B) a cash payment of $262,835,



$172,028 and $143,974, respectively, and the vesting of the restricted
Powergen ADS's and dividends described in the Summary Compensation Table
contained in this document; and (C) an amount not less than the sum of (1)
his annual base salary and (2) his bonus or "target" award paid or payable,
prorated for the number of months remaining in the term of the employment
period (which payment shall be increased to 2.99 times the sum of (1) and (2)
in the event of a termination following a change in control of Powergen). In
addition, such officers would receive, upon the earlier to occur of (a) a
change in control of Powergen or (b) the 18 month anniversary of their
employment agreement, the amounts described in clauses (A) and (B) above.

         During 2001, in connection with these or related arrangements, Messrs.
Staffieri, McCall, Newton and Rives received or became entitled to scheduled
retention payments of $1,719,884, $423,524, $221,098 and $382,393,
respectively. In April 2002, in connection with the change in control event
occurring upon the Powergen shareholders' approval of the E.ON transaction
during that month, Messrs. Staffieri, McCall and Newton received or became
entitled to accelerated retention payments, including interest, of $851,094,
$501,145 and $507,858, respectively and the amounts described in clause (B)
above. Further, upon this change in control event, pursuant to the Long-Term
Plan, respectively, any unvested options vested and outstanding performance
units were paid out in cash.

         Payments may be made to executives which would equal or exceed an
amount which would constitute a nondeductible payment pursuant to Section 280G
of the Code, if any. Additionally, executives shall receive continuation of
certain welfare benefits and payments in respect of accrued but unused vacation
days and for out-placement assistance. A change in control encompasses certain
merger and acquisition events, changes in board membership and acquisitions of
voting securities of Powergen.

         During 2001, Mr. Hale served as Chief Executive Officer of LG&E and KU
until his retirement from service on April 30, 2001. In connection therewith,
Mr. Hale qualified for a new supplemental retirement benefit in an annual amount
equal to 50% of the sum of his base salary and annual target bonus as in effect
on the date of his retirement.