10-K/A 1 a2078273z10-ka.htm FORM 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

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.

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

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.

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

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

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.

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.

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.

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

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

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.

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.

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.

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.

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

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.

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

(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

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.

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

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.

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.

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

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

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.

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 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.

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			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

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.

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

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

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.

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

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.

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.

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

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.

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.

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

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.

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.

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.

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.

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 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 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			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.

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).

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

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.

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.

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.

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	)

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

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

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.

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.

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

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.

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.

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,

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.

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.

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

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.

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.

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

			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.

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.

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.

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.

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.

Management expects to renew these facilities when they expire.

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.

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

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.

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

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.

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.

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.

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.

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

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

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

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.

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

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

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.

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.

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.

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.

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,

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

Note 16—Subsequent Events

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.

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

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

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

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

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

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

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.

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.

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.

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.

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

100

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.

Management expects to renew these facilities when they expire.

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

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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.

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.

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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.

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.

		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	%

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		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

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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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

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

Note 11—Commitments and Contingencies

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

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

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

Environmental. The Clean Air Act imposed stringent new SO₂ and NOx emission limits on electric generating units. KU met its Phase I SO₂requirements primarily through installation of a scrubber on Ghent Unit 1. KU's strategy for Phase II SO₂ reductions, which commenced January 1, 2000, is to use accumulated emissions allowances to delay additional capital expenditures and may also

113

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

In September 1998, the EPA announced its final "NOx SIP Call" rule requiring states to impose significant additional reductions in NOx emissions by May 2003, in order to mitigate alleged ozone transport impacts on the Northeast region. The Commonwealth of Kentucky is currently in the process of revising its State Implementation Plan or "SIP" to require reductions in NOx emissions from coal-fired generating units to the 0.15 lb./Mmbtu level on a system-wide basis. In related proceedings in response to petitions filed by various Northeast states, in December 1999, EPA issued a final rule pursuant to Section 126 of the Clean Air Act directing similar NOx reductions from a number of specifically targeted generating units including all KU units in the eastern half of Kentucky. Additional petitions currently pending before EPA may potentially result in rules encompassing KU's remaining generating units. As a result of appeals to both rules, the compliance date was extended to May 2004. All KU generating units are subject to the May 2004 compliance date under these NOx emissions reduction rules.

KU is currently implementing a plan for adding significant additional NOx controls to its generating units. Installation of additional NOx controls will proceed on a phased basis, with installation of controls commencing in late 2000 and continuing through the final compliance date. In addition, KU will incur additional operation and maintenance costs in operating new NOx controls. KU believes its costs in this regard to be comparable to those of similarly situated utilities with like generation assets. KU anticipated that such capital and operating costs are the type of costs that are eligible for recovery from customers under its environmental surcharge mechanism and believed that a significant portion of such costs could be recovered. In April 2001, the Kentucky Commission granted recovery of these costs for KU.

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

114

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

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

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

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

2002	$	37,788
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)

	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

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.

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.

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.

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

	Applicable to Form 10-K of
	Applicable to Form 10-K of		Description
Exhibit No.	LG&E	KU	Description

2.01	x	x	Copy of Agreement and Plan of Merger, dated as of February 27, 2000, by and among Powergen plc, LG&E Energy Corp., US Subholdco2 and Merger Sub, including certain exhibits thereto. [Filed as Exhibit 1 to LG&E's and KU's Current Report on Form 8-K filed February 29, 2000 and incorporated by reference herein]
2.02	x	x	Amendment No. 1 to Agreement and Plan of merger, dated as of December 8, 2000, among LG&E Energy Corp., Powergen plc, Powergen US Investments Corp. and Powergen Acquisition Corp. [Filed as Exhibit 2.01 to LG&E's and KU's Current Report on Form 8-K filed December 11, 2000 and incorporated by reference herein]
2.03	x	x	Copy of Agreement and Plan of Merger, dated as of May 20, 1997, by and between LG&E Energy and KU Energy, including certain exhibits thereto. [Filed as Exhibit 2 to LG&E's and KU's Current Report on Form 8-K filed May 30, 1997 and incorporated by reference herein]
3.01	x		Copy of Restated Articles of Incorporation of LG&E, dated November 6, 1996. [Filed as Exhibit 3.06 to LG&E 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

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

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

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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.