10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C.  20549

FORM 10-K

(Mark One)

ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
For the fiscal year ended December 31, 2003
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)

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

Indicate by check mark whether the registrants (1) have filed 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.  o

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

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

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

Not applicable.

TABLE OF CONTENTS

PART I
Item 1.	Business.
	Louisville Gas and Electric Company
	General
	Electric Operations
	Gas Operations
	Rates and Regulation
	Construction Program and Financing
	Coal Supply
	Gas Supply
	Environmental Matters
	Competition
	Kentucky Utilities Company
	General
	Electric Operations
	Rates and Regulation
	Construction Program and Financing
	Coal Supply
	Environmental Matters
	Competition
	Employees and Labor Relations
	Executive Officers of the Companies
Item 2.	Properties.
Item 3.	Legal Proceedings.
Item 4.	Submission of Matters to a Vote of Security Holders.
PART II
Item 5.	Market for the Registrant’s Common Equity and Related Stockholder Matters.
Item 6.	Selected Financial Data.
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operation.
	Louisville Gas and Electric Company
	Kentucky Utilities Company
Item 7A.	Quantitative and Qualitative Disclosure About Market Risk.
Item 8.	Financial Statements and Supplementary Data.
	Louisville Gas and Electric Company
	Kentucky Utilities Company
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
Item 9A.	Controls and Procedures.
PART III
Item 10.	Directors and Executive Officers of Registrant (a).
Item 11.	Executive Compensation (a).
Item 12.	Security Ownership of Certain Beneficial Owners and Management (a).
Item 13.	Certain Relationships and Related Transactions (a).
Item 14.	Principal Accountant Fees and Services.
PART IV
Item 15.	Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
Signatures

(a) Incorporated by reference.

INDEX OF ABBREVIATIONS

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

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

PART I

Item 1.  Business.

LG&E and KU are each subsidiaries of LG&E Energy.  On December 11, 2000, LG&E Energy Corp., now LG&E Energy LLC, was acquired by Powergen plc, now known as Powergen Limited, for cash of approximately $3.2 billion 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.  Following the acquisition, Powergen became a registered holding company under PUHCA, and LG&E and KU, as subsidiaries of a registered holding company, became subject to additional regulation under PUHCA.

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

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

Following the purchase of Powergen by E.ON, E.ON became a registered holding company under PUHCA.  As a result, E.ON, its utility subsidiaries, including LG&E and 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.  LG&E and KU believe that they have adequate authority (including financing authority) under existing SEC orders and regulations to conduct their business.  LG&E and KU will seek additional authorization when necessary.

As contemplated in their regulatory filings in connection with the E.ON acquisition, E.ON, Powergen and LG&E Energy completed an administrative reorganization to move the LG&E Energy group from an indirect Powergen subsidiary to an indirect E.ON subsidiary.  This reorganization was effective in March 2003.  In early 2004, LG&E Energy began direct reporting arrangements to E.ON.

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

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

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LOUISVILLE GAS AND ELECTRIC COMPANY

General

LG&E, incorporated in 1913 in Kentucky, is a regulated public utility that supplies natural gas to approximately 312,000 customers and electricity to approximately 384,000 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, 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 which commenced in February 2001.  LG&E completed its accounts receivable securitization arrangements involving LG&E R in January 2004 and LG&E R is currently inactive.

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

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

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

Electric Operations

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

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

2

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

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

The electric utility business is affected by seasonal 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 a 13% – 15% reserve margin range.  At December 31, 2003, LG&E owned steam and combustion turbine generating facilities with a net summer capability of 2,878 Mw and an 80 Mw nameplate-rated hydroelectric facility on the Ohio River with a summer capability rate of 48 Mw.  See Item 2, Properties.  LG&E also obtains power from other utilities under bulk power purchase and interchange contracts.  At December 31, 2003, LG&E’s system net summer capability, including purchases from others and excluding the hydroelectric facility, was 3,032 Mw.  See Item 2, Properties.

LG&E and 11 other electric utilities are participating owners of OVEC located in Piketon, Ohio.  LG&E’s investment in OVEC is the equivalent of 4.9% of OVEC’s common stock.  OVEC owns and operates two power plants that burn coal to generate electricity, Kyger Creek Station in Ohio and Clifty Creek Station in Indiana.  LG&E’s share is 7%, representing approximately 155 Mw of generation capacity.

LG&E and KU are founding members of the MISO.  Membership was obtained in 1998 in response to and consistent with federal policy initiatives. It began commercial operations in February 2002.  At that time, as members of the MISO, LG&E and KU turned over operational control of its high-voltage transmission facilities (100 kV and greater), while continuing to control and operate the lower voltage transmission subject to the terms and conditions of the MISO.  The MISO currently controls over 100,000 miles of transmission over 1.1 million square miles located in the northern Midwest between Manitoba, Canada and Kentucky.  In September 2002, FERC granted a 12.88% ROE on transmission facilities for LG&E, KU and the rest of the MISO owners. As a transmission-owning member of the MISO, LG&E and KU also incur administrative costs through MISO Schedule 10.  The MISO uses Schedule 10 as a means to recover operational and capital costs for providing system operator services to its members.  For discussion of current MISO 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 also has agreements with a 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.

3

Gas Operations

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

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

The gas utility business is affected by seasonal weather patterns.  As a result, operating revenues (and associated operating expenses) are not generated evenly throughout the year.  While natural gas usage patterns are seasonal, LG&E received approval from the Kentucky Commission for a Weather Normalization Adjustment (“WNA”) mechanism.  The WNA mechanism adjusts the non-gas base portion of the natural gas billings of residential and commercial customers to normal temperatures during the heating season months of December through April, somewhat mitigating the effect of weather extremes on gas revenue.  LG&E has requested, and the Kentucky Commission has approved an extension of the current WNA mechanism through April 30, 2006.  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 storage capacity, LG&E would be forced to buy additional gas and pipeline transportation services during the winter months when customer demand increases and when the prices for gas supply and transportation services are typically 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 lower than state and national averages.  At December 31, 2003, LG&E had an inventory balance of gas stored underground of approximately 12.9 million Mcf valued at approximately $69.9 million.

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 approximately one-fourth of LG&E’s annual throughput.

4

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

Rates and Regulation

Following the purchase of Powergen by E.ON, E.ON became a registered holding company under PUHCA.  As a result, E.ON, its utility subsidiaries, including LG&E, and certain of its non-utility subsidiaries are subject 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.  LG&E believes that it has adequate authority (including financing authority) under existing SEC orders and regulations to conduct its business.  LG&E will seek additional authorization when necessary.

The Kentucky Commission has regulatory jurisdiction over LG&E’s retail rates and service, 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.  FERC has classified LG&E as a “public utility” as defined in the FPA. The Department of Energy and FERC have jurisdiction under the FPA over certain electric utility facilities and operations, wholesale sale of power and related transactions, accounting practices of LG&E, and in certain other respects as provided in the FPA.

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.

LG&E’s retail electric rates contain an FAC, whereby increases and decreases in the cost of fuel for electric generation are reflected in the rates charged to retail 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 retail electric rates are subject to an ESM.  The ESM, initially 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, the excess earnings are shared 40% with ratepayers and 60% with shareholders; if earnings are below the lower limit, the earnings deficiency is recovered 40% from ratepayers and 60% from shareholders.  By order of the Kentucky Commission, rate changes prompted by the ESM filing go into effect in April of each year subject to a balancing adjustment in successive periods.

In November 2002, LG&E filed a revised ESM tariff which proposed continuance of the existing ESM through 2005.  In addition, the Kentucky Commission initiated a focused management audit to review the ESM plan and reassess its reasonableness, and recently concluded discovery in the case.  LG&E and interested parties had the opportunity to provide recommendations for modification and continuance of the ESM or other forms of alternative or incentive regulation.  Continuance of the ESM is still being deliberated by the Kentucky Commission and a final order is not expected until the second quarter of 2004.  The ESM tariff remains in effect pending

5

 the resolution of the case.

LG&E’s retail 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.

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 most recent integrated resource plan (“IRP”) in October 2002.  The Kentucky Commission issued its Staff Report and ordered the case closed in December 2003 with no significant findings.  The next IRP is due April 2005 and will incorporate the recommendations from the Staff Report regarding the 2002 IRP.

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

For 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.

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 interest rates, economic conditions, construction costs, and new environmental or other governmental laws and regulations.

During the five years ended December 31, 2003, gross property additions amounted to approximately $1 billion. Internally generated funds and external financings for the five-year period were utilized to provide for these gross additions.  The gross additions during this period amounted to approximately 27% of total utility plant at December 31, 2003, and consisted of $870 million for electric properties and $155 million for gas properties.  Gross retirements during the same period were $116 million, consisting of $80 million for electric properties and $36 million for gas properties.

6

Coal Supply

Coal-fired generating units provided over 98% of LG&E’s net kilowatt-hour generation for 2003.  The remaining net generation for 2003 was provided by natural gas and oil-fueled combustion turbine peaking units and a hydroelectric plant.  Coal is expected to 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 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.

LG&E 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.  LG&E intends to meet a portion of its coal requirements with three-year or shorter contracts.  As part of this strategy, LG&E will continue to negotiate replacement contracts as contracts expire.  LG&E does not anticipate any problems negotiating new contracts for future coal needs.  The balance of coal requirements will be met through spot purchases.  LG&E had a coal inventory of approximately 1.04 million tons, or a53-day supply, on hand at December 31, 2003.

LG&E expects to continue purchasing most of its coal, with sulfur content in the 2%-4.5% range, from western Kentucky, southern 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 electric service in compliance with existing environmental laws and regulations.

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

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

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

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

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 and Tennessee Gas.

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

LG&E transports on the Texas Gas system under Rate Schedules No-Notice Service (“NNS”) and Firm

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Transportation (“FT”) service.  During the winter months, LG&E has 184,900 Mmbtu/day in NNS and 36,000 Mmbtu/day in FT service.  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.  For January 2004 only, LG&E contracted for short-term firm transportation service from Texas Gas under Rate Schedule STF in the amount of 15,000 Mmbtu/day.  LG&E also transports on the Tennessee Gas system under Tennessee Gas’s Rate Schedule FT-A.  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 2007.

LG&E also has a portfolio of supply arrangements of various terms with a number of suppliers designed 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 gas customers.

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

The estimated maximum deliverability from storage during the early part of the heating season is typically 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 $6.30 in 2003, $4.19 in 2002, and $5.27 in 2001.  Natural gas prices in the unregulated wholesale market generally have increased significantly over the last few years beginning in 2000.  These increases in natural gas prices, caused in part by decreased natural gas production, decreased liquidity in the marketplace, and increased demand for natural gas as a fuel for electric generation have been significantly affected by changing national gas storage inventory levels.  LG&E relies upon storage to mitigate the price volatility to which customers might otherwise be exposed.

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 2003, expenditures for pollution control facilities represented $269.9 million or 26% of total construction expenditures.  LG&E estimates that construction expenditures for the installation of NOx control equipment from 2004 through 2005 will be approximately $5.1 million.  For a discussion of environmental matters, see Rates and Regulation for LG&E under Item 7 and Note 11 of LG&E’s Notes to Financial Statements under Item 8.

Competition

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

At this time, 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.

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KENTUCKY UTILITIES COMPANY

General

KU, incorporated in Kentucky in 1912 and incorporated in Virginia in 1991, is a regulated public utility engaged in producing, transmitting and selling electric energy.  KU provides electric service to approximately 482,000 customers in over 600 communities and adjacent suburban and rural areas in 77 counties in central, southeastern and western Kentucky, to approximately 30,000 customers in 5counties in southwestern Virginia and to less than 10 customers in Tennessee.  In Virginia, KU operates under the name Old Dominion Power Company.  KU operates under appropriate franchises in substantially all of the 161 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 which commenced in February 2001.  KU completed its accounts receivable securitization arrangements involving KU R in January 2004 and KU R is currently inactive.

Electric Operations

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

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

KU’s weighted-average system-wide emission rate for sulfur dioxide in 2003 was approximately1.4lbs./Mmbtuof heat input, with every generating unit below its emission limit established by the Kentucky Division for Air Quality.

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

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was -1 degree 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 KU’s Results of Operations under Item 7.

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

Under a contract expiring in 2020 with OMU, KU has agreed to purchase from OMU the surplus output of the 142-Mw and 265-Mw generating units at OMU’s Elmer Smith station.  Purchases under the contract are made under a contractual formula resulting in costs which are expected to be comparable to the cost of other power purchased or generated by KU.  Such power equated to approximately 10% of KU’s net generation system output during 2003.  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 equated to approximately 9% of KU’s net generation system output in 2003.  See Note 11 of KU’s Notes to Financial Statements under Item 8.

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

KU and LG&E are founding members of the MISO.  Membership was obtained in 1998 in response to and consistent with federal policy initiatives.  It began commercial operations in February 2002.  At that time, as members of the MISO, KU and LG&E turned over operational control of its high-voltage transmission facilities (100 kV and greater), while continuing to control and operate the lower voltage transmission subject to the terms and conditions of the MISO.  The MISO currently controls over 100,000 miles of transmission over 1.1 million square miles located in the northern Midwest between Manitoba, Canada and Kentucky.  In September 2002, FERC granted a 12.88% ROE on transmission facilities for LG&E, KU and the rest of the MISO owners.  As a transmission-owning member of the MISO, KU and LG&E also incur administrative costs through MISO Schedule 10.  The MISO uses Schedule 10 as a means to recover operational and capital costs for providing system operator services to its members.  For discussion of current MISO matters, see Rates and Regulation for KU under Item 7 and Note 3 of KU’s Notes to Financial Statements under Item 8.

KU also has agreements with a 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 systems.

Rates and Regulation

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

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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.  KU believes that it has adequate authority (including financing authority) under existing SEC orders and regulations to conduct its business.  KU 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 served five customers at December 31, 2003, KU is subject to the jurisdiction of the TRA. FERC has classified KU as a “public utility” as defined in the FPA.  The Department of Energy and FERC have jurisdiction under the FPA over certain of the electric utility facilities and operations, wholesale sale of power and related transactions, accounting practices of KU, and in certain other respects as provided in the FPA.

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.

KU’s Kentucky retail electric rates contain an FAC, whereby increases and decreases in the cost of fuel for electric generation are reflected in the rates charged to retail 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, initially 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, the excess earnings are shared 40% with ratepayers and 60% with shareholders; if earnings are below the lower limit, the earnings deficiency is recovered 40% from ratepayers and 60% from shareholders.  By order of the Kentucky Commission, rate changes prompted by the ESM filing go into effect in April of each year subject to a balancing adjustment in successive periods.

In November 2002, KU filed a revised ESM tariff which proposed continuance of the existing ESM through 2005.  In addition, the Kentucky Commission initiated a focused management audit to review the ESM plan and reassess its reasonableness, and recently concluded discovery in the case.  KU and interested parties had the opportunity to provide recommendations for modification and continuance of the ESM or other forms of alternative or incentive regulation.  Continuance of the ESM is still being deliberated by the Kentucky Commission and a final order is not expected until the second quarter of 2004.  The ESM tariff remains in effect pending the resolution of the case.

KU’s Kentucky retail 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

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

The Commonwealth of Virginia passed the Virginia Electric Utility Restructuring Act in 1999.  This act gives Virginia customers a choice for energy services.  The change was phased in gradually between January 2002 and January 2004.  In 2002, KU filed prospective unbundled rate schedules which included a cap at current levels from January 2002 through June 2007.  The Virginia Commission granted KU a waiver from retail choice and the associated rate filings through December 2004.  Additionally, in March 2003, the General Assembly of Virginia amended and reenacted Section 56-580 of the Code of Virginia with language that effectively exempts all KU Virginia service territory from retail choice and the associated rate filings until such time as retail choice is offered to other customers in KU’s other service territories.

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

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.

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 interest rates, economic conditions, construction costs, and new environmental or other governmental laws and regulations.

During the five years ended December 31, 2003, gross property additions amounted to approximately $1 billion. Internally generated funds and external financings for the five-year period were utilized to provide for these gross additions.  The gross additions during this period amounted to approximately 28% of total utility plant at December 31, 2003.  Gross retirements during the same period were $90 million.

Coal Supply

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

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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 1.2 million tons, or a 60-day supply, on hand at December 31, 2003.

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

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

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

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

KU’s historical average cost of coal purchased is higher 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 during 2004 is expected to remain at approximately the same level as 2003.

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 2003, expenditures for pollution control facilities represented $201.8 million or 20% of total construction expenditures. KU estimates that construction expenditures for the installation of NOx control equipment from 2004 through 2005 will be approximately $58.9 million.  For a discussion of environmental matters, see Rates and Regulation for KU under Item 7 and Note 11 of KU’s Notes to Financial Statements under Item 8.

Competition

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

At this time, 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.

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

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EMPLOYEES AND LABOR RELATIONS

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

As a result of the Powergen acquisition and in order to comply with PUHCA, LG&E Services was formed effective on January 1, 2001.  LG&E Services provides certain services to affiliated entities, including LG&E and KU, at cost as required under PUHCA.  On January 1, 2001, approximately 1,000 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 the workforce separation program in effect for 2001.

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

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

The present term of office of each of the above executive officers extends to the meeting of the Board of Directors following the 2004 Annual Meeting of Shareholders.

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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, 2003.  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 Chief Financial Officer of LG&E Energy and LG&E from May 1997 to February 1999, (including Chief Financial Officer of KU from May 1998 to February 1999) and President and Chief Operating Officer of LG&E Energy from March 1999 to April 2001 (including President of LG&E and KU from June 2000 to April 2001).

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

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

Before he was elected to his current positions, Mr. Thompson was Vice President - Business Development for LG&E Energy 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 from August 1999 to June 2000.

Before he was elected to his current positions, Mr. Hermann was Vice President, Business Integration of LG&E from June 1997 to May 1998; 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; and Senior Vice President - Distribution Operations, from December 2000 to February 2003.

Before she was elected to her current positions, Ms. Welsh was Vice President, Administration of LG&E Energy 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 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.; and Vice President, Energy Marketing from August 1998 to December 2000 for LG&E Energy.

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 organization of LG&E and KU from November 1994 to December 2000, and was Vice President - Retail Services from December 2000 to March 2003.

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

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

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

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

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

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

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

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

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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 unless otherwise stated:

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

(a)Amount shown represents LG&E’s 75% interest in Trimble County 1.  See Notes 11 and 12 of LG&E’s Notes to Financial Statements under Item 8 for further discussion on ownership.

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

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

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

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

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

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

LG&E operates underground gas storage facilities with a current working gas capacity of approximately15.1million 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 was renegotiated in 2002 and is scheduled to expire July 31, 2015.

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.  In addition, Fidelia Corporation, an affiliate of E.ON, has a second lien on the property subject to the first mortgage bond lien.  The second lien secures loans provided by Fidelia.

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

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

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

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

(c)Amount shown represents KU’s 71% interest in Units 5 and 6 at Trimble County.  See Notes 11 and 12 of KU’s Notes to Financial Statements, under Item 8 for further discussion on ownership.  LG&E operates these units on behalf of KU.

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

At December 31, 2003, KU’s electric transmission system included 112 substations with a total capacity of approximately 16,991,000 Kva and approximately 4,233 structure miles of lines.  The electric distribution system included 466 substations with a total capacity of approximately 4,509,000 Kva and 12,744 structure miles of lines.

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

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

ITEM 3.  Legal Proceedings.

Rates and Regulatory Matters

For a discussion of current rate and regulatory matters, including electric and gas base rate increase proceedings, earnings sharing mechanism proceedings, MISO proceedings, merger surcredit proceedings, and other rate or regulatory matters affecting LG&E and KU, see Rates and Regulation under Item 1, 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.

Environmental

For a discussion of environmental matters including currently proposed reductions in NOx emission limits; items regarding LG&E’s Mill Creek generating plant, KU’s E.W. Brown plant and LG&E’s and KU’s manufactured gas plant sites; and other environmental items affecting LG&E and KU, see Environmental Matters under Item 7 and Note 11 of LG&E’s Notes to Financial Statements and Note 11 of KU’s Notes to Financial Statements under Item 8, respectively.

LG&E Employment Discrimination Case

In October 2001, approximately 30 employees or former employees filed a complaint against LG&E claiming past and current instances of employment discrimination against LG&E.  LG&E has removed the case to the U.S. District Court for the Western District of Kentucky and filed an answer denying all plaintiffs’ claims.  The U.S. Equal Employment Opportunity Commission has declined to proceed to litigation on any claims reviewed. Through continuing mediation, settlements have been reached with the majority of plaintiffs, including the lead plaintiff.  Negotiations continue with nine plaintiffs.  The complaint contains a claimed damage amount of $100 million as well as requests for injunctive relief.  Prior settlements have been for non-material amounts and

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

Combustion Turbine Litigation

In October 2003, LG&E and KU and third parties completed a settlement agreement and subsequently dismissed the Companies’ previously reported lawsuit in the U.S. District Court for the Eastern District of Kentucky against Alstom Power, Inc. The suit concerned two combustion turbines supplied by Alstom during 1999 and jointly owned by LG&E and KU. The settlement agreement provides for an aggregate $20 million in reimbursement in two installments to be paid in January and April 2004 to LG&E and KU for the Companies’ expenditures incurred regarding the turbines. The payments, secured by letters of credit provided during 2003, were included in the Companies’ 2003 results.  The January 2004 payment was received by the Companies.  The parties also entered into a long-term service agreement, whereby Alstom will provide to LG&E and KU certain future inspections, repairs and services for the turbines.

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.

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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 16, 2003.

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:

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

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

Dr. Hans Michael Gaul - 21,294,223 common shares and 71,068 preferred shares cast in favor of election and 1,317 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 72,073 preferred shares in favor of and 258 preferred shares against the approval of PricewaterhouseCoopers LLP as independent accountants for 2003.  Holders of 54 preferred shares abstained from voting on this matter.

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

2.KU

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

37,817,878 common shares cast in favor of election and no shares withheld for each of Michael Söhlke, Victor A. Staffieri and Dr. Hans Michael Gaul, 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 2003.

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

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

d)Not applicable.

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PART II.

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

LG&E:

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

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

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

KU:

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

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ITEM 6.  Selected Financial Data.

The 1999 and 2000 consolidated financial data were derived from financial statements audited by Arthur Andersen LLP, independent accountants, who expressed an unqualified opinion on those financial statements in their report dated January 26, 2001, before the revisions required by EITF 02-03.  Arthur Andersen LLP has ceased operations.  The amounts shown below for such periods, reclassified pursuant to the adoption of EITF 02-03, are unaudited.

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

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

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

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

GENERAL

The following discussion and analysis by management focuses on those factors that had a material effect on LG&E’s and KU’s financial results of operations and financial condition during 2003, 2002, and 2001 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 materially vary.  Factors that could cause actual results to materially differ 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; actions by credit rating agencies; and other factors described from time to time in LG&E’s and KU’s reports to the SEC, including Exhibit No. 99.01 to this report on Form 10-K.

EXECUTIVE SUMMARY

Overview

LG&E and KU continue profitable operations despite national and regional economic weakness and turmoil in the U.S. energy industry.  LG&E and KU enjoy a competitive cost advantage relative to the U.S. industry average and high customer satisfaction ratings. During 2003, the Companies were awarded first place in the region by J.D. Power in the 2003 Residential Customer Satisfaction Survey and a national first place in the Midsize Business Survey.

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

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

Major Strategic Goals

LG&E’s and KU’s major strategic goals are to continue to be leading electric and gas utilities by meeting their utility native load and reliability requirements while managing business, environmental and regulatory risks; by maintaining excellent customer service and reputation with all stakeholders; by engaging in continuous improvement to foster efficiency; by securing a foundation for future regulatory support; and, by developing transferable utility best practices business models.

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

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

Current Trends

Although the stock market has rebounded somewhat, industrial energy demand and the employment market remain dampened.  Short-term interest rates have fallen to forty-year lows and consensus forecasts continue to predict gradual economic recovery over time.  Natural gas prices have been volatile and have increased significantly, further aggravating the U.S. economy’s recovery.  Peak wholesale electric prices have risen as a result of gas price increases, even with continued overcapacity in many regions, favoring coal-fired generators like LG&E and KU.

The U.S. energy industry is still in the grips of national regulatory uncertainty and financial turmoil, highlighting the strength of companies with integrated utility operations.  Deregulation momentum is stalled or abandoned in most states, with national attention on the economy and international issues.  The Kentucky legislature did not take any action in either 2002 or 2003 to move Kentucky towards electric deregulation.  The nature or timing of the ultimate legislative or regulatory actions regarding industry restructuring and their impact on LG&E and KU, which may be significant, cannot currently be predicted.

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

Also, the FERC issued a NOPR in July 2002 which would substantially alter the regulations governing the nation’s wholesale electricity markets by establishing a common set of rules, defined as SMD.  The FERC NOPR has met opposition, even after revision, and implementation is uncertain.  Prolonged litigation is likely over any contentious provisions. Low cost states are wary of grid reforms and increased cost burdens. There are still fundamental differences over federal and state jurisdictional issues and prerogatives.  Kentucky regulators and political leaders are in the forefront of opposition to broad federal mandates on utility related issues.

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

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

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

MERGERS AND ACQUISITIONS

LG&E and KU are each subsidiaries of LG&E Energy.  On December 11, 2000, LG&E Energy Corp., now LG&E Energy LLC, was acquired by Powergen plc, now known as Powergen Limited, for cash of approximately $3.2 billion 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.  Following the acquisition, Powergen became a registered holding company under PUHCA, and LG&E and KU, as subsidiaries of a registered holding company, became subject to additional regulation under PUHCA.

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

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

Following the purchase of Powergen by E.ON, E.ON became a registered holding company under PUHCA.  As a result, E.ON, its utility subsidiaries, including LG&E, and certain of its non-utility subsidiaries are subject 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.  LG&E and KU believe that they have adequate authority (including financing authority) under existing SEC orders and regulations to conduct their business.  LG&E and KU will seek additional authorization when necessary.

As contemplated in their regulatory filings in connection with the E.ON acquisition, E.ON, Powergen and LG&E Energy completed an administrative reorganization to move the LG&E Energy group from an indirect Powergen subsidiary to an indirect E.ON subsidiary.  This reorganization was effective in March 2003.  In early 2004, LG&E Energy began direct reporting arrangements to E.ON.

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

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

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RESULTS OF OPERATIONS

LG&E

Net Income

LG&E’s net income in 2003 increased $1.9 million (2.1%) compared to 2002.  The increase resulted primarily from increased electric wholesale sales partially offset by increased transmission expense and increased depreciation expense due to plant additions.

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

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

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

Revenues

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

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

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

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

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

Expenses

Fuel for electric generation and gas supply expenses comprise a large component of LG&E’s total operating costs. The retail electric rates contain an 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, and passed through to LG&E’s retail customers.

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

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

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

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

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

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

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

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

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

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

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

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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/ESTIMATES

Preparation of financial statements and related disclosures in compliance with generally accepted accounting principles 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 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.  Specific risks for these critical accounting policies are described in the following paragraphs.  Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions.  Events rarely develop exactly as forecast and the best estimates routinely require adjustment.  See also Note 1 of LG&E’s Notes to Financial Statements under Item 8.

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.  LG&E uses sales of market-traded electric forward contracts for periods less than one year to hedge the price volatility of its forecasted peak electric off-system sales.  Gains and losses resulting from ineffectiveness are shown in other income (expense) and to the extent that the hedging relationship has been effective, gains and losses are reflected in other comprehensive income.  See Note 4 - - Financial Instruments.

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

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

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

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

During 2002, the combination of poor market performance and historically low corporate bond rates created a divergence in the potential value of the pension liabilities and the actual value of the pension assets.  Market performance in 2003 reversed the negative trend.  Should poor market conditions return, these conditions could result in an increase in LG&E’s funded accumulated benefit obligations and future pension expense.  The primary assumptions that drive the value of the unfunded accumulated benefit obligations are the discount rate and expected return on plan assets.

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

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

Regulatory Mechanisms – Judgments and uncertainties include future regulatory decisions, the impact of deregulation and competition on ratemaking process, and external regulator decisions.

Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates based upon Kentucky Commission orders.  Regulatory liabilities generally represent obligations to make refunds to customers for previous collections based upon orders by the Kentucky Commission.  Management believes, based on orders, the existing regulatory assets and liabilities are probable of recovery.  This determination reflects the current regulatory climate in the state.  If future recovery of costs ceases to be probable the assets would be required to be recognized in current period earnings.

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

NEW ACCOUNTING PRONOUNCEMENTS

The following accounting pronouncements were implemented by LG&E in 2003:

SFAS No. 143, Accounting for Asset Retirement Obligations 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.

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

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

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

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

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

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

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

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

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

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

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  EITF No. 02-03 established the following:

•Rescinded EITF No. 98-10,

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

•Revenues should be shown in the income statement net of costs associated with trading activities, whether or not the trades are physically settled.

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

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

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

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

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

In January 2003, the Financial Accounting Standards Board issued Financial Accounting Standards Board Interpretation No. 46, Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51 (FIN 46).  FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional

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

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

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

LIQUIDITY AND CAPITAL RESOURCES

LG&E uses net cash generated from its operations and external financing (including financing from affiliates) 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 $163.3 million, $212.4 million and $287.1 million in 2003, 2002, and 2001, respectively.  The 2003 decrease compared to 2002 of $49.1 million resulted primarily from pension funding in 2003 of $89.1 million and the change in accounts receivable balances of $33.4 million, including the sale of accounts receivable through the accounts receivable securitization program, partially offset by an increase in accounts payable and accrued taxes of $35.0 million and $36.0 million, respectively.  The 2002 decrease of $74.7 million resulted primarily from the change in accounts receivable balances of $68.0 million.  See Note 1 of LG&E’s Notes to Financial Statements under Item 8 for a discussion of accounts receivable securitization.

Investing Activities

LG&E’s primary use of funds for investing activities continues to be for capital expenditures.  Capital expenditures were $213.0 million, $220.4 million and $253.0 million in 2003, 2002, and 2001, respectively.  LG&E expects its capital expenditures for 2004 and 2005 to total approximately $270.0 million, which consists primarily of construction estimates associated with installation of NOx equipment as described in the section titled “Environmental Matters,” construction of jointly owned CTs with KU and on-going construction for the generation and distribution systems.

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

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Financing Activities

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

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

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.

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

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

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

LG&E first mortgage bond, 6% Series of $42.6 million matured in 2003.

Under the provisions for LG&E’s variable-rate pollution control bonds totaling $246.2 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.

Future Capital Requirements

Future capital requirements may be affected in varying degrees by factors such as electric energy demand 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 has a variety of funding alternatives available to meet its capital requirements.  The Company maintains a series of bilateral credit facilities with banks totaling $185 million.  Several intercompany financing arrangements are also available.  LG&E participates in an intercompany money pool agreement wherein LG&E

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

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

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

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

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

Contractual Obligations

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

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

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

(b)Includes long-term debt of $246.2 million 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 2013 to 2027.

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

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

(e)Represents construction commitments.

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

LG&E is a participant in a sale and leaseback transaction involving its 38% interest in two jointly-owned CTs at KU’s E.W. Brown generating station (Units 6 and 7).  Commencing in December 1999, LG&E and KU entered into a tax-efficient, 18-year lease of the CTs.  LG&E and KU have provided funds to fully defease the lease,

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and have executed an irrevocable notice to exercise an early purchase option contained in the lease after 15.5 years.  The financial statement treatment of this transaction is no different than if LG&E had retained its ownership.  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.  The leasing transaction was entered into following receipt of required state and federal regulatory approvals.

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

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

MARKET RISKS

LG&E is exposed to market risks from changes in interest rates 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, 2003, the potential change in interest expense associated with a 1% change in base interest rates of LG&E’s unhedged debt is estimated at $4.4 million after the impact of interest rate swaps.

Interest rate swaps are used to hedge LG&E’s underlying variable-rate debt obligations.  These swaps hedge specific debt issuances and, consistent with management’s designation, are accorded hedge accounting treatment.  See Note 4 of LG&E’s Notes to Financial Statements under Item 8.

As of December 31, 2003, LG&E had swaps with a combined notional value of $228.3 million.  The swaps exchange floating-rate interest payments for fixed rate interest payments to reduce the impact of interest rate changes on LG&E’s pollution control bonds.  The potential loss in fair value resulting from a hypothetical 1% adverse movement in base interest rates is estimated at approximately $10 million as of December 31, 2003.  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, will have no effect on LG&E’s net income or cash flow.  See Note 4 of LG&E’s Notes to Financial Statements under Item 8.

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.

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Energy Trading & Risk Management Activities

LG&E conducts energy trading and risk management activities to maximize the value of power sales from physical assets it owns, in addition to the wholesale sale of excess asset capacity.  Certain energy trading activities are accounted for on a mark-to-market basis in accordance with 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 rescission of EITF No. 98-10 for fiscal periods ending after December 15, 2002, had no impact on LG&E’s energy trading and risk management reporting as all forward and option contracts marked to market under EITF No. 98-10 are also within the scope of SFAS No. 133.

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

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

No changes to valuation techniques for energy trading and risk management activities occurred during 2003.  Changes in market pricing, interest rate and volatility assumptions were made during both years.  All contracts outstanding at December 31, 2003, have a maturity of less than one year and are valued using 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.  At December 31, 2003, 100% of the trading and risk management commitments were with counterparties rated BBB-/Baa3 equivalent or better.

Accounts Receivable Securitization

On February 6, 2001, LG&E implemented an accounts receivable securitization program.  The purpose of this program was 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 allowed 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 was able to terminate the program at any time without penalty.

LG&E terminated the accounts receivable securitization program in January 2004 and replaced it with intercompany loans from an E.ON affiliate.  The accounts receivable program required LG&E R to maintain minimum levels of net worth.  The program also contained a cross-default provision if LG&E defaulted on debt obligations in excess of $25 million.  If there was a significant deterioration in the payment record of the receivables by the retail customers or if LG&E failed to meet certain covenants regarding the program, the program could 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.  LG&E did not violate any covenants with regard to the accounts receivable

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securitization program.

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 could sell, on a revolving basis, an undivided interest in certain of its receivables and receive up to $75 million from an unrelated third-party purchaser.  The effective cost of the receivables program was comparable to LG&E’s lowest cost source of capital, and was based on prime rated commercial paper.  LG&E retained servicing rights of the sold receivables through two separate servicing agreements with the third-party purchasers.  LG&E obtained an opinion from independent legal counsel indicating these transactions qualified as a true sale of receivables.  As of December 31, 2003, the outstanding program balance was $58.0 million.

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

The allowance for doubtful accounts associated with the eligible securitized receivables at December 31 was $1.4 million, $1.9 million and $1.3 million in 2003, 2002 and 2001, respectively.  This allowance was based on historical experience of LG&E. Each securitization facility contained a fully funded reserve for 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, its 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 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 - VDT Costs, ESM and Depreciation.  During the first quarter of 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 healthcare benefits.  The result of this workforce reduction was the elimination of approximately 700 positions, accomplished primarily through a voluntary enhanced severance program.

In June 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 a new depreciation study and resulting depreciation rates implemented in 2001.

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

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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 2001 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 to the regulatory asset from $144 million to $141 million.  The settlement reduces revenues approximately $26 million through a surcredit on bills to ratepayers 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 VDT.  The agreement also established new depreciation rates in effect December 2001, retroactive to January 2001.  The new depreciation rates decreased depreciation expense by $5.6 million in 2001.

ECR.  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 in April 2001 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.

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

In August 2002, LG&E filed an application with the Kentucky Commission to amend its compliance plan to allow recovery of the cost of new and additional environmental compliance facilities.  The estimated capital cost of the additional facilities is $71.1 million. A final order was issued in February 2003.  The final order approved recovery of four new environmental compliance facilities totaling $43.1 million.  A fifth project, expansion of the landfill facility at the Mill Creek Station, was denied without prejudice with an invitation to reapply for recovery when required construction permits are approved.  Cost recovery through the environmental surcharge of the four approved projects began with bills rendered in April 2003.

In January 2003, the Kentucky Commission initiated a six-month review of LG&E’s environmental surcharge.  A final order was issued in April 2003, in which LG&E was ordered to refund $2.9 million it had previously over-collected from customers.  In July 2003, the Kentucky Commission initiated a two-year review of LG&E’s environmental surcharge.  A final order was issued in December 2003, in which LG&E was ordered to roll $15.2 million of environmental assets into base rates and make corresponding adjustments to the monthly environmental surcharge filings to reflect that portion of environmental rate base now included in base rates on a going-forward basis.  Additionally, LG&E was ordered to collect $0.2 million to correct for amounts under-collected

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

ESM.  LG&E’s electric rates are subject to an ESM.  The ESM, initially 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, the excess earnings are shared 40% with ratepayers and 60% with shareholders; if earnings are below the lower limit, the earnings deficiency is recovered 40% from ratepayers and 60% from shareholders.  By order of the Kentucky Commission, rate changes prompted by the ESM filing go into effect in April of each year subject to a balancing adjustment in successive periods.

In November 2002, LG&E filed a revised ESM tariff which proposed continuance of the existing ESM through December 2005.  In addition, the Kentucky Commission initiated a focused management audit to review the ESM plan and reassess its reasonableness, and recently concluded discovery in the case.  LG&E and interested parties had the opportunity to provide recommendations for modification and continuance of the ESM or other forms of alternative or incentive regulation.  Continuance of the ESM is still being deliberated by the Kentucky Commission and a final order is not expected until the second quarter of 2004.  The ESM tariff remains in effect pending the resolution of the case.

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

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 provision allowed LG&E to recover revenues from lost sales associated with the DSM programs.  In May 2001, the Kentucky Commission approved LG&E’s plan to continue DSM programs.  This plan called for the expansion of the DSM programs into the service territory served by KU and proposed a mechanism to recover revenues from lost sales associated with DSM programs based on program plan engineering estimates and post-implementation evaluation.

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

FAC.  LG&E employs an FAC mechanism, which under Kentucky law allows 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

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

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

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.  No significant issues have been identified as a result of these reviews.

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

Wholesale Natural Gas Prices.  On September 12, 2000, the Kentucky Commission issued an order establishing Administrative 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”.

Subsequent to this investigation, the Kentucky Commission issued an order in July 2001, 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.

In April 2003, LG&E proposed a hedge plan for the 2003/2004 winter heating season with two alternatives, the first relying upon LG&E’s storage and the second relying upon a combination of LG&E’s storage and financial hedge instruments.  In July 2003, the Kentucky Commission approved LG&E’s first alternative which relies upon storage to mitigate the price volatility to which customers might otherwise be exposed.  The Kentucky Commission validated the effectiveness of storage to mitigate potential volatility associated with high winter gas prices by approving this natural gas hedge plan.

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

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 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.  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 utility’s 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.  In February 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 ongoing.

Kentucky Commission Administrative Case for System Adequacy.  In June 2001, Kentucky’s Governor 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.  In response to that Executive Order, 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.  In December 2001, the Kentucky Commission issued an order in which it 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 Kentucky 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.

FERC SMD NOPR.  On July 31, 2002, FERC issued a NOPR in Docket No. RM01-12-000 which would substantially alter the regulations governing the nation’s wholesale electricity markets by establishing a common set of rules, defined as SMD. The SMD NOPR would require each public utility that owns, operates, or controls interstate transmission facilities to become an Independent Transmission Provider (ITP), belong to an RTO that is an ITP, or contract with an ITP for operation of its transmission assets. It would also establish a standardized congestion management system, real-time and day-ahead energy markets, and a single transmission service for network and point-to-point transmission customers. Review of the proposed rulemaking is underway and no time frame has been established by the FERC for adoption of a final rule.  While it is expected that the SMD final rule will affect LG&E revenues and expenses, the specific impact of the rulemaking is not known at this time.

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

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

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

As a separate matter, MISO, its transmission owners and other interested industry segments reached a settlement in mid-2002 regarding the levelof cost responsibility properly borne by bundled and grandfathered load under these FERC rulings (such settlement expressly not prejudicing the transmission owners’ and LG&E’s right to challenge the FERC’s ruling imposing cost responsibility on bundled loads in the first instance).  In February 2003, FERC accepted a partial settlement between MISO and the transmission owners.  FERC did not accept the only contested section of the settlement, which would have allowed the transmission owners to immediately treat unrecoverable Schedule 10 charges as regulatory assets.  FERC will consider allowing regulatory asset treatment of unrecoverable Schedule 10 charges on a case-by-case basis.

The MISO plans to implement a congestion management system in December 2004, in compliance with FERC Order 2000.  This system will be similar to the Locational Marginal Pricing (LMP) system currently used by the PJM RTO and contemplated in FERC’s SMD NOPR, currently being discussed.  The MISO filed with FERC a mechanism for recovery of costs for the congestion management system.  They proposed the addition of two new Schedules, 16 and 17.  Schedule 16 is the MISO’s cost recovery mechanism for the Financial Transmission Rights Administrative Service it will provide.  Schedule 17 is the MISO’s mechanism for recovering costs it will incur for providing Energy Marketing Support Administrative Service.  The MISO transmission owners, including LG&E and KU, have objected to the allocation of costs among market participants and retail native load.  A hearing at FERC has been completed, but a ruling has not been issued.

The Kentucky Commission opened an investigation into LG&E’s and KU’s membership in MISO in July 2003. The Kentucky Commission directed LG&E and KU to file testimony addressing the costs and benefits of MISO membership both currently and over the next five years and other legal issues surrounding continued membership.  LG&E and KU engaged an independent third-party to conduct a cost benefit analysis on this issue.  The information was filed with the Kentucky Commission in September 2003.  The analysis and testimony supported the exit from MISO, under certain conditions.  The MISO filed its own testimony and cost benefit analysis in December 2003.  A final Kentucky Commission order is expected in the second quarter of 2004.

Merger Surcredit.  As part of the LG&E Energy merger with KU Energy in 1998, 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 was deferred and amortized over a five-year period pursuant to regulatory orders.  Primary components of the merger costs were separation

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

In approving the merger, the Kentucky Commission adopted LG&E’s proposal to reduce its retail customers’ bills based on one-half of the estimated merger-related savings, net of deferred and amortized amounts, over a five-year period.  The surcredit mechanism provides that 50% of the net non-fuel cost savings estimated to be achieved from the merger be provided to ratepayers through a monthly bill credit, and 50% be retained by LG&E and KU, over a five-year period.  The surcredit was allocated 53% to KU and 47% to LG&E.  In that same order, the Kentucky Commission required LG&E and KU, after the end of the five-year period, to present a plan for sharing with ratepayers the then-projected non-fuel savings associated with the merger.  The Companies submitted this filing in January 2003, proposing to continue to share with ratepayers, on a 50%/50% basis, the estimated fifth-year gross level of non-fuel savings associated with the merger.  In October 2003, the Kentucky Commission issued an order approving a settlement agreement reached with the parties in the case. LG&E’s merger surcredit will remain in place for another five-year term beginning July 1, 2003 and the merger savings will continue to be shared 50% with ratepayers and 50% with shareholders.

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

Environmental Matters.  LG&E is subject to SO₂ and NOx emission limits on its electric generating units pursuant to the Clean Air Act.  LG&E was not subject to Phase I SO₂ emissions reduction requirements.  LG&E’s strategy for Phase II SO₂ reductions, which commenced January 1, 2000, is to increase FGD removal efficiency to delay additional capital expenditures and may also include fuel switching or upgrading FGDs.  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 SIP, which was approved by EPA June 24, 2003, requires 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 $185 million to reduce its NOx emissions to the 0.15 lb./Mmbtu level on a company-wide basis.  As of December 31, 2003, LG&E has incurred approximately $177 million of these capital costs related to the reduction of its NOx emissions.  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

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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 EPA’s revised air quality standards for ozone and particulate matter, measures to implement EPA’s regional haze rule, and EPA’s December 2003 proposals to regulate mercury emissions from steam electric generating units and to further reduce emissions of sulfur dioxide and nitrogen oxides under the Interstate Air Quality Rule.  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 $0.4 million.  Accordingly, an accrual of $0.4 million has been recorded in the accompanying financial statements at December 31, 2003 and 2002.

See Note 11 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, 2003, deferred tax assets totaled $80.7 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

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

At this time, 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.

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KU

RESULTS OF OPERATIONS

Net Income

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

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

Revenues

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

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

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

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

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

Expenses

Fuel for electric generation comprises a large component of KU’s total operating expenses.  KU’s Kentucky jurisdictional electric rates are subject to an FAC whereby increases or decreases are reflected in the FAC factor, subject to the approval of the Kentucky Commission and passed through to KU’s retail customers.  KU’s municipal 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 FERC and the Virginia Commission, respectively.

Fuel for electric generation increased $15.8 million (6.3%) in 2003 because of an increase in the cost of coal burned ($18.9 million), partially offset by a decrease in generation ($3.1 million).  Fuel for electric generation increased $13.1 million (5.5%) in 2002 because of an increase in the cost of coal burned ($29.7 million), partially offset by a decrease in generation ($16.5 million).  The average delivered cost per ton of coal purchased was $34.91 in 2003, $31.44 in 2002 and $27.84 in 2001.

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

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

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

Depreciation and amortization increased $6.3 million (6.6%) in 2003 and $5.2 million (5.7%) in 2002 primarily due to an increase in plant in service.

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

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

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

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

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

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

CRITICAL ACCOUNTING POLICIES/ESTIMATES

Preparation of financial statements and related disclosures in compliance with generally accepted accounting principles 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 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.  Specific risks for these critical accounting policies are described in the following paragraphs.  Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions.  Events rarely develop exactly as forecast and the best estimates routinely require adjustment.  See also Note 1 of KU’s Notes to Financial Statements under Item 8.

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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.  KU uses sales of market-traded electric forward contracts for periods less than one year to hedge the price volatility of its forecasted peak electric off-system sales.  Gains and losses resulting from ineffectiveness are shown in other income (expense) and to the extent that the hedging relationship has been effective, gains and losses are reflected in other comprehensive income.  See Note 4 – Financial Instruments.

Unbilled Revenue – At each month end KU prepares a financial estimate that projects electric usage that has been used by customers, but not billed.  The estimated usage is based on allocating the daily system net deliveries between billed volumes and unbilled volumes. The allocation is based on a daily ratio of the number of meter reading cycles remaining in the month to the total number of meter reading cycles in each month.  Each day’s ratio is then multiplied by each day’s system net deliveries to determine an estimated billed and unbilled volume for each day of the accounting period.  At December 31, 2003, a 10% change in these estimated quantities would cause revenue and accounts receivable to change by approximately $3.9 million.  See also Note 1 of KU’s Notes to Financial Statements under Item 8.

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

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

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

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

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

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

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

Regulatory Mechanisms – Judgments and uncertainties include future regulatory decisions, the impact of deregulation and competition on the ratemaking process and external regulator decisions.

Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates based upon Kentucky Commission orders.  Regulatory liabilities generally represent obligations to make refunds to customers for previous collections based upon orders by the Kentucky Commission.  Management believes, based on orders, the existing regulatory assets and liabilities are probable of recovery.  This determination reflects the current regulatory climate in the state.  If future recovery of costs ceases to be probable the assets would be required to be recognized in current period earnings.

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

NEW ACCOUNTING PRONOUNCEMENTS

The following accounting pronouncements were implemented by KU in 2003:

SFAS No. 143, Accounting for Asset Retirement Obligations 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.

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

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

Had SFAS No. 143 been in effect for the 2002 reporting period, KU would have established asset retirement obligations as described in the following table:

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

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

For the year ended December 31, 2003, KU recorded ARO accretion expense of $1.2 million, ARO depreciation

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

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

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

KU transmission and distribution lines largely operate under perpetual property easement agreements which do not generally require restoration upon removal of the property.  Therefore, under SFAS No. 143, no material asset retirement obligations are recorded for transmission and distribution assets.

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

•Rescinded EITF No. 98-10,

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

•Revenues should be shown in the income statement net of costs associated with trading activities, whether or not the trades are physically settled.

With the rescission of EITF No. 98-10, energy trading contracts that do not also meet the definition of a derivative under SFAS No. 133 must be accounted for as executory contracts.  Contracts previously recorded at fair value under EITF No. 98-10 that are not also derivatives under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, must be restated to historical cost through a cumulative effect adjustment.  The rescission of this standard had no impact on financial position or results of operations of KU since all forward and option contracts marked to market under EITF No. 98-10 were also within the scope of SFAS No. 133.

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

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

In May 2003, the Financial Accounting Standards Board issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.  SFAS No. 150 was effective immediately for financial instruments entered into or modified after May 31, 2003, and otherwise was effective for interim reporting periods beginning after June 15, 2003, except for certain instruments and certain entities which have been deferred by the FASB.  Such deferrals do not affect KU.

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

In January 2003, the Financial Accounting Standards Board issued Financial Accounting Standards Board Interpretation No. 46, Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51 (FIN 46).  FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties.  FIN 46 was effective immediately for all new variable interest entities created or acquired after January 31, 2003.  For variable interest entities created or acquired prior to February 1, 2003, the provisions of FIN 46 must have been applied for the first interim or annual period beginning after June 15, 2003.

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

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

LIQUIDITY AND CAPITAL RESOURCES

KU uses net cash generated from its operations and external financing (including financing from affiliates) 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 $237.0 million, $175.8 million and $188.1 million in 2003, 2002, and 2001, respectively.  The 2003 increase compared to 2002 of $59.6 million was primarily the result of an increase in accrued taxes of $19.4 million, an increase in deferred income taxes of $17.3 million, a decrease in pension funding of $6.5 million and the change in accounts receivable balances of $4.6 million, including the sale of

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

Investing Activities

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

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

Financing Activities

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

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

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

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

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

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

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

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anticipates funding future capital requirements through operating cash flow, debt, and/or infusion of capital from its parent.

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

Certain regulatory approvals are required for the Company to incur additional debt.  FERC, the Virginia Commission, and the SEC authorize the issuance of short-term debt while the Kentucky Commission, the Virginia Commission, and the TRA authorize issuance of long-term debt.  As of December 31, 2003 the Company has received approvals from FERC, the Virginia Commission and the SEC to borrow up to $400 million in short-term funds, and approvals from the Kentucky Commission, the Virginia Commission, and the TRA for $100 million in additional long-term loans.  New long-term loans totaling $50 million were completed in January 2004.

KU’s debt ratings as of December 31, 2003, were:

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

These ratings reflect the views of Moody’s and S&P.  A security rating is not a recommendation to buy, sell or hold securities and is subject to revision or withdrawal at any time by the rating agency.  Fitch withdrew its ratings on KU securities effective October 14, 2003.

Contractual Obligations

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

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

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

(b)Includes long-term debt of $91.9 million classified as a current liability because 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.  Maturity dates for the bonds range from 2024 to 2032.

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

(d)Represents construction commitments.

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

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in 2004 as explained in (b) above.  KU anticipates cash from operations and external financing will be sufficient to fund future obligations.  KU anticipates refinancing a portion of its short-term debt with long-term debt in 2004.

KU is a participant in a sale and leaseback transaction involving its 62% interest in two jointly-owned CTs at KU’s E.W. Brown generating station (Units 6 and 7).  Commencing in December 1999, LG&E and KU entered into a tax-efficient, 18-year lease of the CTs.  KU and LG&E have provided funds to fully defease the lease, and have executed an irrevocable notice to exercise an early purchase option contained in the lease after 15.5 years. The financial statement treatment of this transaction is no different than if KU had retained its ownership.  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.  The leasing transaction was entered into following receipt of required state and federal regulatory approvals.

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

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

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, 2003, the potential change in interest expense associated with a 1% change in base interest rates of KU’s variable-rate debt is estimated at $4.5 million after the impact of interest rate swaps.

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.  See Note 4 of KU’s Notes to Financial Statements under Item 8.

As of December 31, 2003, KU has swaps with a combined notional value of $153 million.  The swaps exchange fixed-rate interest payments for floating rate interest payments on KU’s Series P and R first mortgage bonds and Series 9 pollution control bonds.  The potential loss in fair value resulting from a hypothetical 1% adverse movement in base interest rates is estimated at $9.2 million as of December 31, 2003.  This estimate is derived from third-party valuations. Changes in the market value of these swaps, if held to maturity, will have no effect on KU’s net income or cash flow.  See Note 4 of KU’s Notes to Financial Statements under Item 8.

In February 2004, KU terminated the swaps it had in place at December 31, 2003 related to the Series 9 pollution control bonds.  The notional amount of the terminated swap was $50 million and KU received a

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

Commodity Price Sensitivity

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

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

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

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

No changes to valuation techniques for energy trading and risk management activities occurred during 2003.  Changes in market pricing, interest rate and volatility assumptions were made during both years. All contracts outstanding at December 31, 2003 have a maturity of less than one year and are valued using prices actively quoted for proposed or executed transactions or quoted by brokers.

KU maintains policies intended to minimize credit risk and revalues credit exposures daily to monitor compliance with those policies.  At December 31, 2003, 100% of the trading and risk management commitments were with counterparties rated BBB-/Baa3 equivalent or better.

Accounts Receivable Securitization

On February 6, 2001, KU implemented an accounts receivable securitization program.  The purpose of this program was 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 allowed for a percentage of eligible receivables to be sold.  Eligible receivables were generally all receivables associated with retail sales that have standard terms and are not past due.  KU was able to terminate this program at any time without penalty.

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KU terminated the accounts receivable securitization program in January 2004 and replaced it with long-term loans from an E.ON affiliate.  The accounts receivable program required KU R to maintain minimum levels of net worth.  The program also contained a cross-default provision if KU defaulted on debt obligations in excess of $25 million.  If there was a significant deterioration in the payment record of the receivables by the retail customers or if KU failed to meet certain covenants regarding the program, the program could 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.  KU did not violate any covenants with regard to the accounts receivable securitization program.

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 could sell, on a revolving basis, an undivided interest in certain of its receivables and receive up to $50 million from an unrelated third-party purchaser.  The effective cost of the receivable program was comparable to KU’s lowest cost source of capital, and is based on prime rated commercial paper.  KU retained servicing rights of the sold receivables through two separate servicing agreements with the third-party purchaser.  KU obtained an opinion from independent legal counsel indicating these transactions qualified as a true sale of receivables.  As of December 31, 2003, the outstanding program balance was $50.0 million.

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

The allowance for doubtful accounts associated with the eligible securitized receivables at December 31 was $0.5 million in 2003, 2002 and 2001.  This allowance was based on historical experience of KU. Each securitization facility contained 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 - VDT 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 healthcare benefits. The result of this workforce reduction was the elimination of approximately 300 positions, accomplished primarily through a voluntary enhanced severance program.

In June 2001, KU filed an application (VDT case) with the Kentucky Commission to create a regulatory asset

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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 a new depreciation study and resulting depreciation rates implemented in 2001.

KU reached a settlement in the VDT case as well as other cases involving the depreciation rates and ESM with all intervening parties.  The settlement agreement was approved by the Kentucky Commission in December 2001.  The 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 2001 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 which, along with the non-recurring charge of $6.9 million for FERC and Virginia jurisdictions, decreased the original charge to the regulatory asset from $64 million to $54 million. The settlement reduces revenues approximately $11 million through a surcredit on bills to ratepayers over the same five-year period.  The surcredit represents stipulated net savings KU is expected to realize from implementation of best practices through the VDT. The agreement also established KU’s new depreciation rates in effect December 2001, retroactive to January 2001.  The new depreciation rates decreased depreciation expense by $6.0 million in 2001.

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

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

ESM.  KU’s electric rates are subject to an ESM.  The ESM, initially 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, the excess earnings are shared 40% with ratepayers and 60% with shareholders; if earnings are below the lower limit, the earnings deficiency is recovered 40% from ratepayers and 60% from shareholders.  By order of the Kentucky Commission, rate changes prompted by the ESM filing go into effect in April of each year subject to a balancing adjustment in successive periods.

In November 2002, KU filed a revised ESM tariff which proposed continuance of the existing ESM through December 2005.  In addition, the Kentucky Commission initiated a focused management audit to review the ESM plan and reassess its reasonableness, and recently concluded discovery in the case.  KU and interested parties had the opportunity to provide recommendations for modification and continuance of the ESM or other forms of alternative or incentive regulation.  Continuance of the ESM is still being deliberated by the Kentucky Commission and a final order is not expected until the second quarter of 2004.  The ESM tariff remains in effect pending the resolution of the case.

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

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 plan included a rate mechanism that provided for concurrent recovery of DSM costs, provided an incentive for implementing DSM programs, and recovered revenues from lost sales associated with the DSM programs based on program plan engineering estimates and post-implementation evaluations.

FAC.  KU employs an FAC mechanism, which under Kentucky law allows KU 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.  In August 1999, after a rehearing request by KU, the Kentucky Commission issued a final order that reduced the refund obligation to $6.7 million ($5.8 million on Kentucky jurisdictional basis) from the original order amount of $10.1 million.  KU implemented the refund from October 1999 through September 2000.  Both KU and the KIUC appealed the order.  Pending a decision on this appeal, a comprehensive settlement was reached by all parties and approved by the Kentucky Commission in May 2002.  Thereunder, KU agreed to credit its fuel clause in the amount of $1.0 million (refund made in June and July 2002), and the parties agreed on a prospective interpretation of the state’s fuel adjustment clause regulation to ensure consistent and mutually acceptable application going forward.

In January 2003, the Kentucky Commission reviewed KU’s FAC for the six month period ended October 31, 2002. The Kentucky Commission ordered KU to reduce its fuel costs for purposes of calculating its FAC by $0.7 million. At issue was the purchase of approximately 102,000 tons of coal from Western Kentucky Energy Corporation, a non-regulated affiliate, for use at KU’s Ghent facility. The Kentucky Commission further ordered that an independent audit be conducted to examine operational and management aspects of both KU’s and LG&E’s fuel procurement functions. The final report was issued in February 2004.  The report’s recommendations related to documentation and process improvements will be addressed with the Kentucky Commission staff as Management Audit Plans are developed in the second quarter of 2004.

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.  KU also employs a FAC mechanism for Virginia customers that 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.  No other significant issues have been identified as a result of these reviews.

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

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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.  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 utility’s 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.  In February 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.  In June 2001, Kentucky’s Governor 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.  In response to that Executive Order, 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.  In December 2001, the Kentucky Commission issued an order in which it noted that KU is responsibly addressing the long-term supply needs of native load customers and that current reserve margins are appropriate.  However, due to the rapid pace of change in the industry, the order also requires KU to provide an annual assessment of supply resources, future demand, reserve margin, and the need for new resources.

Regarding the transmission system, the Kentucky Commission concluded that the transmission system within Kentucky 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.

FERC SMD NOPR.  On July 31, 2002, the FERC issued a NOPR in Docket No. RM01-12-000 which would substantially alter the regulations governing the nation’s wholesale electricity markets by establishing a common set of rules, defined as SMD. The SMD NOPR would require each public utility that owns, operates, or controls interstate transmission facilities to become an Independent Transmission Provider (ITP), belong to an RTO that is an ITP, or contract with an ITP for operation of its transmission assets. It would also establish a standardized congestion management system, real-time and day-ahead energy markets, and a single transmission service for network and point-to-point transmission customers. Review of the proposed rulemaking is underway and no time frame has been established by the FERC for adoption of a final rule.  While it is expected that the SMD final rule will affect KU revenues and expenses, the specific impact of the rulemaking is not

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known at this time.

MISO.  KU and LG&E are founding members of the MISO.  Membership was obtained in 1998 in response to and consistent with federal policy initiatives.  In February 2002, KU and LG&E turned over operational control of their high voltage transmission facilities (100kV and above) to the MISO.  TheMISO currently controlsover 100,000 miles of transmission over 1.1 million square miles located in the northern Midwest between Manitoba, Canada and Kentucky.  In September 2002, FERC granted a 12.88% ROE on transmission facilities for KU, LG&E and the rest of the MISO owners.

In October 2001, the FERC issued an order requiring that the bundled retail load and grandfathered wholesale load of each member transmission owner be included in the current calculation of the MISO’s “cost-adder,” the Schedule 10 charges designed to recover the MISO’s costs of operation, including start-up capital (debt) costs.  KU and LG&E, along with several other transmission owners, opposed the FERC’s ruling on this matter. The opposition was rejected by the FERC in 2002.  Later that year, the MISO’s transmission owners appealed the FERC’s decision to the United States Court of Appeals for the District of Columbia Circuit.  In response, in November 2002, the FERC requested that the Court issue a partial remand of its challenged orders to allow the FERC to revisit certain issues, and further requested that the case be held in abeyance pending the agency’s resolution of such issues.  The Court granted the FERC’s petition in December 2002.  In February 2003, FERC issued an order reaffirming its position concerning the calculation of the Schedule 10 charges and in July 2003 denied a rehearing.  KU and LG&E, along with several other transmission owners, have again petitioned the District Court of Columbia Circuit for review.  This case is currently pending.

As a separate matter, MISO, its transmission owners and other interested industry segments reached a settlement in mid-2002 regarding the levelof cost responsibility properly borne by bundled and grandfathered load under these FERC rulings (such settlement expressly not prejudicing the transmission owners’ and KU’s right to challenge the FERC’s ruling imposing cost responsibility on bundled loads in the first instance).  In February 2003, FERC accepted a partial settlement between MISO and the transmission owners.  FERC did not accept the only contested section of the settlement, which would have allowed the transmission owners to immediately treat unrecoverable Schedule 10 charges as regulatory assets.  FERC will consider allowing regulatory asset treatment of unrecoverable Schedule 10 charges on a case-by-case basis.

The MISO plans to implement a congestion management system in December 2004, in compliance with FERC Order 2000.  This system will be similar to the Locational Marginal Pricing (LMP) system currently used by the PJM RTO and contemplated in FERC’s SMD NOPR, currently being discussed.  The MISO filed with FERC a mechanism for recovery of costs for the congestion management system.  They proposed the addition of two new Schedules, 16 and 17.  Schedule 16 is the MISO’s cost recovery mechanism for the Financial Transmission Rights Administrative Service it will provide.  Schedule 17 is the MISO’s mechanism for recovering costs it will incur for providing Energy Marketing Support Administrative Service.  The MISO transmission owners, including KU and LG&E, have objected to the allocation of costs among market participants and retail native load.  A hearing at FERC has been completed, but a ruling has not been issued.

The Kentucky Commission opened an investigation into KU’s and LG&E’s membership in MISO in July 2003. The Kentucky Commission directed KU and LG&E to file testimony addressing the costs and benefits of MISO membership both currently and over the next five years and other legal issues surrounding continued membership.  KU and LG&E engaged an independent third party to conduct a cost benefit analysis on this issue.  The information was filed with the Kentucky Commission in September 2003.  The analysis and testimony supported the exit from MISO, under certain conditions.  The MISO filed its own testimony and cost benefit analysis in December 2003.  A final Kentucky Commission order is expected in the second quarter of

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2004.

Merger Surcredit.  As part of the LG&E Energy merger with KU Energy in 1998, 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 was deferred and 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) in the second quarter of 1998.

In approving the merger, the Kentucky Commission adopted KU’s proposal to reduce its retail customers’ bills based on one-half of the estimated merger-related savings, net of deferred and amortized amounts, over a five-year period.  The surcredit mechanism provides that 50% of the net non-fuel cost savings estimated to be achieved from the merger be provided to ratepayers through a monthly bill credit, and 50% be retained by LG&E and KU over a five-year period.  The surcredit was allocated 53% to KU and 47% to LG&E.  In that same order, the Kentucky Commission required LG&E and KU, after the end of the five-year period, to present a plan for sharing with customers the then-projected non-fuel savings associated with the merger.  The Companies submitted this filing in January 2003, proposing to continue to share with ratepayers, on a 50%/50% basis, the estimated fifth-year gross level of non-fuel savings associated with the merger.  In October 2003, the Kentucky Commission issued an order approving a settlement agreement reached with the parties in the case. KU’s merger surcredit will remain in place for another five-year term beginning July 1, 2003 and the merger savings will continue to be shared 50% with ratepayers and 50% with shareholders.

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

Environmental Matters.  KU is subject to SO₂ and NOx emission limits on its electric generating units pursuant to the Clean Air Act.  KU met its Phase I SO₂ requirements primarily through installation of FGD equipment on Ghent Unit 1.  KU’s strategy for Phase II SO₂ reductions, which commenced January 1, 2000, was to use accumulated emissions allowances to delay additional capital expenditures and will include fuel switching or the installation of additional FGDs as necessary.  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 SIP, which was approved by EPA June 24, 2003, requires 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

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in late 2000 and continuing through the final compliance date.  KU estimates that it will incur total capital costs of approximately $230 million to reduce its NOx emissions to the 0.15 lb./Mmbtu level on a company-wide basis.  As of December 31, 2003, KU has incurred $172 million of these capital costs related to the reduction of its NOx emissions.  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 EPA’s revised air quality standards for ozone and particulate matter, measures to implement EPA’s regional haze rule, and EPA’s December 2003 proposals to regulate mercury emissions from steam electric generating units and to further reduce emission of sulfur dioxide and nitrogen oxides under the Interstate Air Quality Rule.

KU owns or formerly owned several properties that were used for company or company-predecessor operations, including MGP’s, power production facilities and substations.  While KU has completed a cleanup of one such site in 1995, evaluations of these types of properties generally have not identified issues of significance.  With regard to these properties, KU is unaware of any imminent exposure or liability.

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.  KU commenced immediate spill containment and recovery measures which continued under the oversight of EPA and state officials and 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 has settled all outstanding issues for this incident with the Commonwealth of Kentucky.  KU incurred costs of approximately $1.8 million and received insurance reimbursement of $1.2 million.  In December 2002, the Department of Justice (DOJ) sent correspondence to KU regarding a potential per-day fine for failure to timely submit a facility response plan and a per-gallon fine for the amount of oil discharged.  KU and the DOJ have commenced settlement discussions using existing DOJ settlement guidelines on this matter.

In April 2002, the EPA sent correspondence to KU regarding potential exposure in connection with $1.5 million in completed remediation costs associated with a transformer scrap-yard.  KU believes it is one of the more remote among a number of potentially responsible parties and has entered into settlement discussions with the EPA on this matter.

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, 2003, deferred tax assets totaled $48.6 million and were principally related to expenses attributable to KU’s post retirement benefits and asset retirement obligations.

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FUTURE OUTLOOK

Competition and Customer Choice

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

At this time, 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.

Virginia has enacted a phase-in of customer choice through the Virginia Electric Restructuring Act.  On March 19, 2003, the General Assembly of Virginia amended and reenacted Section 56-580 of the Code of Virginia with language that effectively exempts all KU Virginia service territory from retail choice until such time as retail choice is offered to other customers in KU’s other service territories.

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.

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INDEX OF ABBREVIATIONS

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

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

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Louisville Gas and Electric Company and Subsidiary

Consolidated Statements of Income

(Thousands of $)

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

Consolidated Statements of Retained Earnings

(Thousands of $)

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

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

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Louisville Gas and Electric Company and Subsidiary

Consolidated Statements of Comprehensive Income

(Thousands of $)

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

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

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Louisville Gas and Electric Company and Subsidiary

Consolidated Balance Sheets

(Thousands of $)

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

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

71

Louisville Gas and Electric Company and Subsidiary

Consolidated Statements of Cash Flows

(Thousands of $)

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

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

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Louisville Gas and Electric Company and Subsidiary

Consolidated Statements of Capitalization

(Thousands of $)

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

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

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Louisville Gas and Electric Company and Subsidiary

Notes to Consolidated Financial Statements

Note 1 - Summary of Significant Accounting Policies

LG&E, a subsidiary of LG&E Energy and an indirect subsidiary of E.ON, is a regulated public utility engaged in the generation, transmission, distribution, and sale of electric energy and the storage, distribution, and sale of natural gas in Louisville and adjacent areas in Kentucky.  LG&E Energy is a registered public utility holding company with wholly owned subsidiaries including LG&E, KU, Capital Corp., LEM, and LG&E Services.  All of LG&E’s common stock is held by LG&E Energy.  LG&E has one wholly owned consolidated subsidiary, LG&E R.  The consolidated financial statements include the accounts of LG&E and LG&E R with the elimination of intercompany accounts and transactions.

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

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

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

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

Regulatory Accounting.  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.  See Note 3 for additional detail regarding regulatory assets and liabilities.

Utility Plant.  LG&E’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.  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 and Amortization.  Depreciation is provided on the straight-line method over the estimated service lives of depreciable plant.  The amounts provided were approximately 3.3% in 2003 (2.9% electric, 2.8% gas, and

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

Cash and Temporary Cash Investments.  LG&E considers all 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.

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

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

Other Materials and Supplies.  Non-fuel materials and supplies of $25.0 million and $25.7 million at December 31, 2003 and 2002, respectively, are 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.  LG&E uses sales of market-traded electric forward contracts for periods less than one year to hedge the price volatility of its forecasted peak electric off-system sales.  Gains and losses resulting from ineffectiveness are shown in other income (expense) and to the extent that the hedging relationship has been effective, gains and losses are reflected in other comprehensive income.  See Note 4 - - Financial Instruments.

Unamortized 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 are recognized at currently enacted tax rates for all material temporary differences between the financial reporting and income tax basis of assets and liabilities.

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 based on allocating the daily system net deliveries between billed volumes and unbilled volumes. The allocation is based on a daily ratio of the number of meter reading cycles remaining in the month to the total number of meter reading cycles in each month.  Each day’s ratio is then multiplied by each day’s system net deliveries to determine an estimated billed and unbilled volume for each day of the accounting period.  The unbilled revenue estimates included in accounts receivable were approximately $50.8 million and $40.7 million at December 31, 2003 and 2002, respectively.

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

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months.

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.  Accrued liabilities, including legal and environmental, are recorded when they are reasonable and estimable.  Actual results could differ from those estimates. See Note 11, Commitments and Contingencies, for a further discussion.

New Accounting Pronouncements. The following accounting pronouncements were implemented by LG&E in 2003:

SFAS No. 143, Accounting for Asset Retirement Obligations 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.

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

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

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

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

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

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

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

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

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

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

•Rescinded EITF No. 98-10,

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

•Revenues should be shown in the income statement net of costs associated with trading activities, whether or not the trades are physically settled.

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

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

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

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

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

In January 2003, the Financial Accounting Standards Board issued Financial Accounting Standards Board Interpretation No. 46, Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51 (FIN 46).  FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties.  FIN 46 was effective immediately for all new variable interest entities created or acquired after January 31, 2003.  For variable interest entities created or acquired prior to February 1, 2003, the provisions of FIN 46 must have been applied for the first interim or annual period beginning after June 15, 2003.

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

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

Note 2 – Mergers and Acquisitions

On July 1, 2002, E.ON completed its acquisition of Powergen, including LG&E Energy, for approximately £5.1 billion ($7.3 billion).  As a result of the acquisition, LG&E Energy became a wholly owned subsidiary (through Powergen) of E.ON and, as a result, LG&E also became an indirect subsidiary of E.ON.  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 the utilities continue to file SEC reports.  Following the acquisition, E.ON became, and Powergen remained, a registered holding company under PUHCA. LG&E, as a subsidiary of a registered holding company, is subject to additional regulations under PUHCA.  As contemplated in their regulatory filings in connection with the E.ON acquisition, E.ON, Powergen and LG&E Energy completed an administrative reorganization to move the LG&E Energy group from an

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indirect Powergen subsidiary to an indirect E.ON subsidiary.  This reorganization was effective in March 2003. In early 2004, LG&E Energy commenced direct reporting arrangements to E.ON.

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

Note 3 - Rates and Regulatory Matters

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

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

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

Kentucky Commission Settlement Order - VDT Costs.  During the first quarter of 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 healthcare benefits.  The result of this workforce reduction was the elimination of approximately 700 positions, accomplished primarily through a voluntary enhanced severance program.

In June 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 a new depreciation study and

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resulting depreciation rates implemented in 2001.

LG&E reached a settlement in the VDT case as well as other cases involving the depreciation rates and ESM with all intervening parties.  The settlement agreement was approved by the Kentucky Commission in December 2001. The order allowed LG&E to set up a regulatory asset of $141 million for the workforce reduction costs and begin amortizing these costs over a five-year period starting in April 2001. The first quarter 2001 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 to the regulatory asset from $144 million to $141 million. The settlement reduces revenues approximately $26 million through a surcredit on bills to ratepayers 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 2001.  The new depreciation rates decreased depreciation expense by $5.6 million in 2001.

PUHCA.  Following the purchases of LG&E Energy by Powergen and Powergen by E.ON, Powergen and E.ON became registered holding companies under PUHCA.  As a result, E.ON, 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.  LG&E believes that it has adequate authority (including financing authority) under existing SEC orders and regulations to conduct its business.  LG&E will seek additional authorization when necessary.

ECR.  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 ECR Tariff to include an overall rate of return on capital investments. Approval of LG&E’s application in April 2001 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.

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

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

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approved recovery of four new environmental compliance facilities totaling $43.1 million.  A fifth project, expansion of the landfill facility at the Mill Creek Station, was denied without prejudice with an invitation to reapply for recovery when required construction permits are approved.  Cost recovery through the environmental surcharge of the four approved projects commenced with bills rendered in April 2003.

In January 2003, the Kentucky Commission initiated a six-month review of LG&E’s environmental surcharge.  A final order was issued in April 2003, in which LG&E was ordered to refund $2.9 million it had previously over-collected from customers.  In July 2003, the Kentucky Commission initiated a two-year review of LG&E’s environmental surcharge.  A final order was issued in December 2003 in which LG&E was ordered to roll $15.2 million of environmental assets into base rates and make corresponding adjustments to the monthly environmental surcharge filings to reflect that portion of environmental rate base now included in base rates on a going-forward basis.  Additionally, LG&E was ordered to collect $0.2 million to correct for amounts under-collected from customers.  The rates of return for LG&E’s 1995 and post-1995 plans were reset to 3.32% and 10.92%, respectively.

ESM.  LG&E’s electric rates are subject to an ESM.  The ESM, initially 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, the excess earnings are shared 40% with ratepayers and 60% with shareholders; if earnings are below the lower limit, the earnings deficiency is recovered 40% from ratepayers and 60% from shareholders.  By order of the Kentucky Commission, rate changes prompted by the ESM filing go into effect in April of each year subject to a balancing adjustment in successive periods.

In November 2002, LG&E filed a revised ESM tariff which proposed continuance of the existing ESM through December 2005.  In addition, the Kentucky Commission initiated a focused management audit to review the ESM plan and reassess its reasonableness, and recently concluded discovery in the case.  LG&E and interested parties had the opportunity to provide recommendations for modification and continuance of the ESM or other forms of alternative or incentive regulation.  Continuance of the ESM is still being deliberated by the Kentucky Commission and a final order is not expected until the second quarter.  The ESM tariff remains in effect pending the resolution of the case.

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

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 provision allowed LG&E to recover revenues from lost sales associated with the DSM programs.  In May 2001, the Kentucky Commission approved LG&E’s plan to continue DSM programs.  This plan called for the expansion of the DSM programs into the service territory served by KU and proposed a mechanism to recover revenues from lost sales associated with DSM programs based on program plan engineering estimates and post-implementation evaluation.

Gas Supply Cost PBR Mechanism.  Since November 1, 1997, LG&E has operated under an experimental PBR mechanism related to its gas procurement activities.  For each of the last five years, LG&E’s rates have been adjusted to recover its portion of the savings (or expenses) incurred during each of the five 12-month periods beginning November 1 and ending October 31. Since its implementation on November 1, 1997, through

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

FAC.  LG&E employs an FAC mechanism, which under Kentucky law allows 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.  While legal challenges to the Kentucky Commission order were pending, a comprehensive settlement was reached by all parties and approved by the Kentucky Commission in May 2002.  Thereunder, LG&E agreed to credit its fuel clause in the amount of $0.7 million (such credit provided over the course of June and July 2002), and the parties agreed on a prospective interpretation of the state’s FAC regulation to ensure consistent and mutually acceptable application going forward.

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

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.  No significant issues have been identified as a result of these reviews.

Electric and Gas Rate Cases.  In December 2003, LG&E filed applications with the Kentucky Commission requesting adjustments in LG&E’s electric and gas rates.  LG&E asked for general adjustments in electric and gas rates based on the twelve month test year ended September 30, 2003.  The revenue increases requested were $63.8 million for electric and $19.1 million for gas.  The Kentucky Commission has suspended the effective date of the proposed new tariffs for five months, so that the rates may go into effect subject to refund by July 1, 2004.  The Kentucky Commission established a procedural schedule for the cases pertaining to discovery and hearings.  Hearings will be held in May 2004.  LG&E expects the Kentucky Commission to issue orders in the cases before new rates go into effect July 1, 2004.

Wholesale Natural Gas Prices.  On September 12, 2000, the Kentucky Commission issued an order establishing Administrative 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”.

Subsequent to this investigation, the Kentucky Commission issued an order on July 17, 2001, 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.

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

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LG&E’s storage and financial hedge instruments.  In July 2003, the Kentucky Commission approved LG&E’s first alternative which relies upon storage to mitigate the price volatility to which customers might otherwise be exposed.  The Kentucky Commission validated the effectiveness of storage to mitigate potential volatility associated with high winter gas prices by approving this natural gas hedge plan.

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.  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 utility’s 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.  In February 2001, the Kentucky Commission published notice of its intent to promulgate new administrative regulations under the auspices of this new law.  This effort is still on-going.

Kentucky Commission Administrative Case for System Adequacy.  In June 2001, Kentucky’s Governor 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.  In response to that Executive Order, 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.  In December 2001, the Kentucky Commission issued an order in which it 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 Kentucky 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.

FERC SMD NOPR.  On July 31, 2002, FERC issued a NOPR in Docket No. RM01-12-000 which would substantially alter the regulations governing the nation’s wholesale electricity markets by establishing a common set of rules, defined as SMD. The SMD NOPR would require each public utility that owns, operates, or controls interstate transmission facilities to become an Independent Transmission Provider (ITP), belong to an RTO that is an ITP, or contract with an ITP for operation of its transmission assets. It would also establish a standardized congestion management system, real-time and day-ahead energy markets, and a single transmission

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

MISO.  LG&E and KU are founding members of the MISO.  Membership was obtained in 1998 in response to and consistent with federal policy initiatives.  In February 2002, LG&E and KU turned over operational control of their high voltage transmission facilities (100kV and above) to the MISO.  The MISO currently controls over 100,000 miles of transmission over 1.1 million square miles located in the northern Midwest between Manitoba, Canada and Kentucky.  In September 2002, FERC granted a 12.88% ROE on transmission facilities for LG&E, KU and the rest of the MISO owners.

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

As a separate matter, MISO, its transmission owners and other interested industry segments reached a settlement in mid-2002 regarding the levelof cost responsibility properly borne by bundled and grandfathered load under these FERC rulings (such settlement expressly not prejudicing the transmission owners’ and LG&E’s right to challenge the FERC’s ruling imposing cost responsibility on bundled loads in the first instance).  In February 2003, FERC accepted a partial settlement between MISO and the transmission owners.  FERC did not accept the only contested section of the settlement, which would have allowed the transmission owners to immediately treat unrecoverable Schedule 10 charges as regulatory assets.  FERC will consider allowing regulatory asset treatment of unrecoverable Schedule 10 charges on a case-by-case basis.

The MISO plans to implement a congestion management system in December 2004, in compliance with FERC Order 2000.  This system will be similar to the Locational Marginal Pricing (LMP) system currently used by the PJM RTO and contemplated in FERC’s SMD NOPR, currently being discussed.  The MISO filed with FERC a mechanism for recovery of costs for the congestion management system.  They proposed the addition of two new Schedules, 16 and 17.  Schedule 16 is the MISO’s cost recovery mechanism for the Financial Transmission Rights Administrative Service it will provide.  Schedule 17 is the MISO’s mechanism for recovering costs it will incur for providing Energy Marketing Support Administrative Service.  The MISO transmission owners, including LG&E and KU, have objected to the allocation of costs among market participants and retail native load.  A hearing at FERC has been completed, but a ruling has not been issued.

The Kentucky Commission opened an investigation into LG&E’s and KU’s membership in MISO in July 2003.  The Kentucky Commission directed LG&E and KU to file testimony addressing the costs and benefits of MISO membership both currently and over the next five years and other legal issues surrounding continued membership.  LG&E and KU engaged an independent third-party to conduct a cost benefit analysis on this issue. The information was filed with the Kentucky Commission in September 2003.  The analysis and

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testimony supported the exit from MISO, under certain conditions.  The MISO filed its own testimony and cost benefit analysis in December 2003.  A final Kentucky Commission order is expected in the second quarter of 2004.

ARO.  In 2003, LG&E recorded $6.0 million in regulatory assets and $0.1 million in regulatory liabilities related to SFAS No. 143, Accounting for Asset Retirement Obligations.

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

Merger Surcredit.  As part of the LG&E Energy merger with KU Energy in 1998, 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 was deferred and 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 approving the merger, the Kentucky Commission adopted LG&E’s proposal to reduce its retail customers’ bills based on one-half of the estimated merger-related savings, net of deferred and amortized amounts, over a five-year period.  The surcredit mechanism provides that 50% of the net non-fuel cost savings estimated to be achieved from the merger be provided to ratepayers through a monthly bill credit, and 50% be retained by LG&E and KU, over a five-year period.  The surcredit was allocated 53% to KU and 47% to LG&E.  In that same order, the Commission required LG&E and KU, after the end of the five-year period, to present a plan for sharing with ratepayers the then-projected non-fuel savings associated with the merger.  The Companies submitted this filing in January 2003, proposing to continue to share with ratepayers, on a 50%/50% basis, the estimated fifth-year gross level of non-fuel savings associated with the merger.  In October 2003, the Kentucky Commission issued an order approving a settlement agreement reached with the parties in the case.  LG&E’s merger surcredit will remain in place for another five-year term beginning July 1, 2003 and the merger savings will continue to be shared 50% with ratepayers and 50% with shareholders.

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

Note 4 - Financial Instruments

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

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

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

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

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.

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

Energy Trading & Risk Management Activities.  LG&E conducts energy trading and risk management activities 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 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 rescission of EITF No. 98-10 for fiscal periods ending after December 15, 2002, had no impact on LG&E’s energy trading and risk management reporting as all forward and option contracts marked to market under EITF No. 98-10 are also within the scope of SFAS No. 133.

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

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

No changes to valuation techniques for energy trading and risk management activities occurred during 2003.  Changes in market pricing, interest rate and volatility assumptions were made during both years.  All contracts outstanding at December 31, 2003, have a maturity of less than one year and are valued using 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.  At December 31, 2003, 100% of the trading and risk management commitments were with counterparties rated BBB-/Baa3 equivalent or better.

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LG&E hedges the price volatility of its forecasted peak electric off-system sales with the sale of market-traded electric forward contracts for periods less than one year.  These electric forward sales have been designated as cashflow hedges and are not speculative in nature.  Gains or losses on these instruments, to the extent that the hedging relationship has been effective, are deferred in other comprehensive income.  Gains and losses resulting from ineffectiveness are shown in LG&E’s Consolidated Statements of Income in other income (expense) – net.  Upon expiration of these instruments, the amount recorded in other comprehensive income is recorded in earnings.  In 2003, LG&E recognized a pre-tax loss of approximately $18,000, and a loss, net of tax, deferred in other comprehensive income of approximately $147,000.

Accounts Receivable Securitization.  On February 6, 2001, LG&E implemented an accounts receivable securitization program.  The purpose of this program was 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 allowed for a percentage of eligible receivables to be sold.  Eligible receivables were generally all receivables associated with retail sales that have standard terms and are not past due.  LG&E was able to terminate the program at any time without penalty.

LG&E terminated the accounts receivable securitization program in January 2004 and replaced it with long-term intercompany loans from an E.ON affiliate.  The accounts receivable program required LG&E R to maintain minimum levels of net worth.  The program also contained a cross-default provision if LG&E defaulted on debt obligations in excess of $25 million.  If there was a significant deterioration in the payment record of the receivables by the retail customers or if LG&E failed to meet certain covenants regarding the program, the program could 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.  LG&E did not violate any covenants with regard to the accounts receivable securitization program.

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 could sell, on a revolving basis, an undivided interest in certain of its receivables and receive up to $75 million from an unrelated third-party purchaser.  The effective cost of the receivables program was comparable to LG&E’s lowest cost source of capital, and was based on prime rated commercial paper. LG&E retained servicing rights of the sold receivables through two separate servicing agreements with the third-party purchaser.  LG&E obtained an opinion from independent legal counsel indicating these transactions qualified as a true sale of receivables.  As of December 31, 2003, the outstanding program balance was $58.0 million.

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

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

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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 312,000 customers and electricity to approximately 384,000 customers in Louisville and adjacent areas in Kentucky.  For the year ended December 31, 2003, 70% of total revenue was derived from electric operations and 30% 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 and completed wage and benefit re-opener negotiations in October 2003.

Note 6 - Pension and Other Post Retirement Benefit Plans

LG&E has both funded and unfunded non-contributory defined benefit pension plans and other post-retirement benefit plans that together cover substantially all of its employees. The healthcare plans are contributory with participants’ contributions adjusted annually.

LG&E uses December 31 as the measurement date for its plans.

Obligations and Funded Status.  The following tables provide a reconciliation of the changes in the plan’s benefit obligations and fair value of assets over the three-year period ending December 31, 2003, and a statement of the funded status as of December 31, 2003, for LG&E’s sponsored defined benefit plan:

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

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Amounts Recognized in Statement of Financial Position. 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, 2003, 2002 and 2001:

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

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

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

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

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

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

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

To develop the expected long-term rate of return on assets assumption, LG&E considered the current level of expected returns on risk free investments (primarily government bonds), the historical level of the risk premium associated with the other asset classes in which the portfolio is invested and the expectations for future returns of each asset class.  The expected return for each asset class was then weighted based on the target asset allocation to develop the expected long-term rate of return on assets assumption for the portfolio.

Assumed Healthcare Cost Trend Rates.  For measurement purposes, a 12.0% annual increase in the per capita cost of covered healthcare benefits was assumed for 2004.  The rate was assumed to decrease gradually to 5.0% by 2015 and remain at that level thereafter.

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

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

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

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

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

The fund focuses on a long-term investment time horizon of at least three to five years or a complete market cycle.  The assets of the pension plans are broadly diversified within different asset classes (equities, fixed income securities and cash equivalents).

To minimize the risk of large losses in a single asset class, no more than 5% of the portfolio will be invested in the securities of any one issuer with the exclusion of the U.S. government and its agencies.  The equity portion of the Fund is diversified among the market’s various subsections to diversify risk, maximize returns and avoid undue exposure to any single economic sector, industry group or individual security.  The equity subsectors include, but are not limited to growth, value, small capitalization and international.

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In addition, the overall fixed income portfolio holdings have a maximum average weighted maturity of no more than fifteen (15) years, with the weighted average duration of the portfolio being no more than eight (8) years.  All securities must be rated “investment grade” or better and foreign bonds in the aggregate shall not exceed 10% of the total fund.  The cash investments should be in securities that either are of short maturities (not to exceed 180 days) or readily marketable with modest risk.

Derivative securities are permitted only to improve the portfolio’s risk/return profile or to reduce transaction costs and must be used in conjunction with underlying physical assets in the portfolio. Derivative securities that involve speculation, leverage, interest rate anticipation, or any undue risk whatsoever are not deemed appropriate investments.

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

Contributions.  LG&E made a discretionary contribution to the pension plan of $34.5 million in January 2004. No further discretionary contributions are planned and no contributions are required for 2004.

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 of this matching were approximately $1.8 million for 2003, $1.7 million for 2002 and $1.2 million for 2001.

Note 7 - Income Taxes

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

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

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

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

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

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

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

Note 8 - Other Income (Expense) - Net

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

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

Note 9 - Long-Term Debt

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

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

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

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Under the provisions for LG&E’s variable-rate pollution control bonds, Series S, T, U, BB, CC, DD and EE, 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 in the Consolidated Balance Sheets.  The average annualized interest rate for these bonds during 2003 was 1.10%.

Interest rate swaps are used to hedge LG&E’s underlying variable-rate debt obligations.  These swaps hedge specific debt issuances and, consistent with management’s designation, are accorded hedge accounting treatment.  As of December 31, 2003, LG&E had swaps with a combined notional value of $228.3 million.  The swaps exchange floating-rate interest payments for fixed rate interest payments to reduce the impact of interest rate changes on LG&E’s pollution control bonds.  See Note 4.

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

LG&E’s first mortgage bond, 6% Series of $42.6 million, matured in 2003.

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

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

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 such that the sinking fund requirements are fully met.

Substantially all of LG&E’s utility plant is pledged as security for its first mortgage bonds.  LG&E’s first mortgage bond 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.  LG&E has not violated any of these conditions that would cause any portion of retained earnings to be restricted by this provision.

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

LG&E has existing $5.875 series mandatorily redeemable preferred stock outstanding having a current redemption price of $100 per share. The preferred stock has a sinking fund requirement sufficient to retire a minimum of 12,500 shares on July 15 of each year commencing with July 15, 2003, and the remaining 187,500 shares on July 15, 2008 at $100 per share.  LG&E redeemed 12,500 shares in accordance with these provisions on July 15, 2003, leaving 237,500 shares currently outstanding.  Beginning with the three months ended September 30, 2003, LG&E reclassified its $5.875 series preferred stock as long-term debt with the minimum shares mandatorily redeemable within one year classified as current.

The following table reflects the long-term debt maturities:

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

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

In January 2004, LG&E entered into one additional long-term loan from an affiliated company totaling $25 million with an interest rate of 4.33% that matures in January 2012.  The loan is secured by a lien subordinated to the first mortgage bond lien.  The proceeds were used to repay amounts due under the accounts receivable securitization program.

Note 10 - Notes Payable and Other Short-Term Obligations

LG&E participates in an intercompany money pool agreement wherein LG&E Energy and KU make funds available to LG&E at market-based rates (based on an index of highly rated commercial paper issues as of the prior month end) up to $400 million.  Likewise, LG&E Energy and LG&E make funds available to KU at market-based rates up to $400 million.  The balance of the money pool loan from LG&E Energy (shown as “Notes payable to affiliated company”) was $80.3 million at an average rate of 1.00% and $193.1 million at an average rate of 1.61%, at December 31, 2003 and 2002, respectively.  The amount available to LG&E under the money pool agreement at December 31, 2003 was $319.7 million.  LG&E Energy maintains a revolving credit facility totaling $150 million with an affiliate to ensure funding availability for the money pool.  The outstanding balance under LG&E Energy’s facility as of December 31, 2003 was $111.1 million, and availability of $38.9 million remained.

During July 2003, LG&E entered into five revolving lines of credit with banks totaling $185 million.  These credit facilities expire in June 2004, and there was no outstanding balance under any of these facilities at December 31, 2003.  The covenants under these revolving lines of credit include:

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

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

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

4.limitation on disposing assets aggregating more than 15% of total assets as of December 31, 2002.

LG&E has not violated any of the above covenants.

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

Note 11 - Commitments and Contingencies

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

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

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

(b)Includes long-term debt of $246.2 million 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 2013 to 2027.

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

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

(e)Represents construction commitments.

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

Operating Lease.  LG&E leases office space, office equipment and vehicles.  LG&E accounts for its leases as operating leases.  Total lease expense for 2003, 2002, and 2001, less amounts contributed by affiliated companies occupying a portion of the office space leased by LG&E, was $2.2 million, $2.2 million, and $2.5 million, respectively.  The future minimum annual lease payments under LG&E’s office space lease agreement for years subsequent to December 31, 2003, are as follows:

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

LG&E is a participant in a sale and leaseback transaction involving its 38% interest in two jointly-owned CTs at KU’s E.W. Brown generating station (Units 6 and 7).  Commencing in December 1999, LG&E and KU entered into a tax-efficient, 18-year lease of the CTs. LG&E and KU have provided funds to fully defease the lease, and have executed an irrevocable notice to exercise an early purchase option contained in the lease after 15.5 years. The financial statement treatment of this transaction is no different than if LG&E had retained its ownership.  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.  The leasing transaction was entered into following receipt of required state and federal regulatory approvals.

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

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

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

Letters of Credit.  LG&E has provided letters of credit totaling $14.3 million as collateral for derivative transactions and to support certain obligations related to landfill reclamation.

Purchased Power. LG&E has a contract for purchased power with OVEC for various Mw capacities.  LG&E has an investment of 4.9% ownership in OVEC’s common stock, which is accounted for under the cost method of accounting.  LG&E’s entitlement is 7% of OVEC’s generation capacity or approximately 155 Mw.

The estimated future minimum annual demand payment under the OVEC purchased power agreement for the years subsequent to December 31, 2003, are as follows:

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

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

Environmental Matters.  LG&E is subject to SO₂ and NOx emission limits on its electric generating units pursuant to the Clean Air Act.  LG&E was not subject to Phase I SO₂ emissions reduction requirements.  LG&E’s strategy for Phase II SO₂ reductions, which commenced January 1, 2000, is to increase FGD removal efficiency to delay additional capital expenditures and may also include fuel switching or upgrading FGDs.  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 SIP, which was approved by EPA June 24, 2003, requires 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 $185 million to reduce its NOx emissions to the 0.15 lb./Mmbtu level on a company-

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wide basis.  As of December 31, 2003, LG&E has incurred approximately $177 million of these capital costs related to the reduction of its NOx emissions.  In addition, LG&E will incur additional operation 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 EPA’s revised air quality standards for ozone and particulate matter, measures to implement EPA’s regional haze rule, EPA’s December 2003 proposals to regulate mercury emissions from steam electric generating units and to further reduce emissions of sulfur dioxide and nitrogen oxides under the Interstate Air Quality Rule.  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 $0.4 million.  Accordingly, an accrual of $0.4 million has been recorded in the accompanying financial statements at December 31, 2003 and 2002.

Note 12 - 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	386.2			66.4		62.4		515.0
LG&E’s 75% ownership (in thousands of $):
Cost	$	595,313
Accumulated depreciation	194,343
Net book value	$	400,970
Construction work in progress (included above)	$	8,374

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

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

99

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

Note 13 - Segments of Business and Related Information

LG&E is a regulated public utility engaged in the generation, transmission, distribution, and sale of electricity and the storage, distribution, and sale of natural gas.  LG&E is regulated by the Kentucky Commission and files electric and gas financial information separately with the Kentucky Commission.  The Kentucky Commission establishes rates specifically for the electric and gas businesses.  Therefore, management reports and analyzes financial performance based on the electric and gas segments of the business.  Financial data for business segments follow:

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

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

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

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

100

Note 14 - Related Party Transactions

LG&E, subsidiaries of LG&E Energy and other subsidiaries of E.ON engage in related party transactions.  Transactions between LG&E and its subsidiary LG&E R are eliminated upon consolidation with LG&E.  Transactions between LG&E and LG&E Energy subsidiaries are eliminated upon consolidation of LG&E Energy. Transactions between LG&E and E.ON subsidiaries are eliminated upon consolidation of E.ON. These transactions are generally performed at cost and are in accordance with the SEC regulations under the PUHCA and the applicable Kentucky Commission regulations.  Amounts payable to and receivable from related parties are netted and presented as accounts payable to affiliated companies on the balance sheet of LG&E, as allowed due to the right of offset. Obligations related to intercompany debt arrangements with LG&E Energy and Fidelia, an E.ON subsidiary, are presented as separate line items on the balance sheet, as appropriate. The significant related party transactions are disclosed below.

Electric Purchases

LG&E and KU purchase energy from each other in order to effectively manage the load of their retail and off-system customers.  In addition, LG&E and LG&E Energy Marketing Inc. (“LEM”), a subsidiary of LG&E Energy, purchase energy from each other. These sales and purchases are included in the Consolidated Statements of Income as Electric Operating Revenues and Purchased Power Operating Expense.  LG&E intercompany electric revenues and purchased power expense for the years ended December 31, 2003, 2002, and 2001 were as follows:

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

Interest Charges

LG&E participates in an intercompany money pool agreement wherein LG&E Energy and KU make funds available to LG&E at market-based rates (based on an index of highly rated commercial paper issues as of the prior month end) up to $400 million.  Likewise, LG&E Energy and LG&E make funds available to KU at market-based rates up to $400 million.  The balance of the money pool loan from LG&E Energy (shown as “Notes payable to affiliated company”) was $80.3 million at an average rate of 1.00% and $193.1 million at an average rate of 1.61%, at December 31, 2003 and 2002, respectively.  The amount available to LG&E under the money pool agreement at December 31, 2003 was $319.7 million.  LG&E Energy maintains a revolving credit facility totaling $150 million with an affiliate to ensure funding availability for the money pool.  The outstanding balance under LG&E Energy’s facility as of December 31, 2003 was $111.1 million, and availability of $38.9 million remained.

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

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

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

101

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

Other Intercompany Billings

LG&E Services provides LG&E with a variety of centralized administrative, management, and support services in accordance with agreements approved by the SEC under PUHCA. These charges include taxes paid by LG&E Energy on behalf of LG&E, labor and burdens of LG&E Services employees performing services for LG&E, and vouchers paid by LG&E Services on behalf of LG&E.  The cost of these services are directly charged to LG&E, or for general costs which cannot be directly attributed, charged based on predetermined allocation factors, including the following ratios: number of customers, total assets, revenues, number of employees, and other statistical information.  These costs are charged on an actual cost basis.

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

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

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

Note 15 - Selected Quarterly Data (Unaudited)

Selected financial data for the four quarters of 2003 and 2002 are shown below.  Because of seasonal fluctuations in temperature and other factors, results for quarters may fluctuate throughout the year.

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

102

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

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

Note 16 - Subsequent Events

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

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

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

In January 2004, LG&E entered into a long-term loan with an affiliated company totaling $25 million with an interest rate of 4.33% that matures in January 2012.  The proceeds were used to repay amounts due under the accounts receivable securitization program. The loan is secured by a lien subordinated to the first mortgage bond lien (see Note 9).

103

Louisville Gas and Electric Company and Subsidiary
REPORT OF MANAGEMENT

The management of Louisville Gas and Electric Company and Subsidiary 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 2003, 2002 and 2001 financial statements have been audited by PricewaterhouseCoopers LLP, independent auditors.  Management made available to PricewaterhouseCoopers LLP 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 and external auditors.  These recommendations for the year ended December 31, 2003, did not identify any material weaknesses in the design and operation of LG&E’s internal control structure.

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

Louisville Gas and Electric Company and Subsidiary maintains and internally communicates a written code of business conduct and a senior financial officer code of ethics which address, 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

Chief Financial Officer

Louisville Gas and Electric Company and Subsidiary

Louisville, Kentucky

104

Louisville Gas and Electric Company and Subsidiary
REPORT OF INDEPENDENT AUDITORS

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

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of capitalization, income, retained earnings, cash flows and comprehensive income present fairly, in all material respects, the financial position of Louisville Gas and Electric Company and Subsidiary (the “Company”) at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America.  In addition, in our opinion, based on our audits, the financial statement schedule as of and for the year ended December 31, 2003 listed in the index appearing under Item 15(a)(2), presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidatedfinancial statements.  These financial statements and financial statement schedules are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits.  We conducted our audits 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 audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the consolidated financial statements, effective January 1, 2003,  Louisville Gas and Electric Company and Subsidiary adopted EITF No. 02-03, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.  As discussed in Note 1 to the consolidated financial statements, effective January 1, 2003, Louisville Gas and Electric Company and Subsidiary adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations.  As discussed in Note 1 to the consolidated financial statements, effective July 1, 2003, Louisville Gas and Electric Company and Subsidiary adopted Statement of Financial Accounting Standards No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Louisville, Kentucky

February 5, 2004

105

INDEX OF ABBREVIATIONS

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

106

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

107

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

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

Consolidated Statements of Retained Earnings
(Thousands of $)

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

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

108

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

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

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

109

Kentucky Utilities Company and Subsidiary
Consolidated Balance Sheets
(Thousands of $)

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

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

110

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

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

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

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

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

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

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

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Kentucky Utilities Company and Subsidiary
Notes to Consolidated Financial Statements

Note 1 - Summary of Significant Accounting Policies

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

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

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

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

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

Regulatory Accounting.  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 item.  See Note 3 for additional detail regarding regulatory assets and liabilities.

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 a significant allowance for funds used during construction.

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

Depreciation and Amortization.  Depreciation is provided on the straight-line method over the estimated service lives of depreciable plant.  The amounts provided were approximately 3.1% in 2003, 3.1% in 2002 and  3.1% in 2001, of average depreciable plant. Of the amount provided for depreciation at December 31, 2003, approximately 0.6% was related to the retirement, removal and disposal costs of long lived assets.

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Cash and Temporary Cash Investments.  KU considers all 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.

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

Other Materials and Supplies.  Non-fuel materials and supplies of $27.1 million and $26.4 million at December 31, 2003 and 2002, respectively, are accounted for using the average-cost method.

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.  KU uses sales of market-traded electric forward contracts for periods less than one year to hedge the price volatility of its forecasted peak electric off-system sales.  Gains and losses resulting from ineffectiveness are shown in other income (expense) and to the extent that the hedging relationship has been effective, gains and losses are reflected in other comprehensive income.  See Note 4 – Financial Instruments.

Unamortized 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 are recognized at currently enacted tax rates for all material temporary differences between the financial reporting and income tax basis of assets and liabilities.

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 the accounting period based on allocating the daily system net deliveries between billed volumes and unbilled volumes.  The allocation is based on a daily ratio of the number of meter reading cycles remaining in the month to the total number of meter reading cycles in each month.  Each day’s ratio is then multiplied by each day’s system net deliveries to determine an estimated billed and unbilled volume for each day of the accounting period.  The unbilled revenue estimates included in accounts receivable were approximately $38.7 million and $36.4 million at December 31, 2003, and 2002, respectively.

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

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.  Accrued liabilities, including legal and environmental, are recorded when they are reasonable and estimable.  Actual results could differ from those estimates.  See Note 11,

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Commitments and Contingencies, for a further discussion.

New Accounting Pronouncements.  The following accounting pronouncements were implemented by KU in 2003:

SFAS No. 143, Accounting for Asset Retirement Obligations 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.

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

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

Had SFAS No. 143 been in effect for the 2002 reporting period, KU would have established asset retirement obligations as described in the following table:

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

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

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

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

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

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

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

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

•Rescinded EITF No. 98-10,

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

•Revenues should be shown in the income statement net of costs associated
with trading activities, whether or not the trades are physically settled.

With the rescission of EITF No. 98-10, energy trading contracts that do not also meet the definition of a derivative under SFAS No. 133 must be accounted for as executory contracts.  Contracts previously recorded at fair value under EITF No. 98-10 that are not also derivatives under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, must be restated to historical cost through a cumulative effect adjustment.  The rescission of this standard had no impact on financial position or results of operations of KU since all forward and option contracts marked to market under EITF No. 98-10 were also within the scope of SFAS No. 133.

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

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

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

In January 2003, the Financial Accounting Standards Board issued Financial Accounting Standards Board Interpretation No. 46, Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51 (FIN 46).  FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support

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

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

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

Note 2 – Mergers and Acquisitions

On July 1, 2002, E.ON completed its acquisition of Powergen, including LG&E Energy, for approximately £5.1 billion ($7.3 billion).  As a result of the acquisition, LG&E Energy became a wholly owned subsidiary (through Powergen) of E.ON and, as a result, KU also became an indirect subsidiary of E.ON.  KU has continued its separate identity and serves customers in Kentucky, Virginia and Tennessee under its existing names.  The preferred stock and debt securities of KU were not affected by this transaction and the utilities continue to file SEC reports.  Following the acquisition, E.ON became, and Powergen remained, a registered holding company under PUHCA.  KU, as a subsidiary of a registered holding company, is subject to additional regulations under PUHCA.  As contemplated in their regulatory filings in connection with the E.ON acquisition, E.ON, Powergen and LG&E Energy completed an administrative reorganization to move the LG&E Energy group from an indirect Powergen subsidiary to an indirect E.ON subsidiary.  This reorganization was effective in March 2003. In early 2004, LG&E Energy commenced direct reporting arrangements to E.ON.

LG&E Energy and KU Energy merged on May 4, 1998, with LG&E Energy as the surviving corporation. Management accounted for the merger as a pooling of interests and as a tax-free reorganization under the Internal Revenue Code.  Following these acquisitions, KU has continued to maintain its separate identity and serve customers under its present name.

Note 3 - Rates and Regulatory Matters

The following regulatory assets and liabilities were included in KU’s balance sheets as of December 31:

(in thousands)	2003			2002
VDT costs	$	26,451		$	38,375
Unamortized loss on bonds	10,511			9,456
ESM provision	12,382			13,500
VA FAC	4,298			4,703
LG&E/KU merger costs	—			2,046
Merger surcredit	4,815			—
One utility costs	—			873
ARO	11,322			—
DSM	(1,563		)	(1,628		)
Post retirement and pension	1,006			662
Total regulatory assets	$	69,222		$	67,987
Accumulated cost of removal of utility plant	$	(266,832	)	$	(248,552	)
Deferred income taxes - net	(24,058		)	(28,854		)
ARO	(1,162		)	—
Spare parts	(1,055		)	(1,022		)
ESM	—			(472		)
ECR	(9,189		)	(2,962		)
FAC	(1,000		)	—
Total regulatory liabilities	$	(303,296	)	$	(281,862	)

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KU currently earns a return on all regulatory assets except for ESM, DSM and FAC, all of which are separate recovery mechanisms with recovery within twelve months.  Additionally, no current return is earned on the ARO regulatory asset.  This regulatory asset will be offset against the associated regulatory liability, ARO asset, and ARO liability at the time the underlying asset is retired.

Kentucky Commission Settlement Order - VDT Costs. During the first quarter of 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 healthcare benefits.  The result of this workforce reduction was the elimination of approximately 300 positions, accomplished primarily through a voluntary enhanced severance program.

In June 2001, KU filed an application (VDT case) with the 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 a new depreciation study and resulting depreciation rates implemented in 2001.

KU reached a settlement in the VDT case as well as other cases involving the depreciation rates and ESM with all intervening parties.  The settlement agreement was approved by the Kentucky Commission in December 2001.  The 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 2001 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 to the regulatory asset from $64 million to $54 million. The settlement reduces revenues approximately $11 million through a surcredit on bills to ratepayers 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 2001.  The new depreciation rates decreased depreciation expense by $6.0 million in 2001.

PUHCA.  Following the purchases of LG&E Energy by Powergen and Powergen by E.ON, Powergen and E.ON became registered holding companies under PUHCA.  As a result, E.ON, 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.  KU believes that it has adequate authority (including financing authority) under existing SEC orders and regulations to conduct its business.  KU will seek additional authorization when necessary.

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

In March 2003, the Kentucky Commission initiated a series of six-month and two-year reviews of the operation of KU’s Environmental Surcharge.  A final order was issued on October 17, 2003 resolving all outstanding issues related to over-recovery from customers and under-recovery of allowed O&M expense.  The Commission found that KU had over-collected a net $6.0 million from customers and ordered the refund to occur through adjustments to the calculation of the monthly surcharge billing factor over the subsequent 12 month period.  The Commission further ordered KU to roll $17.9 million of environmental assets into base rates and make corresponding adjustment in the monthly environmental surcharge filings to reflect that portion of environmental rate base now included in base rates going forward.  The rates of return for KU’s 1994 and post-1994 plans were reset to 1.24% and 12.60%, respectively.

ESM. KU’s electric rates are subject to an ESM.  The ESM, initially 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, the excess earnings are shared 40% with ratepayers and 60% with shareholders; if earnings are below the lower limit, the earnings deficiency is recovered 40% from ratepayers and 60% from shareholders.  By order of the Kentucky Commission, rate changes prompted by the ESM filing go into effect in April of each year subject to a balancing adjustment in successive periods.

In November 2002, KU filed a revised ESM tariff which proposed continuance of the existing ESM through December 2005.  In addition, the Kentucky Commission initiated a focused management audit to review the ESM plan and reassess its reasonableness, and recently concluded discovery in the case.  KU and interested parties had the opportunity to provide recommendations for modification and continuance of the ESM or other forms of alternative or incentive regulation.  Continuance of the ESM is still being deliberated by the Kentucky Commission and a final order is not expected until the second quarter.  The ESM tariff remains in effect pending the resolution of the case.

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

DSM.  In May 2001, the Kentucky Commission approved a plan that would expand LG&E’scurrent DSM programs into the service territory served by KU.  The plan included a rate mechanism that provided for concurrent recovery of DSM costs, provided an incentive for implementing DSM programs, and recovered revenues from lost sales associated with the DSM programs based on program plan engineering estimates and post-implementation evaluation.

FAC.  KU employs an FAC mechanism, which allows under Kentucky law, KU to recover from customers’ 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.  In August 1999, after a rehearing request by KU, the Kentucky Commission issued a final order that reduced the refund obligation to $6.7 million ($5.8 million on a Kentucky jurisdictional basis) from the

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original order amount of $10.1 million.  KU implemented the refund from October 1999 through September 2000.  Both KU and the KIUC appealed the order.  Pending a decision on this appeal, a comprehensive settlement was reached by all parties and approved by the Kentucky Commission in May 2002.  Thereunder, KU agreed to credit its fuel clause in the amount of $1.0 million (refund made in June and July 2002), and the parties agreed on a prospective interpretation of the state’s FAC regulation to ensure consistent and mutually acceptable application going forward.

In January 2003, the Kentucky Commission reviewed KU’s FAC for the six month period ended October 31, 2002. The Kentucky Commission ordered KU to reduce its fuel costs for purposes of calculating its FAC by $0.7 million. At issue was the purchase of approximately 102,000 tons of coal from Western Kentucky Energy Corporation, a non-regulated affiliate, for use at KU’s Ghent facility. The Kentucky Commission further ordered that an independent audit be conducted to examine operational and management aspects of both KU’s and LG&E’s fuel procurement functions.  A final report was issued in February 2004.  The report’s recommendations related to documentation and process improvements will be addressed with the Kentucky Commission staff as Management Audit Plans are developed in the second quarter of 2004.

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.  KU also employs a FAC mechanism for Virginia customers that 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.  No other significant issues have been identified as a result of these reviews.

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

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.  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 utility’s 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.  In February 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.

Kentucky Commission Administrative Case for System Adequacy.  In June 2001, Kentucky’s Governor

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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.  In response to that Executive Order, 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.  In December 2001, the Kentucky Commission issued an order in which it noted that KU is responsibly addressing the long-term supply needs of native load customers and that current reserve margins are appropriate.  However, due to the rapid pace of change in the industry, the order also requires KU to provide an annual assessment of supply resources, future demand, reserve margin, and the need for new resources.

Regarding the transmission system, the Kentucky Commission concluded that the transmission system within Kentucky 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.

FERC SMD NOPR.  In July 2002, the FERC issued a NOPR in Docket No. RM01-12-000 which would substantially alter the regulations governing the nation’s wholesale electricity markets by establishing a common set of rules, SMD. The SMD NOPR would require each public utility that owns, operates, or controls interstate transmission facilities to become an Independent Transmission Provider (ITP), belong to a RTO that is an ITP, or contract with an ITP for operation of its transmission assets. It would also establish a standardized congestion management system, real-time and day-ahead energy markets, and a single transmission service for network and point-to-point transmission customers. Review of the proposed rulemaking is underway and no timeframe has been established by the FERC for adoption of a final rule.  While it is expected that the SMD final rule will affect KU revenues and expenses, the specific impact of the rulemaking is not known at this time.

MISO.  KU and LG&E are founding members of the MISO.  Membership was obtained in 1998 in response to and consistent with federal policy initiatives.  In February 2002, KU and LG&E turned over operational control of their high voltage transmission facilities (100kV and above) to the MISO.  The MISO currently controls over 100,000 miles of transmission over 1.1 million square miles located in the northern Midwest between Manitoba, Canada and Kentucky.  In September 2002, FERC granted a 12.88% ROE on transmission facilities for KU, LG&E, and the rest of the MISO owners.

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

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As a separate matter, MISO, its transmission owners and other interested industry segments reached a settlement in mid-2002 regarding the levelof cost responsibility properly borne by bundled and grandfathered load under these FERC rulings (such settlement expressly not prejudicing the transmission owners’ and KU’s right to challenge the FERC’s ruling imposing cost responsibility on bundled loads in the first instance).  In February 2003, FERC accepted a partial settlement between MISO and the transmission owners.  FERC did not accept the only contested section of the settlement, which would have allowed the transmission owners to immediately treat unrecoverable Schedule 10 charges as regulatory assets.  FERC will consider allowing regulatory asset treatment of unrecoverable Schedule 10 charges on a case-by-case basis.

The MISO plans to implement a congestion management system in December 2004, in compliance with FERC Order 2000.  This system will be similar to the Locational Marginal Pricing (LMP) system currently used by the PJM RTO and contemplated in FERC’s SMD NOPR, currently being discussed.  The MISO filed with FERC a mechanism for recovery of costs for the congestion management system.  They proposed the addition of two new Schedules, 16 and 17.  Schedule 16 is the MISO’s cost recovery mechanism for the Financial Transmission Rights Administrative Service it will provide.  Schedule 17 is the MISO’s mechanism for recovering costs it will incur for providing Energy Marketing Support Administrative Service.  The MISO transmission owners, including KU and LG&E, have objected to the allocation of costs among market participants and retail native load.  A hearing at FERC has been completed, but a ruling has not been issued.

The Kentucky Commission opened an investigation into KU’s and LG&E’s membership in MISO in July 2003.  The Kentucky Commission directed KU and LG&E to file testimony addressing the costs and benefits of MISO membership both currently and over the next five years and other legal issues surrounding continued membership.  LG&E and KU engaged an independent third-party to conduct a cost benefit analysis on this issue.  The information was filed with the Kentucky Commission in September 2003.  The analysis and testimony supported the exit from MISO, under certain conditions.  The MISO filed its own testimony and cost benefit analysis in December 2003.  A final Kentucky Commission order is expected in the second quarter of 2004.

ARO.  In 2003, KU recorded approximately $11.3 million in regulatory assets and approximately $1.2 million in regulatory liabilities related to SFAS No. 143, Accounting for Asset Retirement Obligations.

Accumulated Cost of Removal.  As of December 31, 2003 and 2002, KU has segregated the cost of removal, embedded in accumulated depreciation, of $266.8 million and $248.6 million, respectively, in accordance with FERC Order No. 631.  For reporting purposes in the Consolidated Balance Sheet, KU has presented this cost of removal as a regulatory liability pursuant to SFAS No. 71.

Merger Surcredit.  As part of the LG&E Energy merger with KU Energy, KU 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 was deferred and 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) in the second quarter of 1998.

In approving the merger, the Kentucky Commission adopted KU’s proposal to reduce its retail customers’ bills based on one-half of the estimated merger-related savings, net of deferred and amortized amounts, over a five-year period.  The surcredit mechanism provides that 50% of the net non-fuel cost savings estimated to be LG&E and KU, over a five-year period.  The surcredit was allocated 53% to KU and 47% to LG&E.  In that same order, the Commission required LG&E and KU, after the end of the five-year period, to present a plan for

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sharing with ratepayers the then-projected non-fuel savings associated with the merger.  The Companies submitted this filing in January 2003, proposing to continue to share with ratepayers, on a 50%/50% basis, the estimated fifth-year gross level of non-fuel savings associated with the merger.  In October 2003, the Kentucky Commission issued an order approving a settlement agreement reached with the parties in the case.  KU’s merger surcredit will remain in place for another five-year term beginning July 1, 2003 and the merger savings will continue to be shared 50% with ratepayers and 50%/with shareholders.

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

Note 4 - Financial Instruments

The cost and estimated fair values of KU’s non-trading financial instruments as of December 31, 2003, and 2002 follow:

	2003				2002
(in thousands)	Cost		Fair Value		Cost		Fair Value
Long-term debt (including current portion)	$	389,830	$	405,439	$	484,830	$	503,194
Long-term debt from associates	283,000		288,292		—		—
Interest-rate swaps	—		12,223		—		16,928

All of the above valuations reflect prices quoted by exchanges except for the swaps and the intercompany loans.  The fair values of the swaps and intercompany loans 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, 2003 and 2002, KU was party to various interest rate swap agreements with aggregate notional amounts of $153 million in 2003 and 2002.  Under these swap agreements, KU paid variable rates based on either LIBOR or the Bond Market Association’s municipal swap index averaging 1.85% and 2.36%, and received fixed rates averaging 7.13% and 7.13% at December 31, 2003 and 2002, respectively. The swap agreements in effect at December 31, 2003 have been designated as fair value hedges and mature on dates ranging from 2007 to 2025.  For 2003, the effect of marking these financial instruments and the underlying debt to market resulted in immaterial pretax gains recorded in interest expense.  Upon expiration of these hedges, any resulting gain or loss will be amortized over the remaining term of the related debt.

Interest rate swaps hedge interest rate risk on the underlying debt under SFAS No. 133, in addition to swaps being marked to market, the item being hedged must also be marked to market, consequently at December 31, 2003, KU’s debt reflects a $14.7 million mark to market adjustment.

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In February 2004, KU terminated the swap it had in place at December 31, 2003 related to the Series 9 pollution control bonds.  The notional amount of the terminated swap was $50 million and KU received a payment of $2.0 million as part of the termination.  The swap was terminated because it was no longer an effective hedge of the underlying bond.

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

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

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

No changes to valuation techniques for energy trading and risk management activities occurred during 2003.  Changes in market pricing, interest rate and volatility assumptions were made during both years.  All contracts outstanding at December 31, 2003, have a maturity of less than one year and are valued using prices actively quoted for proposed or executed transactions or quoted by brokers.

KU maintains policies intended to minimize credit risk and revalues credit exposures daily to monitor compliance with those policies.  At December 31, 2003, 100% of the trading and risk management commitments were with counterparties rated BBB-/Baa3 equivalent or better.

KU hedges the price volatility of its forecasted peak electric off-system sales with the sales of market-traded electric forward contracts for periods less than one year.  These electric forward sales have been designated as cashflow hedges and are not speculative in nature.  Gains or losses on these instruments, to the extent that the hedging relationship has been effective, are deferred in other comprehensive income.  Gains and losses resulting from ineffectiveness are shown in KU’s Consolidated Statements of Income in other income (expense) – net.  Upon expiration of these instruments, the amount recorded in other comprehensive income is recorded in earnings.  In 2003, KU recognized a pre-tax loss of approximately $18,000, and a loss, net of tax, deferred in other comprehensive income of approximately $147,000.

Accounts Receivable Securitization.  On February 6, 2001, KU implemented an accounts receivable securitization program.  The purpose of this program was 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 allowed for a percentage of eligible receivables to be sold.  Eligible receivables were generally all receivables associated with retail sales that have standard terms and are not past due.  KU was able to terminate this program at any time without penalty.

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KU terminated the accounts receivable securitization program in January 2004 and replaced it with long-term loans from an E.ON affiliate.  The accounts receivable program required KU R to maintain minimum levels of net worth.  The program also contained a cross-default provision if KU defaulted on debt obligations in excess of $25 million.  If there was a significant deterioration in the payment record of the receivables by the retail customers or if KU failed to meet certain covenants regarding the program, the program could 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.  KU did not violate any covenants with regard to the accounts receivable securitization program.

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 could sell, on a revolving basis, an undivided interest in certain of its receivables and receive up to $50 million from an unrelated third-party purchaser.  The effective cost of the receivables program was comparable to KU’s lowest cost source of capital, and was based on prime rated commercial paper. KU retained servicing rights of the sold receivables through two separate servicing agreements with the third-party purchaser.  KU obtained an opinion from independent legal counsel indicating these transactions qualified as a true sale of receivables.  As of December 31, 2003, the outstanding program balance was $50.0 million.

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

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

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.

KU’s customer receivables and revenues arise from deliveries of electricity to approximately 482,000 customers in over 600 communities and adjacent suburban and rural areas in 77 counties in central, southeastern and western Kentucky, to approximately 30,000 customers in five counties in southwestern Virginia and less than ten customers in Tennessee.  For the year ended December 31, 2003, 100% of total utility revenue was derived from electric operations.

In August 2003, KU and its employees represented by IBEW Local 2100 entered into a three-year collective bargaining agreement. KU and its employees represented by USWA Local 9447-01 entered into a three-year

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collective bargaining agreement effective August 2002 and expiring August 2005.  The employees represented by these two bargaining units comprise approximately 16% of KU’s workforce.

Note 6 - Pension Plans and Other Postretirement Benefit Plans

KU has both funded and unfunded noncontributory defined benefit pension plans and other postretirement benefit plans that together cover substantially all of its employees.  The healthcare plans are contributory with participants’ contributions adjusted annually.

KU uses December 31 as the measurement date for its plans.

Obligations & Funded Status.  The following table provides a reconciliation of the changes in the plan’s benefit obligations and fair value of assets over the three-year period ending December 31, 2003, and a statement of the funded status as of December 31, 2003, for KU’s sponsored defined benefit plan:

(in thousands)	2003			2002			2001
Pension Plans:
Change in benefit obligation
Benefit obligation at beginning of year	$	247,727		$	244,472		$	233,034
Service cost	2,962			2,637			2,761
Interest cost	15,924			16,598			17,534
Plan amendment	40			28			4
Change due to transfers	(269		)	—			(16,827		)
Curtailment loss	—			—			1,400
Special termination benefits	—			—			24,274
Benefits and lump sums paid	(22,594		)	(23,291		)	(29,166		)
Actuarial (gain) or loss and other	13,915			7,283			11,458
Benefit obligation at end of year	$	257,705		$	247,727		$	244,472
Change in plan assets
Fair value of plan assets at beginning of year	$	178,534		$	216,947		$	244,677
Actual return on plan assets	36,528			(13,767		)	18,155
Employer contributions	10,231			15,283			1
Changes due to transfers	(206		)	(15,382		)	(15,301		)
Benefits and lump sums paid	(22,594		)	(23,291		)	(29,166		)
Administrative expenses	(1,400		)	(1,256		)	(1,419		)
Fair value of plan assets at end of year	$	201,093		$	178,534		$	216,947
Reconciliation of funded status
Funded status	$	(56,611	)	$	(69,193	)	$	(27,525	)
Unrecognized actuarial (gain) or loss	27,917			36,233			(20,581		)
Unrecognized transition (asset) or obligation	(399		)	(532		)	(664		)
Unrecognized prior service cost	9,184			10,106			11,027
Net amount recognized at end of year	$	(19,909	)	$	(23,386	)	$	(37,743	)
Other Benefits:
Change in benefit obligation
Benefit obligation at beginning of year	$	104,602		$	83,223		$	64,213
Service cost	805			610			495
Interest cost	6,313			6,379			5,433
Curtailment loss	—			—			6,381
Special termination benefits	—			—			3,824
Benefits and lump sums paid net of retiree contributions	(7,329		)	(4,640		)	(5,446		)
Actuarial (gain) or loss	1,372			19,030			8,323
Benefit obligation at end of year	$	105,763		$	104,602		$	83,223
Change in plan assets
Fair value of plan assets at beginning of year	$	7,943		$	14,330		$	23,762
Actual return on plan assets	(775		)	(2,698		)	(4,404		)
Employer contributions	5,506			1,648			1,071
Changes due to transfers	—			—			(598		)
Benefits and lump sums paid net of retiree contributions	(7,295		)	(5,337		)	(5,501		)
Fair value of plan assets at end of year	$	5,379		$	7,943		$	14,330
Reconciliation of funded status
Funded status	$	(100,383	)	$	(96,659	)	$	(68,893	)
Unrecognized actuarial (gain) or loss	24,013			22,667			(437		)
Unrecognized transition (asset) or obligation	10,088			11,209			12,290
Unrecognized prior service cost	2,142			2,891			3,548
Net amount recognized at end of year	$	(64,140	)	$	(59,892	)	$	(53,492	)

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Amounts Recognized in Statement of Financial Position.  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, 2003, 2002, and 2001:

(in thousands)	2003			2002			2001
Pension Plans:
Amounts recognized in the balance sheet consisted of:
Accrued benefit liability	$	(38,960	)	$	(51,035	)	$	(37,743	)
Intangible asset	9,184			10,106			—
Accumulated other comprehensive income	9,867			17,543			—
Net amount recognized at year-end	$	(19,909	)	$	(23,386	)	$	(37,743	)
Additional year-end information for plans with accumulated benefit obligations in excess of plan assets:
Projected benefit obligation	$	257,705		$	247,727		$	244,472
Accumulated benefit obligation	240,054			229,569			224,261
Fair value of plan assets	201,093			178,534			216,947
Other Benefits:
Amounts recognized in the balance sheet consisted of:
Accrued benefit liability	$	(64,140	)	$	(59,892	)	$	(53,492	)
Additional year-end information for plans with benefit obligations in excess of plan assets:
Projected benefit obligation	$	105,763		$	104,602		$	83,223
Fair value of plan assets	5,379			7,943			14,330
Increase (decrease) in minimum liability included in other comprehensive income	$	(7,676	)	$	17,543		$	0

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

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(in thousands)	2003			2002			2001
Pension Plans:
Components of net periodic benefit cost
Service cost	$	2,962		$	2,637		$	2,761
Interest cost	15,925			16,598			17,534
Expected return on plan assets	(14,888		)	(18,406		)	(19,829		)
Amortization of prior service cost	957			956			962
Amortization of transition (asset) or obligation	(133		)	(133		)	(136		)
Recognized actuarial (gain) or loss	1,211			1			(120		)
Net periodic benefit cost	$	6,034		$	1,653		$	1,172
Special charges
Prior service cost recognized	$	—		$	—		$	1,238
Special termination benefits	—			—			24,274
Total charges	$	—		$	—		$	25,512
Other Benefits:
Components of net periodic benefit cost
Service cost	$	806		$	610		$	495
Interest cost	6,313			6,379			5,433
Expected return on plan assets	(337		)	(1,022		)	(1,313		)
Amortization of prior service cost	714			691			740
Amortization of transition (asset) or obligation	1,121			1,081			1,193
Recognized actuarial (gain) or loss	1,137			343			(40		)
Net periodic benefit cost	$	9,754		$	8,082		$	6,508
Special charges
Transition obligation recognized	$	—		$	—		$	7,638
Prior service cost recognized	—			—			1,613
Special termination benefits	—			—			3,824
Total charges	$	—		$	—		$	13,075

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

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

The assumptions used in the measurement of KU’s net periodic benefit cost are shown in the following table:

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

To develop the expected long-term rate of return on assets assumption, KU considered the current level of expected returns on risk free investments (primarily government bonds), the historical level of the risk premium associated with the other asset classes in which the portfolio is invested and the expectations for future returns of each asset class.  The expected return for each asset class was then weighted based on the target asset allocation to develop the expected long-term rate of return on assets assumption for the portfolio.

Assumed Healthcare Cost Trend Rates.  For measurement purposes, a 12.0% annual increase in the per capita cost of covered healthcare benefits was assumed for 2004.  The rate was assumed to decrease gradually to 5.0% by 2015 and remain at that level thereafter.

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

(in thousands)	1% Decrease			1% Increase
Effect on total of service and interest cost components for 2003	$	(463	)	$	527
Effect on year-end 2003 postretirement benefit obligations	$	(7,041	)	$	8,000

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Plan Assets.  The following table shows KU’s weighted-average asset allocation by asset category at December 31:

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

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

The fund focuses on a long-term investment time horizon of at least three to five years or a complete market cycle.  The assets of the pension plans are broadly diversified within different asset classes (equities, fixed income securities and cash equivalents).

To minimize the risk of large losses in a single asset class, no more than 5% of the portfolio will be invested in the securities of any one issuer with the exclusion of the U.S. government and its agencies.  The equity portion of the fund is diversified among the market’s various subsections to diversify risk, maximize returns and avoid undue exposure to any single economic sector, industry group or individual security.  The equity subsectors include, but are not limited to growth, value, small capitalization and international.

In addition, the overall fixed income portfolio holdings have a maximum average weighted maturity of no more than fifteen (15) years, with the weighted average duration of the portfolio being no more than eight (8) years.  All securities must be rated “investment grade” or better and foreign bonds in the aggregate shall not exceed 10% of the total fund.  The cash investments should be in securities that either are of short maturities (not to exceed 180 days) or readily marketable with modest risk.

Derivative securities are permitted only to improve the portfolio’s risk/return profile or to reduce transaction costs and must be used in conjunction with underlying physical assets in the portfolio. Derivative securities that involve speculation, leverage, interest rate anticipation, or any undue risk whatsoever are not deemed appropriate investments.

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

Contributions.  KU made a discretionary contribution to the pension plan of $43.4 million in January 2004.  No further discretionary contributions are planned and no contributions are required for 2004.

Thrift Savings Plans.  KU has a thrift savings plan under section 401(k) of the Internal Revenue Code.  Under the

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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 $1.9 million for 2003, $1.5 million for 2002 and $1.4 million for 2001.

Note 7 - Income Taxes

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

(in thousands)		2003			2002			2001
Included in operating expenses:
Current	- federal	$	31,079		$	38,524		$	58,337
	- state	11,456			10,494			13,465
Deferred	- federal – net	11,198			3,467			(12,980		)
	- state – net	923			1,547			(1,340		)
Total		54,656			54,032			57,482
Included in other income - net:
Current	- federal	(1,961		)	(685		)	(948		)
	- state	(134		)	(195		)	(268		)
Deferred	- federal – net	180			15			863
	- state – net	(19		)	(88		)	222
Amortization of investment tax credit		(2,641		)	(2,955		)	(3,446		)
Total		(4,575		)	(3,908		)	(3,577		)
Total income tax expense		$	50,081		$	50,124		$	53,905

Components of net deferred tax liabilities included in the balance sheet are shown below:

(in thousands)	2003			2002
Deferred tax liabilities:
Depreciation and other plant-related items	$	282,376		$	271,792
Other liabilities	27,499			30,378
	309,875			302,170
Deferred tax assets:
Investment tax credit	2,365			3,431
Income taxes due to customers	9,710			11,609
Pensions	(4,702		)	15,861
Accrued liabilities not currently deductible and other	41,244			30,085
	48,617			60,986
Net deferred income tax liability	$	261,258		$	241,184

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

	2003		2002		2001
Statutory federal income tax rate	35.0	%	35.0	%	35.0	%
State income taxes, net of federal benefit	5.8		5.5		5.4
Amortization of investment tax credit	(1.9	)	(2.4	)	(2.3	)
Other differences – net	(3.5	)	(3.2	)	(2.2	)
Effective income tax rate	35.4	%	34.9	%	35.9	%

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Other differences include tax benefits related to prior year audit settlements (1.0%), excess deferred taxes (1.8%), and various other permanent differences (0.7%).

Note 8 - Other Income - - Net

Other income – net consisted of the following at December 31:

(in thousands)	2003		2002			2001
Equity in earnings - subsidiary company	$	3,644	$	6,967		$	1,803
Interest and dividend income	682		580			1,072
Investment tax credit	2,641		2,955			3,446
Income and other taxes	1,907		943			121
Other	215		(1,077		)	2,194
	$	9,089	$	10,368		$	8,636

Note 9 - Long-Term Debt

Refer to the Consolidated Statements of Capitalization for detailed information for KU’s long-term debt.

Long-term debt and the current portion of long-term debt consists primarily of first mortgage bonds, pollution control bonds, and long-term loans from affiliated companies as summarized below (in thousands of $).  Interest rates and maturities in the table below are for the amounts outstanding at December 31, 2003 and reflects the impact of interest rate swaps.

	Stated Interest Rates		Weighted Average Interest Rate		Maturities	Principal Amounts
Noncurrent portion	Variable – 7.92	%	3.10	%	2006-2032	$	595,646
Current portion	Variable		1.34	%	2024-2032	$	91,930

Under the provisions for KU’s variable-rate pollution control bonds Series 10, 12, 13, 14, and 15, 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 in the Consolidated Balance Sheets.  The average annualized interest rate for these bonds during 2003 was 1.07%.

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, 2003, KU has swaps with a combined notional value of $153 million.  The swaps effectively convert fixed rate obligations on KU’s first mortgage bonds Series P and R and pollution control bonds Series 9 to variable-rate obligations.  See Note 4.

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

In May 2002, KU issued $37.9 million variable-rate pollution control bonds Series 12, 13, 14, and 15 due February 1, 2032, and exercised its call option on $37.9 million, 6.25% pollution control bonds Series 1B, 2B, 3B, and 4B due February 1, 2018.

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

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

Substantially all of KU’s utility plant is pledged as security for its first mortgage bonds.

During 2003, KU entered into four long-term loans from an affiliated company totaling $283 million (see Note 1).  Of this total, $100 million is unsecured with an interest rate of 4.55% and matures in April 2013.  The remaining $183 million (which is made up of $75 million at 5.31% due August 2013, $33 million at 4.24% due November 2010 and $75 million at 2.29% due December 2005) is secured by a lien subordinated to the first mortgage bond lien.  The second lien applies to substantially all utility assets of KU.

The following table reflects the long-term debt maturities:

(in thousands)	2004			2005		2006		2007		2008		Thereafter		Total
First mortgage bonds	$	—		$	—	$	36,000	$	53,000	$	—	$	50,000	$	139,000
Pollution control bonds	91,930		(1)	—		—		—		—		158,900		250,830
Notes payable to Fidelia	—			75,000		—		—		—		208,000		283,000
Long-term debt marked to market	—			—		—		8,162		—		6,584		14,746
	$	91,930		$	75,000	$	36,000	$	61,162	$	—	$	423,484	$	687,576

(1)Includes $91,930 of bonds with put provisions that allow the holders to sell bonds back to KU at a specific price before maturity.

In January 2004, KU entered into one additional unsecured long-term loan from an affiliated company totaling $50 million with an interest rate of 4.39% that matures in January 2012.  The proceeds were used to repay amounts due under the accounts receivable securitization program.

In February 2004, KU terminated the swap it had in place at December 31, 2003 related to the Series 9 pollution control bonds.  The notional amount of the terminated swap was $50 million and KU received a payment of $2.0 million as part of the termination. The swap was terminated because it was no longer an effective hedge of the underlying bond.

Note 10 - Notes Payable and Other Short-Term Obligations

KU participates in an intercompany money pool agreement wherein LG&E Energy and LG&E make funds available to KU at market-based rates (based on an index of highly rated commercial paper issues as of the prior month end) up to $400 million.  Likewise, LG&E Energy and KU make funds available to LG&E at market-based rates upto $400 million.  The balance of the money pool loan from LG&E Energy (shown as “Notes payable to affiliated company”) was $43.2 million at an average rate of 1.00% and $119.5 million at an average rate of 1.61% at December 31, 2003 and 2002, respectively.  The amount available to KU under the money pool agreement at December 31, 2003 was $356.8 million. LG&E Energy maintains a revolving credit facility totaling $150 million with an affiliate to ensure funding availability for the money pool.  The outstanding balance under LG&E Energy’s facility as of December 31, 2003 was $111.1 million, and availability of $38.9 million remained.

Note 11 - Commitments and Contingencies

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

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

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

(b)Includes long-term debt of $91.9 million classified as a current liability because 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.  Maturity dates for the bonds range from 2024 to 2032.

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

(d)Represents construction commitments.

(e)KU does not expect to pay the $91.9 million of long-term debt classified as a current liability in the Consolidated Balance Sheets in 2004 as explained in (b) above.  KU anticipates cash from operations and external financing will be sufficient to fund future obligations.  KU anticipates refinancing a portion of its short-term debt with long-term debt in 2004.

Operating Leases.  KU leases office space, office equipment, and vehicles.  KU accounts for these leases as operating leases.  In addition, KU reimburses LG&E for a portion of the lease expense paid by LG&E for KU’s usage of office space leased by LG&E.  Total lease expense for 2003, 2002, and 2001, was $2.2 million, $3.1 million, and $3.5 million, respectively.

KU is a participant in a sale and leaseback transaction involving its 62% interest in two jointly-owned CTs at KU’s E.W. Brown generating station (Units 6 and 7).  Commencing in December 1999, LG&E and KU entered into a tax-efficient, 18-year lease of the CTs. LG&E and KU have provided funds to fully defease the lease, and have executed an irrevocable notice to exercise an early purchase option contained in the lease after 15.5 years. The financial statement treatment of this transaction is no different than if KU had retained its ownership.  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.  The leasing transaction was entered into following receipt of required state and federal regulatory approvals.

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

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

Purchased Power.  KU has purchase power arrangements with OMU, EEI, and OVEC.  Under the OMU agreement, which expires on January 1, 2020, KU purchases all of the output of a 400-Mw (approximate) coal-fired generating station not required by OMU.  The amount of purchased power available to KU during 2004-2008, which is expected to be approximately 8% of KU’s total kWh native load energy requirements, is dependent upon a number of factors including the OMU 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

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agreement.  Included in the total costs is KU’s proportionate share of debt service requirements on $210.9 million of OMU bonds outstanding at December 31, 2003.  The debt service is allocated to KU based on its annual allocated share of capacity, which averaged approximately 47% in 2003.  KU does not guarantee the OMU bonds, or any requirements therein, in the event of default by OMU.

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 follow delivered kWh.

KU has an investment of 2.5% ownership in OVEC’s common stock, which is accounted for under the cost method of accounting.  KU’s entitlement is 2.5% of OVEC’s generation capacity or approximately 55 Mw.

The estimated future minimum annual demand payments under purchased power agreements for the five years subsequent to December 31, 2003, are as follows:

(in thousands)
2004	$	37,433
2005	37,481
2006	38,938
2007	38,882
2008	40,851
Thereafter	686,420
Total	$	880,005

Construction Program.  KU had approximately $11.5 million of commitments in connection with its construction program at December 31, 2003.  Construction expenditures for the years 2004 and 2005 are estimated to total approximately $312.0 million; although all of this is not currently committed, including the construction of four jointly owned CTs, $23.2 million, and construction of NOx equipment, $58.9 million.

Environmental Matters.  KU is subject to SO₂ and NOx emission limits on its electric generating units pursuant to the Clean Air Act.  KU met its Phase I SO₂ requirements primarily through installation of FGD equipment 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 will include fuel switching or the installation of additional FGDs as necessary.  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 SIP, which was approved by EPA June 24, 2003, requires 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.

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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 $230 million to reduce its NOx emissions to the 0.15 lb./Mmbtu level on a company-wide basis.  As of December 31, 2003, KU has incurred $172 million of these capital costs related to the reduction of its NOx emissions.  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 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 EPA’s revised air quality standards for ozone and particulate matter, measures to implement EPA’s regional haze rule and EPA’s December 2003 proposals to regulate mercury emissions from steam electric generating units and to further reduce emissions of sulfur dioxide and nitrogen oxides under the Interstate Air Quality Rule.

KU owns or formerly owned several properties that were used for company or company-predecessor operations, including MGP’s, power production facilities and substations. While KU completed a cleanup of one such site in 1995, evaluations of these types of properties generally have not identified issues of significance.  With regard to these properties, KU is unaware of any imminent exposure or liability.

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.  KU commenced immediate spill containment and recovery measures which continued under the oversight of EPA and state officials and 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 has settled all outstanding issues for this incident with the Commonwealth of Kentucky.  KU incurred costs of approximately $1.8 million and received insurance reimbursement of $1.2 million.  In December 2002, the Department of Justice (DOJ) sent correspondence to KU regarding a potential per-day fine for failure to timely submit a facility response plan and a per-gallon fine for the amount of oil discharged.  KU and the DOJ have commenced settlement discussions using existing DOJ settlement guidelines on this matter.

In April 2002, the EPA sent correspondence to KU regarding potential exposure in connection with $1.5 million in completed remediation costs associated with a transformer scrap-yard.  KU believes it is one of the more remote among a number of potentially responsible parties and has entered into settlement discussions with the EPA on this matter.

Note 12 – Jointly Owned Electric Utility Plant

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

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

See also Note 11, Construction Program, for KU’s planned expenditures for construction of four jointly owned CTs in 2004.

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Note 13 - Related Party Transactions

KU, subsidiaries of LG&E Energy and other subsidiaries of E.ON engage in related party transactions.  Transactions between KU and its subsidiary KU R are eliminated upon consolidation with KU.  Transactions between KU and LG&E Energy subsidiaries are eliminated upon consolidation of LG&E Energy. Transactions between KU and E.ON subsidiaries are eliminated upon consolidation of E.ON. These transactions are generally performed at cost and are in accordance with the SEC regulations under the PUHCA and the applicable Kentucky Commission and Virginia Commission regulations.  Amounts payable to and receivable from related parties are netted and presented as accounts payable to affiliated companies on the balance sheet of KU, as allowed due to the right of offset. Obligations related to intercompany debt arrangements with LG&E Energy and Fidelia, an E.ON subsidiary, are presented as separate line items on the balance sheet, as appropriate. The significant related party transactions are disclosed below.

Electric Purchases

KU and LG&E purchase energy from each other in order to effectively manage the load of their retail and off-system customers.  In addition, KU and LG&E Energy Marketing Inc. (“LEM”), a subsidiary of LG&E Energy, purchase energy from each other. These sales and purchases are included in the Consolidated Statements of Income as Electric Operating Revenues and Purchased Power Operating Expense.  KU intercompany electric revenues and purchased power expense for the years ended December 31, 2003, 2002, and 2001 were as follows:

(in thousands)	2003		2002		2001
Electric operating revenues from LG&E	$	46,690	$	33,249	$	31,133
Electric operating revenues from LEM	2,408		3,581		5,444
Purchased power from LG&E	53,747		41,480		28,521
Purchased power from LEM	—		913		—

Interest Charges

KU participates in an intercompany money pool agreement wherein LG&E Energy and LG&E make funds available to KU at market-based rates (based on an index of highly rated commercial paper issues as of the prior month end) up to $400 million.  Likewise, LG&E Energy and KU make funds available to LG&E at market-based rates up to $400 million.  The balance of the money pool loan from LG&E Energy (shown as “Notes payable to parent”) was $43.2 million at an average rate of 1.00% and $119.5 million at an average rate of 1.61% at December 31, 2003 and 2002, respectively.  The amount available to KU under the money pool agreement at December 31, 2003 was $356.8 million. LG&E Energy maintains a revolving credit facility totaling $150 million with an affiliate to ensure funding availability for the money pool.  The outstanding balance under LG&E Energy’s facility as of December 31, 2003 was $111.1 million, and availability of $38.9 million remained.

In addition, in 2003 KU began borrowing long-term funds from Fidelia Corporation, an affiliate of E.ON (see Note 9).  Fidelia Corporation has a second lien on the property subject to the first mortgage bond lien.  The second lien secures $183 million of the loans provided by Fidelia.

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

KU intercompany interest income and expense for the years ended December 31, 2003, 2002, and 2001 were as follows:

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(in thousands)	2003		2002		2001
Interest on money pool loans	$	1,204	$	1,071	$	974
Interest on Fidelia loans	4,729		—		—
Interest expense paid to LG&E	7		5		—
Interest income received from LG&E	8		61		296

Other Intercompany Billings

LG&E Services provides KU with a variety of centralized administrative, management, and support services in accordance with agreements approved by the SEC under PUHCA. These charges include taxes paid by LG&E Energy on behalf of KU, labor and burdens of LG&E Services employees performing services for KU, and vouchers paid by LG&E Services on behalf of KU.  The cost of these services are directly charged to KU, or for general costs which cannot be directly attributed, charged based on predetermined allocation factors, including the following ratios: number of customers, total assets, revenues, number of employees, and other statistical information.  These costs are charged on an actual cost basis.

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

Intercompany billings to and from KU for the years ended December 31, 2003, 2002, and 2001 were as follows:

(in thousands)	2003		2002		2001
LG&E Services billings to KU	$	187,320	$	176,254	$	201,513
KU billings to LG&E	31,850		36,404		87,992
LG&E billings to KU	23,436		29,659		31,314
KU billings to LG&E Services	14,199		18,573		11,726

Note 14 - Selected Quarterly Data (Unaudited)

Selected financial data for the four quarters of 2003 and 2002 are shown below.  Because of seasonal fluctuations in temperature and other factors, results for quarters may fluctuate throughout the year.

	Quarters Ended
(in thousands)	March		June		September		December
2003
Operating revenues	$	224,983	$	197,174	$	235,426	$	234,195
Net operating income	14,660		19,155		32,776		40,963
Net income	11,861		14,159		30,310		35,072
2002
Operating revenues	$	209,023	$	196,020	$	235,059	$	221,562
Net operating income	28,200		20,047		31,028		29,368
Net income	24,357		12,752		31,085		25,190

As the result of EITF No. 02-03, KU has netted the power purchased expense for trading activities against electric operating revenue.  KU applied this guidance to all prior periods beginning with the June 2003 10-Q filing, which had no impact on previously reported net income or common equity (see Note 1).

138

(in thousands)	Quarter Ended March
2003
Gross operating revenues	$	234,147
Less costs reclassified from power purchased	9,164
Net operating revenues reported	$	224,983
2002
Gross operating revenues	$	215,168
Less costs reclassified from power purchased	6,145
Net operating revenues reported	$	209,023

Note 15 – Subsequent Events

KU made a contribution to the pension plan of $43.4 million in January 2004 (see Note 6).

KU terminated the accounts receivable securitization program in January 2004 (see Note 4).

In January 2004, KU entered into an unsecured long-term loan with an affiliated company totaling $50 million with an interest rate of 4.39% that matures in January 2012.  The proceeds were used to repay amounts due under the accounts receivable securitization program (see Note 9).

In February 2004, KU terminated the swap it had in place at December 31, 2003 related to the Series 9 pollution control bonds.  The notional amount of the terminated swap was $50 million and KU received a payment of $2.0 million as part of the termination. The swap was terminated because it was no longer an effective hedge of the underlying bond (see Notes 4 and 9).

139

Kentucky Utilities Company and Subsidiary

REPORT OF MANAGEMENT

The management of Kentucky Utilities Company and Subsidiary 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 2003, 2002 and 2001 financial statements have been audited by PricewaterhouseCoopers LLP, independent auditors.  Management made available to PricewaterhouseCoopers LLP 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 and external auditors.  These recommendations for the year ended December 31, 2003, did not identify any material weaknesses in the design and operation of KU’s internal control structure.

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

Kentucky Utilities Company and Subsidiary maintains and internally communicates a written code of business conduct and a senior financial officer code of ethics which address, 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

Chief Financial Officer

Kentucky Utilities Company and Subsidiary

Louisville, Kentucky

140

Kentucky Utilities Company and Subsidiary

REPORT OF INDEPENDENT AUDITORS

To the Shareholders of Kentucky Utilities Company and Subsidiary:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of capitalization, income, retained earnings, cash flows and comprehensive income present fairly, in all material respects, the financial position of Kentucky Utilities Company and Subsidiary (the “Company”) at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America.  In addition, in our opinion, based on our audits, the financial statement schedule as of and for the year ended December 31, 2003 listed in the index appearing under Item 15(a)(2), presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidatedfinancial statements.  These financial statements and financial statement schedules are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits.  We conducted our audits 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 audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the consolidated financial statements, effective January 1, 2003,  Kentucky Utilities Company and Subsidiary adopted EITF No. 02-03, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.  As discussed in Note 1 to the consolidated financial statements, effective January 1, 2003, Kentucky Utilities Company and Subsidiary adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Louisville, Kentucky

February 5, 2004

141

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

Not applicable.

ITEM 9A.  Controls and Procedures

Disclosure Controls

LG&E and KU maintain a system of disclosure controls and procedures designed to ensure that information required to be disclosed by the companies in reports they file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission rules and forms.  LG&E and KU conducted an evaluation of such controls and procedures under the supervision and with the participation of the companies’ Management, including the Chairman, President and Chief Executive Officer (“CEO”) and the Chief Financial Officer (“CFO”). Based upon that evaluation, the CEO and CFO are of the conclusion that the companies’ disclosure controls and procedures are effective as of the end of the period covered by this report.  There has been no change in LG&E’s and KU’s internal controls over financial reporting that occurred during the fiscal quarter ended December 31, 2003 that has materially affected, or is reasonably likely to materially affect, LG&E’s and KU’s internal control over financial reporting.

PART III

ITEM 10. Directors and Executive Officers of LG&E and KU.

Information regarding directors who are standing for reelection is set forth in Exhibit 99.02 filed herewith, which information is incorporated herein by reference.  Information regarding executive officers of LG&E and KU has been included in Part I of this Form 10-K.

Audit Committee Independence and Financial Expert

As wholly-owned subsidiaries of a common parent, LG&E and KU each have a three-person board of directors. Due to the small size of this board, the board as a whole performs the functions associated with audit committees.  The Boards of Directors of LG&E and KU have determined that each of Victor A. Staffieri and S. Bradford Rives is an audit committee financial expert as defined by Item 401(h) of Regulation S-K.  All of the members of the boards of LG&E and KU are officers or employees of the companies, or their ultimate parent, E.ON AG, and therefore are not independent within the meaning of Item 7(d)(3)(iv) of Schedule 14A of the Exchange Act.  Nevertheless, LG&E and KU believe the structure and composition of their boards of directors and the qualifications and attributes of their members to be fully able and competent to perform their duties in the areas associated with audit committees.

Code of Ethics

LG&E and KU have adopted a code of ethics for senior financial officers (including principal executive officer, principal financial officer principal accounting officer and controller or other employees performing similar functions). The Senior Financial Officer Code of Ethics is available on their corporate website at http://www.lgeenergy.com.  LG&E and KU intend to satisfy the disclosure requirement under Item 10 of Form 8-K regarding an amendment to, or waiver from, a provision of the Code of Ethics by posting such information on our website at the location specified above.

142

Section 16(a) Beneficial Ownership Reporting Compliance

Information regarding Section 16(a) beneficial ownership reporting compliance is included in Exhibit 99.02 filed herewith, which information is incorporated herein by reference.

ITEM 11. Executive Compensation.

Information regarding compensation of named executive officers and of directors is set forth in Exhibit 99.02 filed herewith, which information is incorporated herein by reference.

ITEM 12. Security Ownership of Certain Beneficial Owners and Management.

Information regarding security ownership of certain beneficial owners, directors and executive officers is set forth in Exhibit 99.02 filed herewith, which information is incorporated herein by reference.

Information regarding equity compensation plans, including non-stockholder approved plans, is set forth in Exhibit 99.02 filed herewith, which information is incorporated herein by reference.

ITEM 13. Certain Relationships and Related Transactions.

Information regarding certain relationships and related transactions, if applicable, is set forth in Exhibit 99.02 filed herewith, which information is incorporated herein by reference.

ITEM 14. Principal Accountant Fees and Services.

Information regarding principal accountant fees and services is set forth in Exhibit 99.02 filed herewith, information is incorporated herein by reference.

PART IV

ITEM 15.  Exhibits, Financial Statement Schedules, and Reports on Form 8-K.

(a)1.Financial Statements (included in Item 8):

Report of Independent Auditors.

143

Reports of Independent Auditors.

2.Financial Statement Schedules (included in Part IV):

Schedule II Valuation and Qualifying Accounts for the three years ended December 31, 2003, for LG&E, and KU.

All other schedules have been omitted as not applicable or not required or because the information required to be shown is included in the Financial Statements or the accompanying Notes to Financial Statements.

3.Exhibits:

Exhibit No.	Applicable to Form 10-K of
	LG&E	KU	Description
2.01	X	X	Copy of Agreement and Plan of Merger, dated as of February 27, 2000, by and among Powergen plc, LG&E Energy Corp., US Subholdco2 and Merger Sub, including certain exhibits thereto.  [Filed as Exhibit 1 to LG&E’s and KU’s Current Report on Form 8-K filed February 29, 2000 and incorporated by reference herein]
2.02	X	X	Amendment No. 1 to Agreement and Plan of Merger, dated as of December 8, 2000, among LG&E Energy Corp., Powergen plc, Powergen US Investments Corp. and Powergen Acquisition Corp. [Filed as Exhibit 2.01 to LG&E’s and KU’s Current Report on Form 8-K filed December 11, 2000 and incorporated by reference herein]
2.03	X	X	Copy of Agreement and Plan of Merger, dated as of May 20, 1997, by and between LG&E Energy and KU Energy, including certain exhibits thereto.  [Filed as Exhibit 2 to LG&E’s and KU’s Current Report on Form 8-K filed May 30, 1997 and incorporated by reference herein]
3.01	X		Copy of Restated Articles of Incorporation of LG&E, dated November 6, 1996. [Filed as Exhibit 3.06 to LG&E Quarterly Report on Form 10-Q for the quarter ended September 30, 1996, and incorporated by reference herein]
3.02	X		Copy of Amendment to Articles of Incorporation of LG&E, dated February 6, 2004.

144

Exhibit No.	Applicable to Form 10-K of
	LG&E	KU	Description
3.03	X		Copy of By-Laws of LG&E, as amended through December 16, 2003.
3.04		X	Copy of Amended and Restated Articles of Incorporation of KU [Filed as Exhibits 4.03 and 4.04 to Form 8-K Current Report of KU, dated December 10, 1993, and incorporated by reference herein]
3.05		X	Copy of Amendment to Articles of Incorporation of KU, dated February 6, 2004.
3.06		X	Copy of By-Laws of KU, as amended through December 16, 2003.
4.01	X		Copy of Trust Indenture dated November 1, 1949, from LG&E to Harris Trust and Savings Bank, Trustee.  [Filed as Exhibit 7.01 to LG&E’s Registration Statement 2-8283 and incorporated by reference herein]
4.02	X		Copy of Supplemental Indenture dated September 1, 1992, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.32 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein]
4.03	X		Copy of Supplemental Indenture dated September 2, 1992, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.33 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein]
4.04	X		Copy of Supplemental Indenture dated August 15, 1993, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.34 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
4.05	X		Copy of Supplemental Indenture dated August 16, 1993, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.35 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
4.06	X		Copy of Supplemental Indenture dated October 15, 1993, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.36 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
4.07	X		Copy of Supplemental Indenture dated May 1, 2000, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.37 to LG&E’s Annual Report on Form 10-K/A for the year ended December 31, 2000, and incorporated by reference herein]

145

Exhibit No.	Applicable to Form 10-K of
	LG&E	KU	Description
4.08	X		Copy of Supplemental Indenture dated August 1, 2000, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.38 to LG&E’s Annual Report on Form 10-K/A for the year ended December 31, 2000, and incorporated by reference herein]
4.09	X		Copy of Supplemental Indenture dated March 1, 2002, which is a supplemental instrument to Exhibit 4.01 hereto.  (Filed as Exhibit 4.39 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated by reference herein.)
4.10	X		Copy of Supplemental Indenture dated March 15, 2002, which is a supplemental instrument to Exhibit 4.01 hereto.  (Filed as Exhibit 4.40 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated by reference herein.)
4.11	X		Copy of Supplemental Indenture dated October 1, 2002, which is a supplemental instrument to Exhibit 4.01 hereto.  (Filed as Exhibit 4.41 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated by reference herein.)
4.12		X	Indenture of Mortgage or Deed of Trust dated May 1, 1947, between KU and First Trust National Association (successor Trustee) and a successor individual co-trustee, as Trustees (the Trustees) (Amended Exhibit 7(a) in File No. 2-7061), and Supplemental Indentures thereto dated, respectively, January 1, 1949 (Second Amended Exhibit 7.02 in File No. 2-7802), July 1, 1950 (Amended Exhibit 7.02 in File No. 2-8499), June 15, 1951 (Exhibit 7.02(a) in File No. 2-8499), June 1, 1952 (Amended Exhibit 4.02 in File No. 2-9658), April 1, 1953 (Amended Exhibit 4.02 in File No. 2-10120), April 1, 1955 (Amended Exhibit 4.02 in File No. 2-11476), April 1, 1956 (Amended Exhibit 2.02 in File No. 2-12322), May 1, 1969 (Amended Exhibit 2.02 in File No. 2-32602), April 1, 1970 (Amended Exhibit 2.02 in File No. 2-36410), September 1, 1971 (Amended Exhibit 2.02 in File No. 2-41467), December 1, 1972 (Amended Exhibit 2.02 in File No. 2-46161), April 1, 1974 (Amended Exhibit 2.02 in File No. 2-50344), September 1, 1974 (Exhibit 2.04 in File No. 2-59328), July 1, 1975 (Exhibit 2.05 in File No. 2-59328), May 15, 1976 (Amended Exhibit 2.02 in File No. 2-56126), April 15, 1977 (Exhibit 2.06 in File No. 2-59328), August 1, 1979 (Exhibit 2.04 in File No. 2-64969), May 1, 1980 (Exhibit 2 to Form 10-Q Quarterly Report of KU for the quarter ended June 30, 1980), September 15, 1982 (Exhibit 4.04 in File No. 2-79891), August 1, 1984 (Exhibit 4B to Form 10-K Annual Report of KU for the year ended December 31, 1984), June 1, 1985 (Exhibit 4 to Form 10-Q Quarterly Report of KU for the quarter ended June 30, 1985), May 1, 1990 (Exhibit 4 to Form 10-Q Quarterly Report of KU for the quarter ended June 30, 1990), May 1, 1991 (Exhibit 4 to Form 10-Q Quarterly Report of KU for the quarter ended June 30, 1991), May 15, 1992 (Exhibit 4.02 to Form 8-K of KU dated May 14, 1992), August 1, 1992 (Exhibit 4 to Form 10-Q Quarterly Report of KU for the quarter ended September 30, 1992), June 15, 1993 (Exhibit 4.02 to Form 8-K of KU dated June 15, 1993) and December 1, 1993 (Exhibit 4.01 to Form 8-K of KU dated December 10, 1993), November 1, 1994

146

Exhibit No.	Applicable to Form 10-K of
	LG&E	KU	Description
			(Exhibit 4.C to Form 10-K Annual Report of KU for the year ended December 31, 1994), June 1, 1995 (Exhibit 4 to Form 10-Q Quarterly Report of KU for the quarter ended June 30, 1995) and January 15, 1996 [Filed as Exhibit 4.E to Form 10-K Annual Report of KU for the year ended December 31, 1995, and incorporated by reference herein]
4.13		X	Copy of Supplemental Indenture dated March 1, 1992 between KU and the Trustees, providing for the conveyance of properties formerly held by Old Dominion Power Company  [Filed as Exhibit 4B to Form 10-K Annual Report of KU for the year ended December 31, 1992, and incorporated by reference herein]
4.14		X	Copy of Supplemental Indenture dated May 1, 2000, which is a supplemental instrument to Exhibit 4.12 hereto.  [Filed as Exhibit 4.41 to KU’s Annual Report on Form 10-K for the year ended December 31, 2000, and incorporated by reference herein]
4.15		X	Copy of Supplemental Indenture dated September 1, 2001, which is a supplemental instrument to Exhibit 4.12 hereto. [Filed as Exhibit 4.42 to KU’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
4.16		X	Receivables Purchase Agreement dated as of February 6, 2001 among KU Receivables LLC, Kentucky Utilities Company as Servicer, the Various Purchaser Groups From Time to Time Party Hereto and PNC Bank, National Association, as Administrator. [Filed as Exhibit 4.43 to KU’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
4.17		X	Purchase and Sale Agreement dated as of February 6, 2001 between KU Receivables LLC and Kentucky Utilities Company. [Filed as Exhibit 4.44 to KU’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
4.18	X		Receivables Purchase Agreement dated as of February 6, 2001 among LG&E Receivables LLC, Louisville Gas and Electric Company as Servicer, the Various Purchaser Groups From Time to Time Party Hereto and PNC Bank, National Association, as Administrator. [Filed as Exhibit 4.45 to KU’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]

147

Exhibit No.	Applicable to Form 10-K of
	LG&E	KU	Description
4.19		X	Purchase and Sale Agreement dated as of February 6, 2001 between LG&E Receivables LLC and Louisville Gas and Electric Company. [Filed as Exhibit 4.46 to KU’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
4.20		X	Copy of Supplemental Indenture dated May 1, 2002, which is a supplemental instrument to Exhibit 4.12 hereto.  (Filed as Exhibit 4.50 to KU's Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated by reference herein.)
4.21		X	Copy of Supplemental Indenture dated September 1, 2002, which is a supplemental instrument to Exhibit 4.12 hereto.  (Filed as Exhibit 4.51 to KU's Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated by reference herein.)
4.22	X		Copy of Supplemental Indenture dated October 1, 2003, which is a supplemental instrument to Exhibit 4.01 hereto.
4.23		X	Copy of Loan Agreement between KU and Fidelia Corporation, dated April 30, 2003.
4.24	X		Copy of Loan Agreement between LG&E and Fidelia Corporation, dated April 30, 2003.
4.25		X	Copy of Loan Agreement between KU and Fidelia Corporation, dated January 15, 2004.
4.26		X	Copy of Loan and Security Agreement between KU and Fidelia Corporation, dated as of August 15, 2003.
4.27	X		Copy of Loan and Security Agreement between LG&E and Fidelia Corporation, dated as of August 15, 2003.
10.01	X	X	Copies of (i) Inter-Company Power Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies (which Agreement includes as Exhibit A the Power Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation); (ii) First Supplementary Transmission Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies; (iii) Inter-Company Bond Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies; (iv) Inter-Company Bank Credit Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies.  [Filed as Exhibit 5.02f to LG&E’s Registration Statement 2-61607 and incorporated by reference herein]

148

Exhibit No.	Applicable to Form 10-K of
	LG&E	KU	Description
10.02	X	X	Copy of Modification No. 1 and No. 2 dated June 3, 1966 and January 7, 1967, respectively, to Inter-Company Power Agreement dated July 10, 1953.  [Filed as Exhibits 4(a)(8) and 4(a)(10) to LG&E’s Registration Statement 2-26063 and incorporated by reference herein]
10.03	X	X	Copies of Amendments to Agreements (iii) and (iv) referred to under 10.06 above as follows:  (i) Amendment to Inter-Company Bond Agreement and (ii) Amendment to Inter-Company Bank Credit Agreement.  [Filed as Exhibit 5.02h to LG&E’s Registration Statement 2-61607 and incorporated by reference herein]
10.04	X	X	Copy of Modification No. 1, dated August 20, 1958, to First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies.  [Filed as Exhibit 5.02i to LG&E’s Registration Statement 2-61607 and incorporated by reference herein]
10.05	X	X	Copy of Modification No. 2, dated April 1, 1965, to the First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies.  [Filed as Exhibit 5.02j to LG&E’s Registration Statement 2-61607 and incorporated by reference herein]
10.06	X	X	Copy of Modification No. 3, dated January 20, 1967, to First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies.  [Filed as Exhibit 4(a)(7) to LG&E’s Registration Statement 2-26063 and incorporated by reference herein]
10.07	X	X	Copy of Modification No. 3 dated November 15, 1967, to the Inter-Company Power Agreement dated July 10, 1953.  [Filed as Exhibit 4.02m to LG&E’s Registration Statement 2-37368 and incorporated by reference herein]
10.08	X	X	Copy of Modification No. 4 dated November 5, 1975, to the Inter-Company Power Agreement dated July 10, 1953.  [Filed as Exhibit 5.02o to LG&E’s Registration Statement 2-56357 and incorporated by reference herein]
10.09	X	X	Copy of Modification No. 4 dated April 30, 1976, to First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies.  [Filed as Exhibit 5.02p to LG&E’s Registration Statement 2-61607 and incorporated by reference herein]

149

Exhibit No.	Applicable to Form 10-K of
	LG&E	KU	Description
10.10	X	X	Copy of Modification No. 5 dated September 1, 1979, to Inter-Company Power Agreement dated July 5, 1953, among Ohio Valley Electric Corporation and Sponsoring Companies.  [Filed as Exhibit 4 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1979, and incorporated by reference herein]
10.11	X	X	Copy of Modification No. 6 dated August 1, 1981, to Inter-Company Power Agreement dated July 5, 1953, among Ohio Valley Electric Corporation and Sponsoring Companies.  [Filed as Exhibit 10.26 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1981, and incorporated by reference herein]
10.12	X		Copy of Non-Qualified Savings Plan covering officers of the Company, effective January 1, 1992.  [Filed as Exhibit 10.43 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein]
10.13	X	X	Copy of Modification No. 7 dated January 15, 1992, to Inter-Company Power Agreement dated July 10, 1953, among Ohio Valley Electric Corporation and Sponsoring Companies.  [Filed as Exhibit 10.44 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
10.14	X		Copies of Firm No-Notice Transportation Agreements each effective November 1, 1993, between Texas Gas Transmission Corporation and LG&E (expiring October 31, 2000, 2001 and 2003)  covering the transmission of natural gas.  [All filed as Exhibit 10.47 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
10.15	X	X	Copy of Modification No. 8 dated January 19, 1994, to Inter-Company Power Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies.  [Filed as Exhibit 10.43 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.16	X		Copy of Amendment dated March 1, 1995, to Firm No-Notice Transportation Agreements dated November 1, 1993 (2-Year, 5-Year and 8-Year), between Texas Gas Transmission Corporation and LG&E covering the transmission of natural gas.  [Filed as Exhibit 10.44 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]

150

Exhibit No.	Applicable to Form 10-K of
	LG&E	KU	Description
10.17	X	X	Copy of Modification No. 9, dated August 17, 1995, to the Inter-Company Power Agreement dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies.  [Filed as Exhibit 10.39 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1996, and incorporated by reference herein]
10.18	X		Copies of Firm Transportation Agreements, each dated March 1, 1995, between Texas Gas Transmission Corporation and LG&E (expiring October 31, 2001 and 2003) covering the transportation of natural gas.  [Both filed as Exhibit 10.45 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.19	X		Copy of Firm Transportation Agreement, dated March 1, 1995, between Texas Gas Transmission Corporation and LG&E (expires October 31, 2000) covering the transportation of natural gas. [Filed as Exhibit 10.41 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1996, and incorporated by reference herein]
10.20	X	X	*  Copy of Amendment to the Non-Qualified Savings Plan, effective January 1, 1992.  [Filed as Exhibit 10.55 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.21	X	X	*  Copy of Amendment to the Non-Qualified Savings Plan, effective January 1, 1995.  [Filed as Exhibit 10.56 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.22	X	X	*  Copy of Amendment to the Non-Qualified Savings Plan, effective January 1, 1995.  [Filed as Exhibit 10.57 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.23	X	X	*  Copy of Supplemental Executive Retirement Plan as amended through January 1, 1998, covering officers of LG&E Energy.  [Filed as Exhibit 10.74 to LG&E Energy’s Annual Report on Form 10-K for the year ended December 31, 1997, and incorporated by reference herein]
10.24	X		Copy of Coal Supply Agreement between LG&E and Kindill Mining, Inc., dated July 1, 1997.  [Filed as Exhibit 10.76 to LG&E Energy’s Annual Report on Form 10-K for the year ended December 31, 1997, and incorporated by reference herein]

151

Exhibit No.	Applicable to Form 10-K of
	LG&E	KU	Description
10.25	X		Copies of Amendments dated September 23, 1997, to Firm No-Notice Transportation Agreements dated November 1, 1993, between Texas Gas Transmission Corporation and LG&E, as amended.  [Filed as Exhibit 10.81 to LG&E Energy’s Annual Report on Form 10-K for the year ended December 31, 1997, and incorporated by reference herein]
10.26	X		Copies of Amendments dated September 23, 1997, to Firm Transportation Agreements dated March 1, 1995, between Texas Gas Transmission Corporation and LG&E, as amended.  [Filed as Exhibit 10.82 to LG&E Energy’s Annual Report on Form 10-K for the year ended December 31, 1997, and incorporated by reference herein]
10.27	X	X	Copy of Coal Supply Agreement between LG&E and KU and Black Beauty Coal Company, dated as of January 1, 2002, covering the purchase of coal.  [Filed as Exhibit 10.51 to LG&E’s and KU’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
10.28	X	X	Copy of Coal Supply Agreement between LG&E and KU and McElroy Coal Company, Consolidation Coal Company, Consol Pennsylvania Coal Company, Greenon Coal Company, Nineveh Coal Company, Eighty Four Mining Company and Island Creek Coal Company, dated as of January 1, 2000, and Amendment No. 1 dated as of January 1, 2002, for the purchase of coal. [Filed as Exhibit 10.52 to LG&E’s and KU’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
10.29		X	Copy of Coal Supply Agreement between KU and Arch Coal Sales Company, Inc., as agent for the independent operating subsidiaries of Arch Coal, Inc., dated as of July 22, 2001, for the purchase of coal. [Filed as Exhibit 10.53 to KU’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
10.30	X		Copy of Coal Supply Agreement between LG&E and Hopkins County Coal, LLC and Alliance Coal Sales, a division of Alliance Coal, LLC, dated as of January 1, 2002, for the purchase of coal. [Filed as Exhibit 10.54 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
10.31	X		Copy of Amendment dated November 6, 2000, to Firm Transportation Agreement between LG&E and Texas Gas Transmission Corporation covering the transmission of natural gas (expires October 31, 2006). [Filed as Exhibit 10.57 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]

152

Exhibit No.	Applicable to Form 10-K of
	LG&E	KU	Description
10.32	X		Copy of Amendment dated November 6, 2000, to Firm Transportation Agreement between LG&E and Texas Gas Transmission Corporation covering the transmission of natural gas (expires October 31, 2008). [Filed as Exhibit 10.58 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
10.33	X		Copy of Amendment dated November 6, 2000, to Firm No-Notice Transportation Agreement between LG&E and Texas Gas Transmission Corporation covering the transmission of natural gas (expires October 31, 2006). [Filed as Exhibit 10.59 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
10.34	X		Copy of Amendment dated September 15, 1999, to Firm Transportation Agreement between LG&E and Texas Gas Transmission Corporation covering the transmission of natural gas (expires October 31, 2005). [Filed as Exhibit 10.60 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
10.35	X	X	*  Copy of Amendment to LG&E Energy’s Supplemental Executive Retirement Plan, effective September 2, 1998. [Filed as Exhibit 10.90 to LG&E Energy’s Annual Report on Form 10-K for the year ended December 31, 1998 and incorporated by reference herein]
10.36	X	X	* Copy of Employment and Severance Agreement, dated as of February 25, 2000, by and among LG&E Energy, Powergen plc and an executive officer of the Company.  (Filed as Exhibit 10.54 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated by reference herein.)
10.37	X	X	* Copy of Amendment, effective October 1, 1999, to LG&E Energy’s Non-Qualified Savings Plan. [Filed as Exhibit 10.96 to LG&E’s and KU’s Annual Report on Form 10-K for the year ended December 31, 1999, and incorporated by reference herein]
10.38	X	X	* Copy of Amendment, effective December 1, 1999, to LG&E Energy’s Non-Qualified Savings Plan. [Filed as Exhibit 10.97 to LG&E’s and KU’s Annual Report on Form 10-K for the year ended December 31, 1999, and incorporated by reference herein]
10.39	X	X	Copy of Modification No. 10, dated January 1, 1998, to the Inter-Company Power Agreement dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 10.102 to LG&E’s and KU’s Annual Report on Form 10-K for the year ended December 31, 1999, and incorporated by reference herein]

153

Exhibit No.	Applicable to Form 10-K of
	LG&E	KU	Description
10.40	X	X	Copy of Modification No. 11, dated April 1, 1999, to the Inter-Company Power Agreement dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 10.103 to LG&E’s and KU’s Annual Report on Form 10-K for the year ended December 31, 1999, and incorporated by reference herein]
10.41	X		Copy of Letter Amendment, dated September 15, 1999, to Firm No-Notice Transportation Agreement, dated November 1, 1993, between LG&E and Texas Gas Transmission Corporation. [Filed as Exhibit 10.106 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1999, and incorporated by reference herein]
10.42	X	X	* Copy of Powergen Short-Term Incentive Plan, effective January 1, 2001, applicable to certain employees of LG&E Energy Corp. and its subsidiaries. [Filed as Exhibit 10.109 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2000, and incorporated herein by reference]
10.43	X	X	* Copy of two forms of Change-In-Control Agreement applicable to certain employees of LG&E Energy Corp. and its subsidiaries. [Filed as Exhibit 10.110 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2000, and incorporated by reference herein]
10.44	X	X	* Copy of Employment and Severance Agreement, dated as of February 25, 2000, and amendments thereto dated December 8, 2000 and April 30, 2001, by and among LG&E Energy, Powergen plc and Victor A. Staffieri. [Filed as Exhibit 10.74 to LG&E’s and KU’s Annual Report on Form 10-K/A for the year ended December 31, 2001, and incorporated by reference herein]
10.45	X	X	* Copy of Amendment, dated as of December 8, 2000, to Employment and Severance Agreement dated as of February 25, 2000, by and among LG&E Energy, Powergen plc and an executive officer of the Company. [Filed as Exhibit 10.63 to LG&E’s and KU’s Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated by reference herein]
10.46	X		Copy of Amendment dated June 5, 2002, to Firm No-Notice Transportation Agreement dated November 1, 1993, between LG&E and Texas Gas Transmission Corporation covering the transmission of natural gas (expires October 31, 2008). [Filed as Exhibit 10.64 to LG&E’s and KU’s Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated by reference herein]

154

Exhibit No.	Applicable to Form 10-K of
	LG&E	KU	Description
10.47	X		Copy of Firm Transportation Service Agreement dated November 1, 2002, between LG&E and Tennessee Gas Pipeline Company covering the transmission of natural gas (expires October 31, 2012).  [Filed as Exhibit 10.65 to LG&E’s and KU’s Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated by reference herein]
10.48	X		Copy of Amendment No. 1 dated January 1, 2001, to Coal Supply Agreement dated July 1, 1997, between LG&E and Kindill Mining, Inc.  [Filed as Exhibit 10.66 to LG&E’s and KU’s Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated by reference herein]
10.49	X		Copy of Amendment No. 2 dated January 1, 2002, to Coal Supply Agreement dated July 1, 1997, between LG&E and Kindill Mining, Inc.  [Filed as Exhibit 10.67 to LG&E’s and KU’s Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated by reference herein]
10.50	X	X	Copy of Amendment No. 2 dated January 1, 2003, to Coal Supply Agreement dated January 1, 2000, between LG&E and KU and McElroy Coal Company, Consolidation Coal Company, Consol Pennsylvania Coal Company, Greenon Coal Company, Nineveh Coal Company, Eighty Four Mining Company and Island Creek Coal Company.  [Filed as Exhibit 10.68 to LG&E’s and KU’s Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated by reference herein]
10.51	X		Copy of Coal Supply Agreement dated January 1, 2003, between LG&E and Peabody Coalsales Company.  [Filed as Exhibit 10.69 to LG&E’s and KU’s Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated by reference herein]
10.52	X		Copy of Coal Supply Agreement dated January 1, 2002, between LG&E and Peabody Coalsales Company.  [Filed as Exhibit 10.70 to LG&E’s and KU’s Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated by reference herein]
10.53	X		Copy of Amendment No. 1 dated June 1, 2002, to Coal Supply Agreement dated January 1, 2002, between LG&E and Peabody Coalsales Company. [Filed as Exhibit 10.71 to LG&E’s and KU’s Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated by reference herein]
10.54	X		Copy of  Amendment No. 2 dated January 1, 2003, to Coal Supply Agreement dated January 1, 2002, between LG&E and Peabody Coalsales Company.  [Filed as Exhibit 10.72 to LG&E’s and KU’s Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated by reference herein]

155

Exhibit No.	Applicable to Form 10-K of
	LG&E	KU	Description
10.55		X	Copy of Coal Supply Agreement dated January 1, 2002, between KU and Massey Coal Sales Company, Inc.  [Filed as Exhibit 10.73 to LG&E’s and KU’s Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated by reference herein]
10.56	X	X	*Copy of Third Amendment, dated July 1, 2002, to Employment and Severance Agreement dated as of February 25, 2000 by and among E.ON AG, LG&E Energy, Powergen and Victor A. Staffieri.  [Filed as Exhibit 10.74 to LG&E’s and KU’s Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated by reference herein]
10.57	X	X	*Copy of form of Retention and Severance Agreement dated April/May, 2002 by and among LG&E Energy, E.ON AG and certain executive officers of the Companies.  [Filed as Exhibit 10.75 to LG&E’s and KU’s Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated by reference herein]
10.58	X	X	*Copy of Second Amendment, dated May 20, 2002, to Employment and Severance Agreement, dated February 25, 2000, by and among E.ON AG, LG&E Energy Corp., Powergen plc and an executive of the Companies.  [Filed as Exhibit 10.76 to LG&E’s and KU’s Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated by reference herein]
10.59	X	X	*Copy of Terms and Conditions for Stock Options Issued as part of E.ON Group’s Stock Option Programs, applicable to certain executive officers of the Companies.  [Filed as Exhibit 10.79 to LG&E’s and KU’s Annual Report on Form 10-K for the year ended December 31, 2002, and incorporated by reference herein]
10.60	X	X	Copy of Amendment No. 1 dated as of January 1, 2004, to Coal Supply Agreement dated as of January 1, 2002, between LG&E, KU and Black Beauty Coal Company
10.61		X	Copy of Amendment No. 1 dated as of July 1, 2003, to Coal Supply Agreement dated as of January 1, 2002, between KU and Arch Coal Sales Company, Inc.
10.62	X		Copy of Amendment No. 1 dated as of January 1, 2000, to Amended and Restated Coal Supply Agreement dated as of April 1, 1998, between LG&E and Hopkins County Coal, LLC and Webster County Coal, LLC as successor to Webster County Coal Corporation.

156

Exhibit No.	Applicable to Form 10-K of
	LG&E	KU	Description
10.63	X		Copy of Amendment No. 2 dated as of September 15, 2000, to Amended and Restated Coal Supply Agreement dated as of April 1, 1998, as amended by Amendment No. 1 dated January 1, 2000 between LG&E and Hopkins County Coal, LLC and Webster County Coal, LLC, as successor to Webster County Coal Corporation.
10.64	X		Copy of Amendment No. 3 dated as of September 15, 2003,  to Coal Supply Agreement dated as of January 1, 2002, as amended by Amendment No. 1 dated effective June 1, 2002, and Amendment No. 2 dated effective January 1, 2003, between LG&E and Peabody Coalsales Company.
10.65	X	X	*Copy of LG&E Energy Corp. Long-Term Performance Unit Plan, adopted April 25, 2003, effective January 1, 2003.
10.66			[NOT USED]
10.67			[NOT USED]
10.68			[NOT USED]
10.69	X	X	Copy of Modification No. 12 dated as of November 1, 1999, to Inter-Company Power Agreement dated July 10, 1953 among Ohio Valley Electric Corporation and Sponsoring Companies.
10.70	X	X	Copy of Modification No. 13 dated as of May 24, 2000, to Inter-Company Power Agreement dated July 10, 1953 among Ohio Valley Electric Corporation and Sponsoring Companies.
10.71	X	X	Copy of Modification No. 14 dated as of April 1, 2001, to Inter-Company Power Agreement dated July 10, 1953 among Ohio Valley Electric Corporation and Sponsoring Companies.
12	X	X	Computation of Ratio of Earnings to Fixed Charges for LG&E and KU.
21	X	X	Subsidiaries of the Registrants.
24	X	X	Powers of Attorney.
31.1	X		Certification of Chief Executive Officer, Pursuant to Section 302 of Sarbanes-Oxley Act of 2002.

157

Exhibit No.	Applicable to Form 10-K of
	LG&E	KU	Description
31.2	X		Certification of Chief Financial Officer, Pursuant to Section 302 of Sarbanes-Oxley Act of 2002.
31.3		X	Certification of Chief Executive Officer, Pursuant to Section 302 of Sarbanes-Oxley Act of 2002.
31.4		X	Certification of Chief Financial Officer, Pursuant to Section 302 of Sarbanes-Oxley Act of 2002.
32	X	X	Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	X	X	Cautionary Statement for purposes of the “Safe Harbor” provisions of the Private Securities Litigation Reform Act of 1995.
99.02	X	X	LG&E and KU Director and Officer Information.

(b)Reports on Form 8-K:

On November 13, 2003, LG&E and KU filed a Current Report on Form 8-K to present reclassified financial statements and other financial information in accordance with the requirements of Emerging Issues Task Force Issue No. 02-03.

On November 25, 2003 and December 30, 2003, LG&E and KU filed Current Reports describing their intention and submission, respectively, of requests to the Kentucky Public Service Commission for increases in electric and gas base rates, as applicable.

(c)Executive Compensation Plans and Arrangements:

Exhibits preceded by an asterisk (“*”) above are management contracts, compensation plans or arrangements required to be filed as an exhibit pursuant to Item 15(c) of Form 10-K.

(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

158

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.

159

Schedule II

Louisville Gas and Electric Company

Schedule II - Valuation and Qualifying Accounts

For the Three Years Ended December 31, 2003

(Thousands of $)

	Other Property and Investments		Accounts Receivable (Uncollectible Accounts)
Balance December 31, 2000	$	63	$	1,286
Additions:
Charged to costs and expenses	—		4,953
Deductions:
Net charges of nature for which reserves were created	—		4,664
Balance December 31, 2001	63		1,575
Additions:
Charged to costs and expenses	—		4,459
Deductions:
Net charges of nature for which reserves were created	—		3,909
Balance December 31, 2002	63		2,125
Additions:
Charged to costs and expenses	—		5,477
Deductions:
Net charges of nature for which reserves were created	—		4,087
Balance December 31, 2003	$	63	$	3,515

160

Schedule II

Kentucky Utilities Company

Schedule II - Valuation and Qualifying Accounts

For the Three Years Ended December 31, 2003

(Thousands of $)

	Other Property and Investments		Accounts Receivable (Uncollectible Accounts)
Balance December 31, 2000	$	751	$	800
Additions:
Charged to costs and expenses	9		1,528
Deductions:
Net charges of nature for which reserves were created	630		1,528
Balance December 31, 2001	130		800
Additions:
Charged to costs and expenses	—		1,314
Deductions:
Net charges of nature for which reserves were created	—		1,314
Balance December 31, 2002	130		800
Additions:
Charged to costs and expenses	—		1,492
Deductions:
Net charges of nature for which reserves were created	—		1,620
Balance December 31, 2003	$	130	$	672

161

SIGNATURES – LOUISVILLE GAS AND ELECTRIC COMPANY

Pursuant to the requirements of Section 13 or 15(d) of 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
March 29, 2004	/s/ S. Bradford Rives
(Date)	S. Bradford Rives
	Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of 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);
S. Bradford Rives	Director and Chief Financial Officer
	(Principal Financial Officer and Principal Accounting Officer);
John R. McCall	Director and Executive Vice President,
	General Counsel and Corporate Secretary

By	/s/ S. Bradford Rives	March 29, 2004
	(Attorney-In-Fact)

162

SIGNATURES – KENTUCKY UTILITIES COMPANY

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

	KENTUCKY UTILITIES COMPANY
	Registrant
March 29, 2004	/s/ S. Bradford Rives
(Date)	S. Bradford Rives
	Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of 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);
S. Bradford Rives	Director and Chief Financial Officer
	(Principal Financial Officer and Principal Accounting Officer);
John R. McCall	Director and Executive Vice President,
	General Counsel and Corporate Secretary

By	/s/ S. Bradford Rives	March 29, 2004
	(Attorney-In-Fact)

163

EX-3.02

EXHIBIT 3.02

ARTICLES OF AMENDMENT

TO

ARTICLES OF INCORPORATION

OF

LOUISVILLE GAS AND ELECTRIC COMPANY

Pursuant to the provisions of KRS 271B.10-030 and KRS 271B.10-060, the following Articles of Amendment to the Articles of Incorporation of Louisville Gas and Electric Company, a Kentucky corporation (the “Corporation”), are hereby adopted:

FIRST:           The name of the Corporation is Louisville Gas and Electric Company.

SECOND:      The text of the amendment to Article Ninth of the Corporation’s Articles of Incorporation is as follows:

“NINTH:  All corporate powers shall be exercised by or under the authority of, and the business and affairs of the Company managed under the direction of, its Board of Directors.  The number of directors shall be fixed by resolution of the Board of Directors from time to time.

The Board of Directors of the Company, to the extent not prohibited by law, shall have the power to cause the Company to repurchase its own shares and shall have the power to make distributions from time to time to the corporation’s shareholders.”

THIRD:          The above designated amendments do not provide for an exchange, reclassification or cancellation of issued shares of stock of the Corporation.

FOURTH:      The designated amendments were adopted by the Corporation’s Board of Directors on March 21, 2003, and submitted for approval by the Corporation’s shareholders.  The Corporation has 21,294,223 outstanding shares of common stock, without par value and 860,287 outstanding shares of Preferred Stock, par value $25 per share, 5% Series, which are entitled to vote on the amendment.  One hundred percent of the common shares and at least 99.9 percent of the voting

Preferred Stock were indisputably represented at a shareholders’ meeting held December 16, 2003, duly called in accordance with the Kentucky Business Corporation Act, with 21,294,223 of the common shares and 65,098 Preferred Shares indisputably cast in favor of the amendment, such votes being sufficient for approval of the amendment.

DATED:	February 6, 2004
		Louisville Gas and Electric Company
		BY:
			John R. McCall
			Executive Vice President,
			General Counsel and
			Corporate Secretary

EX-3.03

EXHIBIT 3.03

BY-LAWS

OF

LOUISVILLE GAS AND ELECTRIC COMPANY

By-Laws Adopted November 7, 1956

As Amended Through April 22, 1998

As Amended Through June 2, 1999

As Amended Through November 3, 2003

As Amended Through December 16, 2003

ARTICLE I

MEETINGS OF STOCKHOLDERS

Section 1.  The Annual Meeting of the stockholders of the Company shall be held at a location in or out of Kentucky at a time and date to be fixed by the Board of Directors each year.  Notice of the annual meeting shall be mailed to each stockholder entitled to notice at least ten (10) days before the Annual Meeting.

Section 2.  Except as otherwise mandated by Kentucky law and except as otherwise provided in or fixed by or pursuant to the provisions of Article Fourth of the Company’s Amended Articles of Incorporation relating to the rights of the holders of any class or series of stock having a preference over the Company’s Common Stock as to dividends or upon liquidation to elect directors under specified circumstances, special meetings of stockholders may be called only by the President of the Company or by the Board of Directors pursuant to a resolution approved by a majority of the entire Board of Directors.  For purposes of these By-Laws, the phrase “Company’s Amended Articles of Incorporation” shall mean the Amended Articles of Incorporation of Louisville Gas and Electric Company as in effect on February 1, 1987, and as thereafter amended from time to time.

Section 3.  A stockholder may vote in person or by proxy, filed with the Secretary of the Company before or immediately upon the convening of the meeting.

Section 4.  Any action required or permitted to be taken by the stockholders of the Company at a meeting of such holders may be taken without such a meeting only if a consent in writing setting forth the action so taken shall be signed by all of the stockholders entitled to vote with respect to the subject matter thereof.

Section 5.  At an annual meeting of the stockholders, only such business shall be conducted as shall have been properly brought before the meeting.  To be properly brought before an annual meeting, business must be (a) specified in the notice of meeting (or any supplement thereto) given by or at the direction of the Board of Directors, (b) otherwise properly brought before the meeting by or at the direction of the Board of Directors, or (c) otherwise properly be requested to be brought before the meeting by a stockholder.  For business to be

properly requested to be brought before an annual meeting by a stockholder, the stockholder must have given timely notice thereof in writing to the Secretary of the Company.  To be timely, a stockholder’s notice must be delivered to or mailed and received at the principal executive offices of the Company, not less than 90 days prior to the meeting; provided, however, that in the event that the date of the meeting is not publicly announced by the Company by mail, press release or otherwise more than 100 days prior to the meeting, notice by the stockholder to be timely must be delivered to the Secretary of the Company not later than the close of business on the tenth day following the day on which such announcement of the date of the meeting was communicated to stockholders.  A stockholder’s notice to the Secretary shall set forth as to each matter the stockholder proposes to bring before the annual meeting (a) a brief description of the business desired to be brought before the annual meeting and the reasons for conducting such business at the annual meeting, (b) the name and address, as they appear on the Company’s books, of the stockholder proposing such business, (c) the class and number of shares of the Company which are beneficially owned by the stockholder, and (d) any material interest of the stockholder in such business.  Notwithstanding anything in the By-Laws to the contrary, no business shall be conducted at an annual meeting except in accordance with the procedures set forth in this Section 5. The Chairman of an annual meeting shall, if the facts warrant, determine and declare to the meeting that business was not properly brought before the meeting and in accordance with the provisions of this Section 5, and if he should so determine, he shall so declare to the meeting that any such business not properly brought before the meeting shall not be transacted.

ARTICLE II

BOARD OF DIRECTORS

Section 1.   (a) The Board shall be composed of such number of Directors as shall be set by resolution of the Board.  Regular meetings of the Board of Directors shall be held at such time and place as may be fixed by the Board of Directors.  The number of Directors may be changed from time to time by resolution of the Board of Directors or by amendment to these By-laws, but no decrease in the number of Directors shall have the effect of shortening the term of any incumbent Director.  Unless a Director dies, resigns or is removed, he shall hold office until the next annual meeting of the shareholders or until a successor is elected, whichever is later.

(b)           Advance notice of stockholder nominations for the election of directors shall be given in the manner provided in Section 2 of Article IV of these By-Laws.

(c)           Except as otherwise provided in or fixed by or pursuant to the provisions of Article Fourth of the Company’s Amended Articles of Incorporation relating to the rights of the holders of any class or series of stock having a preference over the Company’s Common Stock as to dividends or upon liquidation to elect directors under specified circumstances: (i) newly created directorships resulting from any increase in the number of directors and any vacancies on the Board of Directors resulting from death, resignation, disqualification, removal or other cause shall be filled by the affirmative vote of a majority of the remaining directors then in office, even though less than a quorum of the Board of Directors; (ii) any director elected in accordance with the preceding clause (i) shall hold office until the next annual meeting of the shareholders or until

2

such director’s successor shall have been elected and qualified, whichever is later; and (iii) no decrease in the number of directors constituting the Board of Directors shall shorten the term of any incumbent director.

(d)   Except as otherwise provided in or fixed by or pursuant to the provisions of Article Fourth of the Company’s Amended Articles of Incorporation relating to the rights of the holders of any class or series of stock having a preference over the Company’s Common Stock as to dividends or upon liquidation to elect directors under specified circumstances, any director may be removed from office, with or without cause, only by the affirmative vote of the holders of at least 80% of the combined voting power of the then outstanding shares of the Company’s stock entitled to vote generally (as defined in Article Eighth of the Company’s Amended Articles of Incorporation), voting together as a single class.  Notwithstanding the foregoing provisions of this Paragraph (d), if at any time any stockholders of the Company have cumulative voting rights with respect to the election of directors and less than the entire Board of Directors is to be removed, no director may be removed from office if the votes cast against his removal would be sufficient to elect him as a director if then cumulatively voted at an election of the class of directors of which he is a part.

Section 2.  Regular Meetings shall be held at such time and place as may be fixed by the Board of Directors.

Section 3.  Special Meetings of the Board of Directors shall be held at the call of the Chairman or of the President, or, in their absence, of a Vice President, or at the request in writing of not less than three (3) members of the Board.

Section 4.  Regular and Special Meetings may be held outside of the State of Kentucky.

Section 5.  Notices of Regular and Special Meetings shall be sent to each director at least one (1) day prior to the meeting.

Section 6.  The business and affairs of the Company shall be managed by or under the direction of the Board of Directors, except as may be otherwise provided by law or by the Company’s Amended Articles of Incorporation.  Unless otherwise provided by law, at each meeting of the Board of Directors, the presence of one-third of the fixed number of directors  shall constitute a quorum for the transaction of business.  Except as provided in Section l(c) of this Article II, the vote of a majority of the directors present at a meeting at which a quorum is present shall be the act of the Board of Directors.  In case at any meeting of the Board of Directors a quorum shall not be present, the members of the Board of Directors present may by majority vote adjourn the meeting from time to time until a quorum shall attend.

Section 7.  Directors may receive such fees or compensation for their services as may be authorized by resolution of the Board of Directors.  In addition, expenses of attendance, if any, may be allowed for attendance at each regular or special meeting.

Section 8.  The Board of Directors, by resolution adopted by a majority of the full Board of Directors, may designate from among its members an executive committee and one or more

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other committees each of which, to the extent provided in such resolution, shall have and exercise all the authority of the Board of Directors, but no such committee shall have the authority to take action that under Kentucky law can only be taken by a board of directors.

Section  9.  The Chairman of the Board, if such person is present, shall serve as Chairman at each regular or special meeting of the Board of Directors and shall determine the order of business at such meeting.  If the Chairman of the Board is not present at a regular or special meeting of the Board of Directors, the Vice Chairman of the Board shall serve as Chairman of such meeting and shall determine the order of business of such meeting.  The Board of Directors may elect one of its members as Vice Chairman of the Board.

ARTICLE III

OFFICERS

Section 1.  The officers of the Company shall be a Chief Executive Officer, President, Chief Financial Officer, one or more Vice Presidents, Secretary, Treasurer, Controller and such other officers (including, if so directed by a resolution of the Board of Directors, Chairman of the Board) as the Board may from time to time elect or appoint.  Any two of the offices may be combined in one person, but no officer shall execute, acknowledge, or verify any instrument in more than one capacity.  Officers are to be elected by the Board of Directors of the Company at the first meeting of the Board following the annual meeting of stockholders and, unless otherwise specified by the Board of Directors, shall be elected to hold office for one year or until their successors are elected and qualified.  Any vacancy shall be filled by the Board of Directors, provided that the Chief Executive Officer may fill such a vacancy until the Board of Directors shall elect a successor.  Except as provided below, officers shall perform those duties usually incident to the office or as otherwise required by the Board of Directors, the Chief Executive Officer, or the officer to whom they report.  An officer may be removed with or without cause and at any time by the Board of Directors or by the Chief Executive Officer.

Chief Executive Officer

Section 2.  The Chief Executive Officer of the Company shall have full charge of all of the affairs of the Company, shall preside at all meetings of the stockholders and, in the absence of the Chairman of the Board, at meetings of the Board of Directors.

President

Section 3.  The President shall exercise the functions of the Chief Executive Officer during the absence or disability of the Chief Executive Officer.

Chief Financial Officer

Section 4.  The Chief Financial Officer of the Company shall have full charge of all of the financial affairs of the Company, including maintaining accurate books and records, meeting all reporting requirements and controlling Company funds.

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Vice Presidents

Section 5.  The Vice President or Vice Presidents may be designated as Vice President, Senior Vice President or Executive Vice President, as the Board of Directors or Chief Executive Officer may determine.

Secretary

Section 6.  The Secretary shall be present at and record the proceedings of all meetings of the Board of Directors and of the stockholders, give notices of meetings of Directors and stockholders, have custody of the seal of the Company and affix it to any instrument requiring the same, and shall have the power to sign certificates for shares of stock of the Company.

Treasurer

Section 7.  The Treasurer shall have charge of all receipts and disbursements of the Company and be custodian of the Company’s funds.

Controller

Section 8.  The Controller shall have charge of the accounting records of the Company.

Chairman of the Board

Section 9.  In the event the Board of Directors elects a Chairman of the Board and designates by resolution that the Chairman of the Board shall be an officer of the corporation, the Chairman of the Board shall preside at all meetings of the Board of Directors and serve the corporation in an advisory capacity.

ARTICLE IV

CAPITAL STOCK CERTIFICATES

AND DIRECTOR NOMINATIONS

Section 1.  The Board of Directors shall approve all stock certificates as to form.  The certificates for the various classes of stock, issued by the Company, shall be printed or engraved with the facsimile signatures of the President and Secretary and a facsimile seal of the Company.  The Board of Directors shall appoint transfer agents to issue and transfer certificates of stock, and registrars to register said certificates.

Section 2.  Except as otherwise provided in or fixed by or pursuant to the provisions of Article Fourth of the Company’s Amended Articles of Incorporation relating to the rights of the holders of any class or series of stock having a preference over the Company’s Common Stock as to dividends or upon liquidation to elect directors under specified circumstances, nominations for the election of directors may be made by the Board of Directors or a committee appointed by the Board of Directors or by any stockholder entitled to vote in the election of directors generally.

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However, any stockholder entitled to vote in the election of directors generally may nominate one or more persons for election as director or directors at a stockholders’ meeting only if written notice of such stockholder’s intent to make such nomination or nominations has been given either by personal delivery or by United States mail, postage prepaid, to the Secretary of the Company not later than 90 days in advance of such meeting; provided, however, that in the event the date of the meeting is not publicly announced by the Company by mail, press release or otherwise more than 100 days prior to the meeting, notice by the stockholder to be timely must be delivered not later than the close of business on the tenth day following the date on which notice of such meeting was first communicated to stockholders.  Each such notice shall set forth (a) the name and address of the stockholder who intends to make the nomination and of the person or persons to be nominated; (b) a representation that the stockholder is a holder of record of stock of the Company entitled to vote at such meeting and intends to appear in person or by proxy at the meeting to nominate the person or persons specified in the notice; (c) a description of all arrangements or understandings between the stockholder and each nominee and any other person or persons (naming such person or persons) pursuant to which the nomination or nominations are to be made by the stockholder; (d) such other information regarding each nominee proposed by such stockholder as would be required to be included in a proxy statement filed pursuant to the proxy rules of the Securities and Exchange Commission, had the nominee been nominated, or intended to be nominated, by the Board of Directors; and (e) the consent of each nominee to serve as a director of the Company if so elected.  The Chairman of the meeting may refuse to acknowledge the nomination of any person not made in compliance with the foregoing procedure.

ARTICLE V

LOST STOCK CERTIFICATES

The Board of Directors may, in its discretion, direct that a new certificate or certificates of stock be issued in place of any certificate or certificates of stock theretofore issued by the Company, alleged to have been stolen, lost or destroyed, and the Board of Directors when authorizing the issuance of such new certificate or certificates may, in its discretion, and as a condition precedent thereto, require the owner of such stolen, lost or destroyed certificate or certificates or the legal representatives of such owner, to give to the Company, its transfer agent or agents, its registrar or registrars, as may be authorized or required to sign and countersign such new certificate or certificates, a corporate surety bond in such sum as it may direct as indemnity against any claim or claims that may be made against the Company, its transfer agent or agents, its registrar or registrars, for or in respect to the shares of stock represented by the certificate or certificates alleged to have been stolen, lost or destroyed.

ARTICLE VI.

DIVIDENDS ON PREFERRED STOCK

Dividends upon the 5% Cumulative Preferred Stock, $25 Par value, if declared, shall be payable on January 15, April 15, July 15 and October 15 of each year.  If the date herein

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designated for the payment of any dividend shall, in any year, fall upon a legal holiday, then the dividend payable on such date shall be paid on the next day not a legal holiday.

Dividends in respect of each share of $8.90 Cumulative Preferred Stock (without par value) of the Company shall be payable on October 16, 1978, when and as declared by the Board of Directors of the Company, to holders of record on September 29, 1978, and shall accrue from the date of original issuance of said series.  Thereafter, such dividends shall be payable on January 15, April 15, July 15, and October 15 in each year (or the next business day thereafter in each case), when and as declared by the Board of Directors of the Company, for the quarter-yearly period ending on the last business day of the preceding month.

Dividends in respect of each share of Preferred Stock, Auction Series A (without par value), of the Company shall be payable when and as declared by the Board of Directors of the Company, on the dates and in the manner set forth in the Amendment to the Articles of Incorporation of the Company setting forth the terms of such series.

Dividends in respect of each share of $5.875 Cumulative Preferred Stock, of the Company shall be payable when and as declared by the Board of Directors of the Company, on the dates and in the manner set forth in the Amendment to the Articles of Incorporation of the Company setting forth the terms of such series.

ARTICLE VII

FINANCE

Section 1.  The Board of Directors shall designate the bank or banks to be used as depositories of the funds of the Company and shall designate the officers and employees of the Company who may sign and countersign checks drawn against the various accounts of the Company.  The Board of Directors may authorize the use of facsimile signatures on checks drawn against certain bank accounts of the Company.

Section 2.  Notes shall be signed by the President and either a Vice President or the Treasurer.  In the absence of the President, notes shall be signed by two Vice Presidents, or a Vice President and the Treasurer.

ARTICLE VIII

SEAL

The seal of this Company shall be in the form of a circular disk, bearing the following information:

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(	Louisville Gas and Electric Company	)
(	Incorporated Under the Laws of	)
(	Kentucky	)
(	Seal	)
(	1913	)

ARTICLE IX

AMENDMENTS

Subject to the provisions of the Company’s Amended Articles of Incorporation, these By-Laws may be amended or repealed at any regular meeting of the stockholders (or at any special meeting thereof duly called for that purpose) by the holders of at least a majority of the voting power of the shares represented and entitled to vote thereon at such meeting at which a quorum is present; provided that in the notice of such special meeting notice of such purpose shall be given.  Subject to the laws of the State of Kentucky, the Company’s Amended Articles of Incorporation and these By-Laws, the Board of Directors may by majority vote of those present at any meeting at which a quorum is present amend these By-Laws, or adopt such other By-Laws as in their judgment may be advisable for the regulation of the conduct of the affairs of the Company.

ARTICLE X

INDEMNIFICATION

Section 1.  Right to Indemnification.  Each person who was or is a director of the Company and who was or is made a party or is threatened to be made a party to or is otherwise involved (including, without limitation, as a witness) in any action, suit or proceeding, whether civil, criminal, administrative or investigative (hereinafter a “proceeding”), by reason of the fact that he or she is or was a director or officer of the Company or is or was serving at the request of the Company as a director, officer, partner, trustee, employee or agent of another corporation or of a partnership, joint venture, trust or other enterprise, including service with respect to an employee benefit plan (hereinafter an “Indemnified Director”), whether the basis of such proceeding is alleged action in an official capacity as a director or officer or in any other capacity while serving as a director or officer, shall be indemnified and held harmless by the Company to the fullest extent permitted by the Kentucky Business Corporation Act, as the same exists or may hereafter be amended, against all expense, liability and loss (including, without limitation, attorneys’ fees, judgments, fines, ERISA excise taxes or penalties and amounts paid in settlement) reasonably incurred or suffered by such Indemnified Director in connection therewith and such indemnification shall continue as to an Indemnified Director who has ceased to be a director or officer and shall inure to the benefit of the Indemnified Director’s heirs, executors and administrators.  Each person who was or is an officer of the Company and not a director of the Company and who was or is made a party or is threatened to be made a party to or is otherwise involved (including, without limitation, as a witness) in any proceeding, by reason of the fact that he or she is or was an officer of the Company or is or was serving at the request of the Company as a director, officer, partner, trustee, employee or agent of another corporation or of a

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partnership, joint venture, trust or other enterprise, including service with respect to an employee benefit plan (hereinafter an “Indemnified Officer”), whether the basis of such proceeding is alleged action in an official capacity as an officer or in any other capacity while serving as an officer, shall be indemnified and held harmless by the Company against all expense, liability and loss (including, without limitation, attorneys’ fees, judgments, fines, ERISA excise taxes or penalties and amounts paid in settlement) reasonably incurred or suffered by such Indemnified Officer to the same extent and under the same conditions that the Company must indemnify an Indemnified Director pursuant to the immediately preceding sentence and to such further extent as is not contrary to public policy and such indemnification shall continue as to an Indemnified Officer who has ceased to be an officer and shall inure to the benefit of the Indemnified Officer’s heirs, executors and administrators.  Notwithstanding the foregoing and except as provided in Section 2 of this Article X with respect to proceedings to enforce rights to indemnification, the Company shall indemnify any Indemnified Director or Indemnified Officer in connection with a proceeding (or part thereof) initiated by such Indemnified Director or Indemnified Officer only if such proceeding (or part thereof) was authorized by the Board of Directors of the Company.  As hereinafter used in this Article X, the term “indemnitee” means any Indemnified Director or Indemnified Officer.  Any person who is or was a director or officer of a subsidiary of the Company shall be deemed to be serving in such capacity at the request of the Company for purposes of this Article X. The right to indemnification conferred in this Article shall include the right to be paid by the Company the expenses incurred in defending any such proceeding in advance of its final disposition (hereinafter an “advancement of expenses”); provided, however, that, if the Kentucky Business Corporation Act requires, an advancement of expenses incurred by an indemnitee who at the time of receiving such advance is a director of the Company shall be made only upon:  (i) delivery to the Company of an undertaking (hereinafter an “undertaking”), by or on behalf of such indemnitee, to repay all amounts so advanced if it shall ultimately be determined by final judicial decision from which there is no further right to appeal (hereinafter, a “final adjudication”) that such indemnitee is not entitled to be indemnified for such expenses under this Article or otherwise; (ii) delivery to the Company of a written affirmation of the indemnitee’s good faith belief that he has met the standard of conduct that makes indemnification by the Company permissible under the Kentucky Business Corporation Act; and (iii) a determination that the facts then known to those making the determination would not preclude indemnification under the Kentucky Business Corporation Act.  The right to indemnification and advancement of expenses incurred in this Section 1 shall be a contract right.

Section 2.  Right of Indemnitee to Bring Suit.  If a claim under Section 1 of this Article X is not paid in full by the Company within sixty days after a written claim has been received by the Company (except in the case of a claim for an advancement of expenses, in which case the applicable period shall be twenty days), the indemnitee may at any time thereafter bring suit against the Company to recover the unpaid amount of the claim.  If successful in whole or in part to any such suit or in a suit brought by the Company to recover an advancement of expenses pursuant to the terms of an undertaking, the indemnitee also shall be entitled to be paid the expense of prosecuting or defending such suit.  In (i) any suit brought by the indemnitee to enforce a right to indemnification hereunder (other than a suit to enforce a right to an advancement of expenses brought by an indemnitee who will not be a director of the Company at the time such advance is made) it shall be a defense that, and in (ii) any suit by the Company to

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recover an advancement of expenses pursuant to the terms of an undertaking the Company shall be entitled to recover such expenses upon a final adjudication that, the indemnitee has not met the standard of conduct that makes it permissible hereunder or under the Kentucky Business Corporation Act (the “applicable standard of conduct”) for the Company to indemnify the indemnitee for the amount claimed.  Neither the failure of the Company (including its Board of Directors, independent legal counsel or its stockholders) to have made a determination prior to the commencement of such suit that indemnification of the indemnitee is proper in the circumstances because the indemnitee has met the applicable standard of conduct, nor an actual determination by the Company (including its Board of Directors, independent legal counsel or its stockholders) that the indemnitee has not met the applicable standard of conduct, shall create a presumption that the indemnitee has not met the applicable standard of conduct or, in the case of such a suit brought by the indemnitee, be a defense to such suit.  In any suit brought by the indemnitee to enforce a right to indemnification or to an advancement of expenses hereunder, or by the Company to recover an advancement of expenses pursuant to the terms of an undertaking, the burden of proving that the indemnitee is not entitled to be indemnified or to such advancement of expenses under this Article X or otherwise shall be on the Company.

Section 3.  Non-Exclusivity of Rights.  The rights to indemnification and to the advancement of expenses conferred in this Article X shall not be exclusive of any other right which any person may have or hereafter acquire under any statute, the Company’s Articles of Incorporation, these By-Laws, any agreement, any vote of stockholders or disinterested directors or otherwise.

Section 4.  Insurance.  The Company may maintain insurance, at its expense, to protect itself and any director, officer, employee or agent of the Company or another corporation, partnership, joint venture, trust or other enterprise against any expense, liability or loss, whether or not the Company would have the power to indemnify such person against such expense, liability or loss under the Kentucky Business Corporation Act.

Section 5.  Indemnification of Employees and Agents.  The Company may, to the extent authorized from time to time by the Board of Directors, grant rights to indemnification and to the advancement of expenses to any employee or agent of the Company and to any person serving at the request of the Company as an agent or employee of another corporation or of a partnership, joint venture, trust or other enterprise to the fullest extent of the provisions of this Article X with respect to the indemnification and advancement of expenses of directors and officers of the Company.

Section 6. Repeal or Modification.  Any repeal or modification of any provision of this Article X shall not adversely affect any rights to indemnification and to advancement of expenses that any person may have at the time of such repeal or modification with respect to any acts or omissions occurring prior to such repeal or modification.

Section 7.  Severability.  In case any one or more of the provisions of this Article X, or any application thereof, shall be invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions of this Article X, and any other application thereof, shall not in any way be affected or impaired thereby.

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BY-LAWS

OF

LOUISVILLE GAS AND ELECTRIC COMPANY

By-Laws Adopted November 7, 1956

As Amended Through April 22, 1998

As Amended Through June 2, 1999

As Amended Through November 3, 2003

As Amended Through December 16, 2003

EX-3.05

EXHIBIT 3.05

ARTICLES OF AMENDMENT

TO

ARTICLES OF INCORPORATION

OF

KENTUCKY UTILITIES COMPANY

Pursuant to the provisions of the Kentucky Revised Statutes and the Virginia Corporation Act, the following Articles of Amendment to the Articles of Incorporation of Kentucky Utilities Company, a Kentucky and Virginia corporation (the “Corporation”), are hereby adopted:

FIRST:              The name of the Corporation is Kentucky Utilities Company.

SECOND:         The text of the amendment to Article Seventh of the Corporation’s Articles of Incorporation is as follows:

“SEVENTH:     All corporate powers shall be exercised by or under the authority of, and the business and affairs of the corporation managed under the direction of, its Board of Directors.  The number of directors shall be fixed by resolution of the Board of Directors from time to time.

The Board of Directors of the corporation, to the extent not prohibited by law, shall have the power to cause the corporation to repurchase its own shares and shall have the power to make distributions from time to time to the corporation’s shareholders.”

THIRD:             The above designated amendments do not provide for an exchange, reclassification or cancellation of issued shares of stock of the Corporation.

FOURTH:         The designated amendments were adopted by the Corporation’s Board of Directors on July 1, 2002, and submitted for approval by the Corporation’s sole shareholder entitled to vote.  The Corporation has 31,817,878 outstanding shares of common stock, without

par value, which are entitled to vote on the amendment.  One hundred percent of the common shares were indisputably represented at a duly called shareholders’ meeting held on December 16, 2003, with 31,817,878 of the common shares indisputably cast in favor of the amendment, such vote being sufficient for approval of the amendment. 

DATED:	February 6, 2004
		Kentucky Utilities Company
		BY:
			John R. McCall
			Executive Vice President,
			General Counsel and Corporate Secretary

EX-3.06

EXHIBIT 3.06

BY-LAWS

OF

KENTUCKY UTILITIES COMPANY

ARTICLE I

STOCK TRANSFERS

Section 1.  Each holder of fully paid stock shall be entitled to a certificate or certificates of stock stating the number and the class of shares owned by such holder, provided that, the Board of Directors may, by resolution, authorize the issue of some or all of the shares of any or all classes or series of stock without certificates.  All certificates of stock shall, at the time of their issuance, be signed by the Chairman of the Board, the President or a Vice-President and by the Secretary or Assistant Secretary, and may be authenticated and registered by a duly appointed registrar.  If the stock certificate is authenticated by a registrar, the signatures of the corporate officers may be facsimiles.  In case any officer designated for the purpose who has signed or whose facsimile signature has been used on any stock certificate shall, from any cause, cease to be such officer before the certificate has been delivered by the Company, the certificate may nevertheless be adopted by the Company and be issued and delivered as though the person had not ceased to be such officer.

Section 2.  Shares of stock shall be transferable only on the books of the Company and upon proper endorsement and surrender of the outstanding certificates representing the same.  If any outstanding certificate of stock shall be lost, destroyed or stolen, the officers of the Company shall have authority to cause a new certificate to be issued to replace such certificate upon the receipt by the Company of satisfactory evidence that such certificate has been lost, destroyed or stolen and of a bond of indemnity deemed sufficient by the officers to protect the Company and any registrar and any transfer agent of the Company against loss which may be sustained by reason of issuing such new certificate to replace the certificate reported lost, destroyed or stolen; and any transfer agent of the Company shall be authorized to issue and deliver such new certificate and any registrar of the Company is authorized to register such new certificate, upon written directions signed by the Chairman of the Board, the President or a Vice-President and by the Treasurer or the Secretary of the Company.

Section 3.  All certificates representing each class of stock shall be numbered and a record of each certificate shall be kept showing the name of the person to whom the certificate was issued with the number and the class of shares and the date thereof.  All certificates exchanged or returned to the Company shall be cancelled and an appropriate record made.

Section 4.  The Board of Directors may fix a date not exceeding seventy days preceding the date of any meeting of shareholders, or the date fixed for the payment of any dividend or distribution, or the date of allotment of rights, or, subject to contract rights with respect thereto,

the date when any change or conversion or exchange of shares shall be made or go into effect, as a record date for the determination of the shareholders entitled to notice of and to vote at any such meeting, or entitled to receive payment of any such dividend, or allotment of rights, or to exercise the rights with respect to any such change, conversion or exchange of shares, and in such case only shareholders of record on the date so fixed shall be entitled to notice of and to vote at such meeting, or to receive payment of such dividend or allotment of rights or to exercise such rights, as the case may be, notwithstanding any transfer of shares on the books of the Company after the record date fixed as aforesaid.  The Board of Directors may close the books of the Company against transfer of shares during the whole or any part of such period.  When a determination of shareholders entitled to notice of and to vote at any meeting of shareholders has been made as provided in this section, such determination shall apply to any adjournment thereof except as otherwise provided by statute.

ARTICLE II

MEETINGS OF STOCKHOLDERS

Section 1.  An Annual Meeting of Stockholders of the Company shall be held at such date and time as shall be designated from time to time by the Board of Directors.  Each such Annual Meeting shall be held at the principal office of the Company in Kentucky or at such other place as the Board of Directors may designate from time to time.

Section 2.  Special meetings of the stockholders may be called by the Board of Directors or by the holders of not less than 51% of all the votes entitled to be cast on each issue proposed to be considered at the special meeting, or in such other manner as may be provided by statute.  Business transacted at special meetings shall be confined to the purposes stated in the notice of meeting.

Section 3.  Notice of the time and place of each annual or special meeting of stockholders shall be sent by mail to the recorded address of each stockholder entitled to vote not less than ten or more than sixty days before the date of the meeting, except in cases where other special method of notice may be required by statute, in which case the statutory method shall be followed.  The notice of special meeting shall state the object of the meeting.  Notice of any meeting of the stockholders may be waived by any stockholder.

Section 4.   At an Annual Meeting of the Stockholders, only such business shall be conducted as shall have been properly brought before the meeting in accordance with the procedures set forth in these By-laws.  To be properly brought before the Annual Meeting, business must be (a) specified in the notice of meeting (or any supplement thereto) given by or at the direction of the Board of Directors, (b) otherwise properly brought before the meeting by or at the direction of the Board of Directors, or (c) otherwise be a proper matter for consideration and otherwise be properly requested to be brought before the meeting by a stockholder as hereinafter provided.  For business to be properly requested to be brought before an Annual Meeting by a stockholder, a stockholder of a class of shares of the Company entitled to vote upon the matter requested to be brought before the meeting (or his designated proxy as provided below) must have given timely and proper notice thereof to the Secretary.  To be timely, a

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stockholder’s notice must be given by personal delivery or mailed by United States mail, postage prepaid, and received by the Secretary not fewer than sixty calendar days prior to the meeting; provided, however, that in the event that the date of the meeting is not publicly announced by mail, press release or otherwise or disclosed in a public report, information statement, or other filing made with the Securities and Exchange Commission, in either case, at least seventy calendar days prior to the meeting, notice by the stockholder to be timely must be received by the Secretary, as provided above, not later than the close of business on the tenth day following the day on which such notice of the date of the meeting or such public disclosure or filing was made.  To be proper, a stockholder’s notice to the Secretary must be in writing and must set forth as to each matter the stockholder proposes to bring before the Annual Meeting (a) a description in reasonable detail of the business desired to be brought before the Annual Meeting and the reasons for conducting such business at the Annual Meeting, (b) the name and address, as they appear on the Company books, of the stockholder proposing such business or granting a proxy to the proponent or an intermediary, (c) a representation that the stockholder is a holder of record of stock of the Company entitled to vote at such meeting and intends to appear in person or by proxy at the meeting to nominate the person or persons specified in the notice, (d) the name and address of the proponent, if the holder of a proxy from a qualified stockholder of record, and the names and addresses of any intermediate proxies, (e) the class and number of shares of the Company which are beneficially owned by the stockholder, and (f) any material interest of the stockholder or the proponent in such business.  The chairman of an Annual Meeting shall determine whether business was properly brought before the meeting, which determination absent manifest error will be conclusive for all purposes.

Section 5.  The Chairman of the Board, if present, and in his absence the President, and the Secretary of the Company, shall act as Chairman and Secretary, respectively, at each stockholders meeting, unless otherwise provided by the Board of Directors prior to the meeting.  Unless otherwise determined by the Board of Directors prior to the meeting, the Chairman of the stockholders’ meeting shall determine the order of business and shall have the authority in his discretion to regulate the conduct of any such meeting, including, without limitation, by imposing restrictions on the persons (other than stockholders of the Company or their duly appointed proxies) who may attend any such stockholders’ meeting, by determining whether any stockholder or his proxy may be excluded from any stockholders’ meeting based upon any determination by the Chairman, in his sole discretion, that any such person has unduly disrupted or is likely to disrupt the proceedings thereat, and by regulating the circumstances in which any person may make a statement or ask questions at any stockholders’ meeting.

Section 6.  The Company shall be entitled to treat the holder of record of any share or shares as the holder in fact thereof and, accordingly, shall not be bound to recognize any equitable or other claim to or interest in such share on the part of any other person whether or not it shall have express or other notice thereof, except as expressly provided by law.

Section 7.  The Board of Directors may postpone and reschedule any previously scheduled annual or special meeting of stockholders and may adjourn any convened meeting of stockholders to another date and time as specified by the chairman of the meeting.

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ARTICLE III

BOARD OF DIRECTORS

Section 1.   The Board shall be composed of such number of Directors as shall be set by resolution of the Board.  The number of Directors may be changed from time to time by resolution of the Board of Directors or by amendment to these By-laws, but no decrease in the number of Directors shall have the effect of shortening the term of any incumbent Director.  Unless a Director dies, resigns or is removed, he shall hold office until the next annual meeting of the shareholders or until a successor is elected, whichever is later.  Directors need not be shareholders of the corporation or residents of the Commonwealth of Kentucky or of the Commonwealth of Virginia.  Except as otherwise expressly provided by the Articles of Incorporation, the Board of Directors may fill, until the first annual election thereafter and until the necessary election shall have taken place, vacancies occurring at any time in the membership of the Board by death, resignation or otherwise.  Written notice of such resignation shall be made as provided by law.

Section 2.  Nominations for the election of directors may be made by the Board of Directors or a committee appointed by the Board of Directors or by any stockholder entitled to vote in the election of directors generally.  However, any stockholder entitled to vote in the election of directors generally may nominate one or more persons for election as directors at a meeting only if the stockholder has given timely and proper notice thereof to the Secretary.  To be timely, a stockholder's notice must be given by personal delivery or mailed by United States mail, postage prepaid, and received by the Secretary not fewer than sixty calendar days or more than ninety calendar days prior to the meeting; provided, however, that in the event that the date of the meeting is not publicly announced by mail, press release or otherwise or disclosed in a public report, information statement or other filing made with the Securities and Exchange Commission, in either case, at least seventy calendar days prior to the meeting, notice by the stockholder to be timely must be so received by the Secretary, as provided above, not later than the close of business on the tenth day following the day on which such notice of the date of the meeting or such public disclosure or filing was made.  To be proper, a stockholder’s notice of nomination to the Secretary must be in writing and must set forth as to each nominee:  (a) the name and address, as they appear on the Company books, of the stockholder who intends to make the nomination or granting a proxy to the proponent or an intermediary; (b) the name and address of the person or persons to be nominated; (c) a representation that the stockholder is a holder of record of stock of the Company entitled to vote at such meeting and intends to appear in person or by proxy at the meeting to nominate the person or persons specified in the notice; (d) a description of all arrangements or understandings between the stockholder and each nominee and any other person or persons (naming such person or persons) pursuant to which the nomination or nominations are to be made by the stockholder; (e) such other information regarding each nominee proposed by such stockholder as would be required to be included in a proxy statement filed pursuant to the proxy rules of the Securities and Exchange Commission, had the nominee been nominated, or intended to be nominated, by the Board of Directors, provided that (i) such information does not in any way violate any applicable Securities and Exchange Commission regulation, including regulations concerning public availability of information, and (ii) any information withheld on such basis shall be provided by separate notice

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at such time as would not be in violation of any applicable Securities and Exchange Commission regulation, such notice to be a supplement to the notice otherwise required herein; (f) the class and number of shares of the Company which are beneficially owned by the stockholder; and (g) the signed consent of each nominee to serve as a director of the Company if so elected.

Section 3.  If the Chairman of the meeting for the election of Directors determines that a nomination of any candidate for election as a director at such meeting was not made in accordance with the applicable provisions of these By-laws, such nomination shall be void.

Section 4.  The Board of Directors may adopt such special rules and regulations for the conduct of their meetings and the management of the affairs of the Company as they may determine to be appropriate, not inconsistent with law or these By-laws.

Section 5.  A regular meeting of the Board of Directors shall be held as soon as practicable after the annual meeting of stockholders in each year.  In addition, regular quarterly meetings of the Board may be held at the general offices of the Company in Kentucky, or at such other place as shall be specified in the notice of such meeting on the last Monday of January, July and October in each year.  Written notice of every regular meeting of the Board, stating the time of day at which such meeting will be held, shall be given to each Director not less than two days prior to the date of the meeting.  Such notice may be given personally in writing, or by telegraph or other written means of electronic communication, or by depositing the same, properly addressed, in the mail.

Section 6.  Special meetings of the Board may be called at any time by the Chairman of the Board, or the President, or by a Vice-President when acting as President, or by any two Directors.  Notice of such meeting, stating the place, day and hour of the meeting shall be given to each Director not less than one day prior to the date of the meeting.  Such notice may be given personally in writing, or by telegraph or other written means of electronic communication, or by depositing the same, properly addressed, in the mail.

Section 7.  Notice of any meeting of the Board may be waived by any Director.

Section 8.  A majority of the Board of Directors shall constitute a quorum for the transaction of business at any meeting of the board, but a less number may adjourn the meeting to some other day or sine die.  The Board of Directors shall keep minutes of their proceedings at their meetings. The members of the Board may be paid such fees or compensations for their services as Directors as the Board, from time to time, by resolution, may determine.

Section 9.  The Chairman of the Board, if such person is present, shall serve as Chairman at each regular or special meeting of the Board of Directors and shall determine the order of business at such meeting.  If the Chairman of the Board is not present at a regular or special meeting of the Board of Directors, the Vice Chairman of the Board shall serve as Chairman of such meeting and shall determine the order of business of such meeting.  The Board of Directors may elect one of its members as Vice Chairman of the Board.

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ARTICLE IV

COMMITTEES

Section 1.  The Board of Directors may, by resolution passed by a majority of the whole Board, appoint an Executive Committee of not less than three members of the Board, including the Chairman of the Board, if there be one, and the President of the Company.  The Executive Committee may make its own rules of procedure and elect its Chairman, and shall meet where and as provided by such rules, or by resolution of the Board of Directors.  A majority of the members of the Committee shall constitute a quorum for the transaction of business.  During the intervals between the meetings of the Board of Directors, the Executive Committee shall have all the powers of the Board in the management of the business and affairs of the Company except as limited by statute, including power to authorize the seal of the Company to be affixed to all papers which require it, and, by majority vote of all its members, may exercise any and all such powers in such manner as such Committee shall deem best for the interests of the Company, in all cases in which specific directions shall not have been given by the Board of Directors.  The Executive Committee shall keep regular minutes of its proceedings and report the same to the Board at meetings thereof.

Section 2.  The Board of Directors may appoint other committees, standing or special, from time to time from among their own number, or otherwise, and confer powers on such committees, and revoke such powers and terminate the existence of such committees at its pleasure.

Section 3.  Meetings of any committee may be called in such manner and may be held at such times and places as such committee may by resolution determine, provided that a meeting of any committee may be called at any time by the Chairman of the Board or by the President.  Notice of such meeting, stating the place, day and hour of the meeting shall be given to each Director not less than one day prior to the meeting.  Such notice may be given personally in writing, or by telegraph or other written means of electronic communication, or by depositing the same, properly addressed, in the mail.  Members of all committees may be paid such fees for attendance at meetings as the Board of Directors may determine.

ARTICLE V

OFFICERS

Section 1.  The officers of the Company shall be a Chief Executive Officer, President, Chief Operating Officer, Chief Financial Officer, Chief Administrative Officer, one or more Vice Presidents, Secretary, Treasurer, Controller or such other officers (including, if so directed by a resolution of the Board of Directors, the Chairman of the Board) as the Board or the Chief Executive Officer may from time to time elect or appoint.  Any two of the offices may be combined in one person, but no officer shall execute, acknowledge, or verify any instrument in more than one capacity.  If practicable, officers are to be elected or appointed by the Board of Directors or the Chief Executive Officer at the first meeting of the Board following the annual

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meeting of stockholders and, unless otherwise specified, shall hold office for one year or until their successors are elected and qualified.  Any vacancy shall be filled by the Board of Directors or the Chief Executive Officer.  Except as provided below, officers shall perform those duties usually incident to the office or as otherwise required by the Board of Directors, the Chief Executive Officer, or the officer to whom they report.  An officer may be removed with or without cause and at any time by the Board of Directors or by the Chief Executive Officer.

Section 2.  The Chief Executive Officer of the Company shall have full charge of all of the affairs of the Company and shall report directly to the Board of Directors.

Section 3.  The President, should that office be created and filled, shall exercise such functions as may be delegated by the Chief Executive Officer and shall exercise the functions of the Chief Executive Officer during the absence or disability of the Chief Executive Officer.

Section 4.  The Chief Operating Officer, should that office be created and filled, shall have responsibility for the management and direction of the Company, subject to the direction and approval of the Chief Executive Officer.

Section 5.  The Chief Financial Officer, should that office be created and filled, shall have responsibility for the financial affairs of the Company, including maintaining accurate books and records, meeting all financial reporting requirements and controlling Company funds, subject to the direction and approval of the Chief Executive Officer.

Section 6.  The Chief Administrative Officer, should that office be created and filled, shall have responsibility for the general administrative and human resources operations of the Company, subject to the direction and approval of the Chief Executive Officer.

Section 7.  The Vice President or Vice Presidents, should such offices be created and filled, may be designated as Vice President, Senior Vice President or Executive Vice President, as the Board of Directors or Chief Executive Officer may determine.

Section 8.  The Secretary shall be present at and record the proceedings of all meetings of the Board of Directors and of the stockholders, give notices of meetings of Directors and stockholders, have custody of the seal of the Company and affix it to any instrument requiring the same, and shall have the power to sign certificates for shares of stock of the Company.

Section 9.  The Treasurer, should that office be created and filled, shall have responsibility for all receipts and disbursements of the Company and be custodian of the Company’s funds.

Section 10.  The Controller, should that office be created and filled, shall have responsibility for the accounting records of the Company.

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ARTICLE VI

MISCELLANEOUS

Section 1.  The funds of the Company shall be deposited to its credit in such banks or trust companies as are selected by the Treasurer, subject to the approval of the chief executive officer.  Such funds shall be withdrawn only on checks or drafts of the Company for the purpose of the Company, except that such funds may be withdrawn without the issuance of a check or draft (a) to effect a transfer of funds between accounts maintained by the Company at one or more depositaries; (b) to effect the withdrawal of funds, pursuant to resolution of the Board of Directors, for the payment of either commercial paper promissory notes of other entities or government securities purchased by the Company; (c) to effect a withdrawal of funds by the Company pursuant to the terms of any agreement or other document, approved by the Board of Directors, which requires or contemplates payment or payments by the Company by means other than a check or draft; or (d) to effect a withdrawal of funds for such other purpose as the Board of Directors by resolution shall provide.  All checks and drafts of the Company shall be signed in such manner and by such officer or officers or such individuals as the Board of Directors, from time to time by resolution, shall determine.  Only checks and drafts so signed shall be valid checks or drafts of the Company.

Section 2.  No debt shall be contracted except for current expenses unless authorized by the Board of Directors or the Executive Committee, and no bills shall be paid by the Treasurer unless audited and approved by the Controller or some other person or committee expressly authorized by the Board of Directors or the Executive Committee, to audit and approve bills for payment.  All notes of the Company shall be executed by two different officers of the Company.  Either or both of such executions may be by facsimile.

Section 3.  The fiscal year of the Company shall close at the end of December annually.

ARTICLE VII

INDEMNIFICATION OF DIRECTORS, OFFICERS,

EMPLOYEES AND AGENTS

Section 1.  Unless prohibited by law, the Company shall indemnify each of its Directors, officers, employees and agents against expenses  (including attorneys’ fees), judgments, taxes, fines and amounts paid in settlement, incurred by such person in connection with, and shall advance expenses (including attorneys’ fees) incurred by such person in defending any threatened, pending or completed action, suit or proceeding (whether civil, criminal, administrative or investigative) to which such person was, is, or is threatened to be made a party by reason of the fact that such person is or was a Director, officer, employee or agent of another domestic or foreign corporation, partnership, joint venture, trust, other enterprise, or employee benefit plan.  Advancement of expenses shall be made upon receipt of a written statement of his good faith belief that he has met the standard of conduct  as required by statute and a written undertaking, with such security, if any, as the Board may reasonably require, by or on behalf of

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the person seeking indemnification, to repay amounts advanced if it shall ultimately be determined that such person is not entitled to be indemnified by the Company.

Section 2.  In addition (and not by way of limitation of) the foregoing provisions of Section 1 of this Article VII and the provisions of the Kentucky Business Corporation Act, each person (including the heirs, executors, administrators and estate of such person) who is or was or had agreed to become a Director, officer, employee or agent of the Company and each person (including the heirs, executors, administrators and estate of such person) who is or was serving or who had agreed to serve at the request of the Directors or any officer of the Company as a Director, officer, employee, trustee, partner or agent of another corporation, partnership, joint venture, trust, employee benefit plan or other enterprise shall be indemnified by the Company to the fullest extent permitted by the Kentucky Business Corporation Act or any other applicable laws as presently or hereafter in effect.  Without limiting the generality or the effect of the foregoing, the Company is authorized to enter into one or more agreements with any person which provide for indemnification greater or different than that provided in this Article VII.  Any repeal or modification of this Article by the stockholders of the Company shall not adversely affect any indemnification of any person hereunder in respect of any act or omission occurring prior to the time of such repeal or modification.

Section 3.  The Company may purchase and maintain insurance on behalf of any person who is or was entitled to indemnification as described above, whether or not the Company would have the power or duty to indemnify such person against such liability under this Article VII or applicable law.

Section 4.  To the extent required by applicable law, any indemnification of, or advance of expenses to, any person who is or was entitled to indemnification as described above, if arising out of a proceeding by or in the right of the Company, shall be reported in writing to the stockholders with or before the notice of the next stockholder’ meeting.

Section 5.  The indemnification provided by this Article VII:  (a) shall not be deemed exclusive of any other rights to which the Company’s Directors, officers, employees or agents may be entitled pursuant to the Articles of Incorporation, any agreement of indemnity, as a matter of law or otherwise; and (b) shall continue as to a person who has ceased to be a Director, officer, employee or agent and shall inure to the benefit of such person’s heirs, executors and administrators.

ARTICLE VIII

AMENDMENT OR REPEAL OF BY-LAWS

These By-laws may be added to, amended or repealed at any meeting of the Board of Directors, and may also be added to, amended or repealed by the stockholders.

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BY-LAWS

OF

KENTUCKY UTILITIES COMPANY

Dated April 28, 1998

(as amended through June 2, 1999)

(as amended through December 16, 2003)

EX-4.22

EXHIBIT 4.22

SUPPLEMENTAL INDENTURE

FROM

LOUISVILLE GAS AND ELECTRIC COMPANY

TO

BNY MIDWEST TRUST COMPANY
TRUSTEE

DATED OCTOBER 1, 2003

SUPPLEMENTAL TO TRUST INDENTURE

DATED NOVEMBER 1, 1949

Table of Contents

Parties
Recitals
Form of Bonds of Pollution Control Series GG
Further Recitals
ARTICLE I.
SPECIFIC SUBJECTION OF PROPERTY TO THE LIEN OF THE ORIGINAL INDENTURE.
Section 1.01-	Grant of certain property, including all personal property to comply with Uniform Commercial Code of the Commonwealth of Kentucky, subject to permissible encumbrances and other exceptions contained in Original Indenture
ARTICLE II.
PROVISIONS OF BONDS OF POLLUTION CONTROL SERIES GG.
Section 2.01-	Terms of Bonds of Pollution Control Series GG
Section 2.02-	Payment of principal and interest-Bonds of Pollution Control Series GG
Section 2.03-	Bonds of Pollution Control Series GG deemed fully paid upon payment of corresponding Pollution Control Revenue Bonds
Section 2.04-	Interchangeability of bonds
Section 2.05-	Charges upon exchange or transfer of bonds
ARTICLE III.
MISCELLANEOUS.
Section 3.01-	Recitals of fact, except as stated, are statements of the Company
Section 3.02 -	Supplemental Indenture to be construed as a part of the Original Indenture
Section 3.03-	(a)  Trust Indenture Act to control
	(b)  Severability of provisions contained in Supplemental Indenture and bonds
Section 3.04-	Word “Indenture” as used herein includes in its meaning the Original Indenture and all indentures supplemental thereto
Section 3.05-	References to either party in Supplemental Indenture include successors or assigns
Section 3.06-	(a)  Provision for execution in counterparts
	(b) Table of contents and descriptive headings of Articles not to affect meaning
Schedule A

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Supplemental Indenture, made as of the 1st day of October, 2003, by and between LOUISVILLE GAS AND ELECTRIC COMPANY, a corporation duly organized and existing under and by virtue of the laws of the Commonwealth of Kentucky, having its principal office in the City of Louisville, County of Jefferson, in said Commonwealth of Kentucky (the “Company”), the party of the first part, and BNY MIDWEST TRUST COMPANY, an Illinois trust company duly organized and existing under and by virtue of the laws of the State of Illinois, having its principal office at Two North LaSalle Street, City of Chicago, County of Cook, State of Illinois 60602, as Trustee (the “Trustee”), party of the second part;

WITNESSETH:

WHEREAS, the Company has heretofore executed and delivered its Trust Indenture (the “Original Indenture”), made as of November 1, 1949, whereby the Company granted, bargained, sold, warranted, released, conveyed, assigned, transferred, mortgaged, pledged, set over and confirmed unto the Trustee under said Indenture and to its respective successors in trust, all property, real, personal and mixed then owned or thereafter acquired or to be acquired by the Company (except as therein excepted from the lien thereof) and subject to the rights reserved by the Company in and by the provisions of the Original Indenture, to be held by said Trustee in trust in accordance with the provisions of the Original Indenture for the equal pro rata benefit and security of all and each of the bonds issued and to be issued thereunder in accordance with the provisions thereof, and

WHEREAS, Section 2.01 of the Original Indenture provides that bonds may be issued thereunder in one or more series, each series to have such distinctive designation as the Board of Directors of the Company may select for such series; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture, bonds of a series designated “First Mortgage Bonds, Series due November 1, 1979,” bearing interest at the rate of 2 3/4% per annum; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated February 1, 1952, bonds of a series designated “First Mortgage Bonds, Series due February 1, 1982,” bearing interest at the rate of 3 1/8% per annum; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated February 1, 1954, bonds of a series designated “First Mortgage Bonds, Series due February 1, 1984,” bearing interest at the rate of 3 1/8% per annum; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated September 1, 1957, bonds of a series designated “First Mortgage Bonds, Series due September 1, 1987,” bearing interest at the rate of 4 7/8% per annum; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated October 1, 1960, bonds

of a series designated “First Mortgage Bonds, Series due October 1, 1990,” bearing interest at the rate of 4 7/8% per annum; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated June 1, 1966, bonds of a series designated “First Mortgage Bonds, Series due June 1, 1996,” bearing interest at the rate of 5 5/8% per annum; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated June 1, 1968, bonds of a series designated “First Mortgage Bonds, Series due June 1, 1998,” bearing interest at the rate of 6 3/4% per annum; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated June 1, 1970, bonds of a series designated “First Mortgage Bonds, Series due July 1, 2000,” bearing interest at the rate of 9 1/4% per annum; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated August 1, 1971, bonds of a series designated “First Mortgage Bonds, Series due August 1, 2001,” bearing interest at the rate of 8 1/4% per annum; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated June 1, 1972, bonds of a series designated “First Mortgage Bonds, Series due July 1, 2002,” bearing interest at the rate of 7 1/2% per annum; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated February 1, 1975, bonds of a series designated “First Mortgage Bonds, Series due March 1, 2005,” bearing interest at the rate of 8 7/8% per annum; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated September 1, 1975, bonds of a series designated “First Mortgage Bonds, Pollution Control Series A,” bearing interest as provided therein and maturing September 1, 2000; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated September 1, 1976, bonds of a series designated “First Mortgage Bonds, Pollution Control Series B,” bearing interest as provided therein and maturing September 1, 2006; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated October 1, 1976, bonds

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of a series designated “First Mortgage Bonds, Series due November 1, 2006,” bearing interest at the rate of 8 1/2% per annum; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated June 1, 1978, bonds of a series designated “First Mortgage Bonds, Pollution Control Series C,” bearing interest as provided therein and maturing June 1, 1998/2008; and

WHEREAS, the Company has heretofore executed and delivered to the Trustee a Supplemental Indenture dated February 15, 1979, setting forth duly adopted modifications and alterations to the Original Indenture and all Supplemental Indentures thereto; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated September 1, 1979, bonds of a series designated “First Mortgage Bonds, Series due October 1, 2009,” bearing interest at the rate of 10 1/8% per annum; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated September 15, 1979, bonds of a series designated “First Mortgage Bonds, Pollution Control Series D,” bearing interest as provided therein and maturing October 1, 2004/2009; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated September 15, 1981, bonds of a series designated “First Mortgage Bonds, Pollution Control Series E,” bearing interest as provided therein and maturing September 15, 1984; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated March 1, 1982, bonds of a series designated “First Mortgage Bonds, Pollution Control Series F,” bearing interest as provided therein and maturing March 1, 2012; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated March 15, 1982, bonds of a series designated “First Mortgage Bonds, Pollution Control Series G,” bearing interest as provided therein and maturing March 1, 2012; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated September 15, 1982, bonds of a series designated “First Mortgage Bonds, Pollution Control Series H,” bearing interest as provided therein and maturing September 15, 1992; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated February 15, 1984, bonds of a series designated “First Mortgage Bonds, Pollution Control Series I,” bearing interest

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as provided therein and maturing February 15, 2011; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated July 1, 1985, bonds of  a series designated “First Mortgage Bonds, Pollution Control Series J,” bearing interest as provided therein and maturing July 1, 1995/2015; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated November 15, 1986, bonds of a series designated “First Mortgage Bonds, Pollution Control Series K,” bearing interest as provided therein and maturing December 1, 2016; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated November 16, 1986, bonds of a series designated “First Mortgage Bonds, Pollution Control Series L,” bearing interest as provided therein and maturing December 1, 2016; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated August 1, 1987, bonds of a series designated “First Mortgage Bonds, Pollution Control Series M,” bearing interest as provided therein and maturing August 1, 1997; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated February 1, 1989, bonds of a series designated “First Mortgage Bonds, Pollution Control Series N,” bearing interest as provided therein and maturing February 1, 2019; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated February 2, 1989, bonds of a series designated “First Mortgage Bonds, Pollution Control Series O,” bearing interest as provided therein and maturing February 1, 2019; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated June 15, 1990, bonds of a series designated “First Mortgage Bonds, Pollution Control Series P,” bearing interest as provided therein and maturing June 15, 2015; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated November 1, 1990, bonds of a series designated “First Mortgage Bonds, Pollution Control Series Q” and bonds of a series designated “First Mortgage Bonds, Pollution Control Series R,” each series bearing interest as provided therein and maturing November 1, 2020; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated September 1, 1992,

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bonds of a series designated “First Mortgage Bonds, Pollution Control Series S,” bearing interest as provided therein and maturing September 1, 2017; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated September 2, 1992, bonds of a series designated “First Mortgage Bonds, Pollution Control Series T,” bearing interest as provided therein and maturing September 1, 2017; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated August 15, 1993, bonds of a series designated “First Mortgage Bonds, Series due August 15, 2003,” bearing interest at the rate of 6% per annum; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated August 16, 1993, bonds of a series designated “First Mortgage Bonds, Pollution Control Series U,” bearing interest as provided therein and maturing August 15, 2013 and bonds of a series designated “First Mortgage Bonds, Pollution Control Series V,” bearing interest as provided therein and maturing August 15, 2019; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated October 15, 1993, bonds of a series designated “First Mortgage Bonds, Pollution Control Series W,” bearing interest as provided therein and maturing October 15, 2020, and bonds of a series designated “First Mortgage Bonds, Pollution Control Series X,” bearing interest as provided therein and maturing April 15, 2023; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated May 1, 2000, bonds of a series designated “First Mortgage Bonds, Pollution Control Series Y,” bearing interest as provided therein and maturing May 1, 2027; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated August 1, 2000, bonds of a series designated “First Mortgage Bonds, Pollution Control Series Z,” bearing interest as provided therein and maturing August 1, 2030; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated September 1, 2001, bonds of a series designated “First Mortgage Bonds, Pollution Control Series AA,” bearing interest as provided therein and maturing September 1, 2027; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated March 1, 2002, bonds of a series designated “First Mortgage Bonds, Pollution Control Series BB,” bearing interest as

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provided therein and maturing September 1, 2026, and bonds of a series designated “First Mortgage Bonds, Pollution Control Series CC,” bearing interest as provided therein and maturing September 1, 2026; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated March 15, 2002, bonds of a series designated “First Mortgage Bonds, Pollution Control Series DD,” bearing interest as provided therein and maturing November 1, 2027, and bonds of a series designated “First Mortgage Bonds, Pollution Control Series EE,” bearing interest as provided therein and maturing November 1, 2027; and

WHEREAS, the Company has heretofore issued in accordance with the provisions of the Original Indenture as supplemented by the Supplemental Indenture dated October 1, 2002, bonds of a series designated “First Mortgage Bonds, Pollution Control Series FF,” bearing interest as provided therein and maturing October 1, 2032; and

WHEREAS, the Louisville/Jefferson County Metro Government in the Commonwealth of Kentucky (the “Issuer”) has agreed to issue $128,000,000 principal amount of its Pollution Control Revenue Bonds, 2003 Series A (Louisville Gas and Electric Company Project) (the “Pollution Control Revenue Bonds”) pursuant to the provisions of the Indenture of Trust, dated as of October 1, 2003 (the “Pollution Control Indenture”), between and among the Issuer and Deutsche Bank Trust Company Americas, as Trustee, Paying Agent and Bond Registrar (said Trustee or any successor trustee under the Pollution Control Indenture being hereinafter referred to as the “Pollution Control Trustee”); and

WHEREAS, the proceeds of the Pollution Control Revenue Bonds (other than any accrued interest, if any, thereon) will be loaned by the Issuer to the Company pursuant to the provisions of a Loan Agreement, dated as of October 1, 2003, between the Issuer and the Company (the “Agreement”), to pay and discharge (i) $102,000,000 in outstanding principal amount of “County of Jefferson, Kentucky, Pollution Control Revenue Bonds (Louisville Gas and Electric Company Project) 1993 Series B,” dated August 15, 1993 (the “1993 Series B Bonds”) and (ii) $26,000,000 in outstanding principal amount of “County of Jefferson, Kentucky, Pollution Control Revenue Bonds (Louisville Gas and Electric Company Project) 1993 Series C,” dated October 15, 1993 (the “1993 Series C Bonds” and, together with the 1993 Series B Bonds, the “1993 Bonds”) on the date of issuance of the Pollution Control Revenue Bonds.  The 1993 Bonds were issued to finance or refinance the cost of construction of certain air and water pollution control facilities and solid waste disposal facilities at the Mill Creek and Cane Run Generating Stations of the Company, which facilities are hereinafter sometimes referred to as the “1993 Project,” which 1993 Project is located in Jefferson County, Kentucky, and which 1993 Project is more fully described in Exhibit A to the Agreement; and

WHEREAS, payments by the Company under and pursuant to the Agreement have been assigned by the Issuer to the Pollution Control Trustee in order to secure the payment of the Pollution Control Revenue Bonds; and

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WHEREAS, in order to further secure the payment of the Pollution Control Revenue Bonds, the Company desires to provide for the issuance under the Original Indenture to the Pollution Control Trustee of a new series of bonds designated “First Mortgage Bonds, Pollution Control Series GG” (sometimes called “Bonds of Pollution Control Series GG”), in a principal amount equal to the principal amount of the Pollution Control Revenue Bonds, and with corresponding terms and maturity, the Bonds of Pollution Control Series GG to be issued as registered bonds without coupons in denominations of a multiple of $1,000; and the Bonds of Pollution Control Series GG are to be substantially in the form and tenor following, to-wit:

(Form of Bonds of Pollution Control Series GG)

This Bond has not been registered under the Securities Act of 1933, as amended, and may not be offered or sold in contravention of said Act and is not transferable except to a successor Trustee under the Indenture of Trust dated as of October 1, 2003, from the Louisville/Jefferson County Metro Government, Kentucky, to Deutsche Bank Trust Company Americas, as Trustee, Paying Agent and Bond Registrar.

LOUISVILLE GAS AND ELECTRIC COMPANY
(Incorporated under the laws of the Commonwealth of Kentucky)
First Mortgage Bond
Pollution Control Series GG

No              $             

Louisville Gas and Electric Company, a corporation organized and existing under and by virtue of the laws of the Commonwealth of Kentucky (herein called the “Company”), for value received, hereby promises to pay to Deutsche Bank Trust Company Americas, as Trustee under the Indenture of Trust (the “Pollution Control Indenture”) dated as of October 1, 2003, from the Louisville/Jefferson County Metro Government, Kentucky, to Deutsche Bank Trust Company Americas, or any successor trustee under the Pollution Control Indenture (the “Pollution Control Trustee”) and at the office of BNY Midwest Trust Company, Chicago, Illinois (the “Trustee”) the sum of                      Dollars in lawful money of the United States of America on the Demand Redemption Date, as hereinafter defined, and to pay on the Demand Redemption Date to the Pollution Control Trustee, interest hereon from the Initial Interest Accrual Date, as hereinafter defined, to the Demand Redemption Date at the same rate or rates per annum then and thereafter from time to time borne by the Pollution Control Revenue Bonds, in like money, said interest being payable at the office of the Trustee in Chicago, Illinois, subject to the provisions hereinafter set forth in the event of a rescission of a Redemption Demand, as hereinafter defined.

This bond is one of a duly authorized issue of bonds of the Company, known as its First Mortgage Bonds, unlimited in aggregate principal amount, which issue of bonds consists, or may consist of several series of varying denominations, dates and tenors, all issued and to be issued under and equally secured (except in so far as a sinking fund, or similar fund, established in accordance with the provisions of the Indenture may afford additional security for the bonds of any specific series) by a Trust Indenture dated November 1, 1949 (the “Original Indenture”), and

7

Supplemental Indentures thereto dated February 1, 1952, February 1, 1954, September 1, 1957, October 1, 1960, June 1, 1966, June 1, 1968, June 1, 1970, August 1, 1971, June 1, 1972, February 1, 1975, September 1, 1975, September 1, 1976, October 1, 1976, June 1, 1978, February 15, 1979, September 1, 1979, September 15, 1979, September 15, 1981, March 1, 1982, March 15, 1982, September 15, 1982, February 15, 1984, July 1, 1985, November 15, 1986, November 16, 1986, August 1, 1987, February 1, 1989, February 2, 1989, June 15, 1990, November 1, 1990, September 1, 1992, September 2, 1992, August 15, 1993, August 16, 1993, October 15, 1993, May 1, 2000, August 1, 2000, September 1, 2001, March 1, 2002, March 15, 2002, October 1, 2002 and October 1, 2003 (all of which instruments are herein collectively called the “Indenture”), executed by the Company to the Trustee, to which Indenture reference is hereby made for a description of the property mortgaged and pledged, the nature and extent of the security, the rights of the holders of the bonds as to such security, and the terms and conditions upon which the bonds may be issued under the Indenture and are secured.  The principal hereof may be declared or may become due on the conditions, in the manner and at the time set forth in the Indenture, upon the happening of a completed default as in the Indenture provided.  The Indenture provides that such declaration may in certain events be waived by the holders of a majority in principal amount of the bonds outstanding.

This bond is one of a series of bonds of the Company issued under the Indenture and designated as First Mortgage Bonds, Pollution Control Series GG.  The bonds of this Series have been issued to the Pollution Control Trustee under the Pollution Control Indenture to secure payment of the Pollution Control Revenue Bonds, 2003 Series A (Louisville Gas and Electric Company Project) (the “Pollution Control Revenue Bonds”) issued by the Louisville/Jefferson County Metro Government, Kentucky (the “Issuer”) under the Pollution Control Indenture, the proceeds of which have been or are to be loaned to the Company pursuant to the provisions of the Loan Agreement dated as of October 1, 2003 (the “Agreement”) between the Company and the Issuer.  The maturity of the obligation represented by the bonds of this Series is October 1, 2033.  The date of maturity of the obligation represented by the bonds of this Series is hereinafter referred to as the Final Maturity Date.  The bonds of this Series shall bear interest from the Initial Interest Accrual Date, as hereinafter defined, at the same rate or rates per annum then and thereafter from time to time borne by the Pollution Control Revenue Bonds.

With the consent of the Company and to the extent permitted by and as provided in the Indenture, the rights and obligations of the Company and/or of the holders of the bonds, and/or the terms and provisions of the Indenture and/or of any instruments supplemental thereto may be modified or altered by affirmative vote of the holders of at least seventy percent in principal amount of the bonds then outstanding under the Indenture and any instruments supplemental thereto (excluding bonds disqualified from voting by reason of the interest of the Company or of certain related persons therein as provided in the Indenture), and by the affirmative vote of at least seventy percent in principal amount of the bonds of any series entitled to vote then outstanding under the Indenture and any instruments supplemental thereto (excluding bonds disqualified from voting as aforesaid) and affected by such modification or alteration, in case one or more but less than all of the series of bonds then outstanding are so affected; provided that no such modification or alteration shall permit the extension of the maturity of the principal of this

8

bond or the reduction in the rate of interest, if any, hereon or any other modification in the terms of payment of such principal or interest, if any, or the taking of certain other action as more fully set forth in the Indenture, without the consent of the holder hereof.

Except as provided in the next succeeding paragraph, in the event of a default under Section 9.1 of the Agreement or in the event of a default in the payment of the principal of, premium, if any, or interest (and such default in the payment of interest continues for the full grace period, if any, permitted by the Pollution Control Indenture and the Pollution Control Revenue Bonds) on the Pollution Control Revenue Bonds, whether at maturity, by tender for purchase, by acceleration, by sinking fund, redemption or otherwise, as and when the same becomes due, the bonds of this Series shall be redeemable in whole upon receipt by the Trustee of a written demand (hereinafter called a “Redemption Demand”) from the Pollution Control Trustee stating that there has been such a default, stating that it is acting pursuant to the authorization granted by Section 9.02(c) of the Pollution Control Indenture, specifying the last date to which interest on the Pollution Control Revenue Bonds has been paid (such date being hereinafter referred to as the “Initial Interest Accrual Date”) and demanding redemption of the bonds of this Series.  The Trustee shall, within 10 days after receiving such Redemption Demand, mail a copy thereof to the Company marked to indicate the date of its receipt by the Trustee.  Promptly upon receipt by the Company of such copy of a Redemption Demand, the Company shall fix a date on which it will redeem the bonds of this Series so demanded to be redeemed (hereinafter called the “Demand Redemption Date”).  Notice of the date fixed as and for the Demand Redemption Date shall be mailed by the Company to the Trustee at least 30 days prior to such Demand Redemption Date.  The date to be fixed by the Company as and for the Demand Redemption Date may be any date up to and including the earlier of (i) the 120th day after receipt by the Trustee of the Redemption Demand or (ii) the Final Maturity Date, provided that if the Trustee shall not have received such notice fixing the Demand Redemption Date within 90 days after receipt by it of the Redemption Demand, the Demand Redemption Date shall be deemed to be the earlier of (i) the 120th day after receipt by the Trustee of the Redemption Demand or (ii) the Final Maturity Date.  The Trustee shall mail notice of the Demand Redemption Date (such notice being hereinafter called the “Demand Redemption Notice”) to the Pollution Control Trustee not more than 10 nor less than five days prior to the Demand Redemption Date.  Notwithstanding the foregoing, if a default to which this paragraph is applicable is existing on the Final Maturity Date, such date shall be deemed to be the Demand Redemption Date without further action (including actions specified in this paragraph) by the Pollution Control Trustee, the Trustee or the Company.  The bonds of this Series shall be redeemed by the Company on the Demand Redemption Date, upon surrender thereof by the Pollution Control Trustee to the Trustee, at a redemption price equal to the principal amount thereof, plus accrued interest thereon at the rate per annum set forth in the third paragraph of this Bond, from the Initial Interest Accrual Date to the Demand Redemption Date.  If a Redemption Demand is rescinded by the Pollution Control Trustee by written notice to the Trustee prior to the Demand Redemption Date, no Demand Redemption Notice shall be given, or, if already given, shall be automatically annulled, and interest on the bonds of

9

this Series shall cease to accrue, all interest accrued thereon shall be automatically rescinded and cancelled and the Company shall not be obligated to make any payments of principal of or interest on the bonds of this Series; but no such rescission shall extend to or affect any subsequent default or impair any right consequent thereon.

In the event that all of the bonds outstanding under the Indenture shall have become immediately due and payable, whether by declaration or otherwise, and such acceleration shall not have been annulled, the bonds of this Series shall bear interest at the rate per annum set forth in the third paragraph of this bond, from the Initial Interest Accrual Date, as specified in a written notice to the Trustee from the Pollution Control Trustee, and the principal of and interest on the bonds of this Series from the Initial Interest Accrual Date shall be payable in accordance with the provisions of the Indenture.

Upon payment of the principal of and premium, if any, and interest on the Pollution Control Revenue Bonds, whether at maturity or prior to maturity by redemption or otherwise, and the surrender thereof to and cancellation thereof by the Pollution Control Trustee (other than any Pollution Control Revenue Bond that was cancelled by the Pollution Control Trustee and for which one or more other Pollution Control Revenue Bonds were delivered and authenticated pursuant to the Pollution Control Indenture in lieu of or in exchange or substitution for such cancelled Pollution Control Revenue Bond), or upon provision for the payment thereof having been made in accordance with the Pollution Control Indenture, bonds of this Series in a principal amount equal to the principal amount of the Pollution Control Revenue Bonds so surrendered and cancelled or for the provision for which payment has been made shall be deemed fully paid and the obligations of the Company thereunder shall be terminated, and such bonds of this Series shall be surrendered by the Pollution Control Trustee to the Trustee and shall be cancelled by the Trustee.  From and after the Release Date (as defined below), the bonds of this Series shall be deemed fully paid, satisfied and discharged and the obligations of the Company hereunder and thereunder shall be terminated.  The Release Date shall be the date that the Bond Insurer (as such term is defined in the Pollution Control Indenture), at the request of the Company, consents to the release of the bonds of this Series as security for the Pollution Control Revenue Bonds, provided that in no event shall that date be later than the date as of which all bonds issued under the Indenture prior to the date of initial issuance of this bond (and excluding bonds of this Series and First Mortgage Bonds, Pollution Control Series Y, Z, AA, BB, CC, DD, EE and FF) have been retired through payment, redemption or otherwise (including those bonds “deemed to be redeemed” within the meaning of that term as used in Article X of the Original Indenture) at, before or after the maturity thereof.  On the Release Date, the bonds of this Series shall be surrendered by the Pollution Control Trustee to the Trustee whereupon the bonds of said Series so surrendered shall be cancelled by the Trustee.

No recourse shall be had for the payment of principal of, or interest, if any, on this bond, or any part thereof, or of any claim based hereon or in respect hereof or of the Indenture, against any incorporator, or any past, present or future stockholder, officer or director of the Company or of any predecessor or successor corporation, either directly or through the Company, or through any such predecessor or successor corporation, or through any receiver or trustee in bankruptcy, whether by virtue of any constitution, statute or rule of law or by the enforcement of any assessment or penalty or otherwise, all such liability being, by the acceptance hereof and as part

10

of the consideration for the issue hereof, expressly waived and released, as more fully provided in the Indenture.

This bond shall not be valid or become obligatory for any purpose unless and until the certificate of authentication hereon shall have been signed by or on behalf of BNY Midwest Trust Company, as Trustee under the Indenture, or its successor thereunder.

IN WITNESS WHEREOF, LOUISVILLE GAS AND ELECTRIC COMPANY has caused this instrument to be signed in its name by its President or a Vice President or with the facsimile signature of its President, and its corporate seal, or a facsimile thereof, to be hereto affixed and attested by its Secretary or Assistant Secretary or with the facsimile signature of its Secretary.

Dated	LOUISVILLE GAS AND ELECTRIC COMPANY
Attest:	By
		Vice President
Secretary

and

WHEREAS, Sections 4.01 and 21.03 of the Original Indenture provide in substance that the Company and the Trustee may enter into indentures supplemental thereto for the purposes, among others, of creating and setting forth the particulars of any new series of bonds and of providing the terms and conditions of the issue of the bonds of any series not expressly provided for in the Original Indenture and of assigning, conveying, mortgaging, pledging and transferring unto the Trustee additional property of the Company, and for any other purpose not inconsistent with the terms of the Original Indenture; and

WHEREAS, the execution and delivery of this Supplemental Indenture have been duly authorized by a resolution adopted by the Board of Directors of the Company;

Now, THEREFORE, THIS INDENTURE WITNESSETH:

Louisville Gas and Electric Company, in consideration of the premises and of one dollar

11

to it duly paid by the Trustee at or before the ensealing and delivery of these presents, the receipt whereof is hereby acknowledged, and other good and valuable considerations, does hereby covenant and agree to and with BNY Midwest Trust Company, as Trustee, and its successors in the trust under the Indenture for the benefit of those who hold or shall hold the bonds issued or to be issued thereunder, as follows:

ARTICLE I.

SPECIFIC SUBJECTION OF PROPERTY TO THE LIEN OF THE ORIGINAL INDENTURE

Section 1.01.          The Company in order better to secure the payment, both of principal and interest, of all bonds of the Company at any time outstanding under the Indenture, according to their tenor and effect, and the performance of and compliance with the covenants and conditions in the Indenture contained, has granted, bargained, sold, warranted, released, conveyed, assigned, transferred, mortgaged, pledged, set over and confirmed and by these presents does grant, bargain, sell, warrant, release, convey, assign, transfer, mortgage, pledge, set over and confirm unto BNY Midwest Trust Company, as Trustee and to its respective successors in said trust forever, subject to the rights reserved by the Company in and by the provisions of the Indenture, all the property described and mentioned or enumerated in a schedule hereto annexed and marked Schedule A, reference to said schedule being hereby made with the same force and effect as if the same were incorporated herein at length; together with all and singular the tenements, hereditaments and appurtenances belonging or in any wise appertaining to the aforesaid property or any part thereof with the reversion and reversions, remainder and remainders, tolls, rents and revenues, issues, income, product and profits thereof;

Also, in order to subject all of the personal property and chattels of the Company to the lien of the Indenture in conformity with the provisions of the Uniform Commercial Code of the Commonwealth of Kentucky, all steam, hydro and other electric generating plants, including buildings and other structures, turbines, generators, boilers, condensing equipment, and all other equipment; substations; electric transmission and distribution systems, including structures, poles, towers, fixtures, conduits, insulators, wires, cables, transformers, services and meters; steam and heating mains and equipment; gas generating and coke plants, including buildings, holders and other structures, boilers and other boiler plant equipment, benches, retorts, coke ovens, water gas sets, condensing and purification equipment, piping and other accessory works equipment; facilities for gas storage whether above or below surface; gas transmission and distribution systems, including structures, mains, compressor stations, purifier stations, pressure holders, governors, services and meters; office, shop, garage and other general buildings and structures, furniture and fixtures; and all municipal and other franchises and all leaseholds, licenses, permits, easements, and privileges; all as now owned or hereafter acquired by the Company pursuant to the provisions of the Original Indenture; and

All the estate, right, title and interest and claim whatsoever, at law as well as in equity, which the Company now has or may hereafter acquire in and to the aforesaid property and franchises and every part and parcel thereof;

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Excluding, however, (1) all shares of stock, bonds, notes, evidences of indebtedness and other securities other than such as may be or are required to be deposited from time to time with the Trustee in accordance with the provisions of the Indenture; (2) cash on hand and in banks other than such as may be or is required to be deposited from time to time with the Trustee in accordance with the provisions of the Indenture; (3) contracts, claims, bills and accounts receivable and chooses in action other than such as may be or are required to be from time to time assigned to the Trustee in accordance with the provisions of the Indenture; (4) motor vehicles; (5) any stock of goods, wares and merchandise, equipment, materials and supplies acquired for the purpose of sale or lease in the usual course of business or for the purpose of consumption in the operation, construction or repair of any of the properties of the Company; and (6) the properties described in Schedule B annexed to the Original Indenture.

To have and to hold all said property, real, personal and mixed, mortgaged, pledged or conveyed by the Company as aforesaid, or intended so to be, unto the Trustee and its successors and assigns forever, subject, however, to permissible encumbrances as defined in Section 1.09 of the Original Indenture and to the further reservations, covenants, conditions, uses and trusts set forth in the Indenture, in trust nevertheless for the same purposes and upon the same conditions as are set forth in the Indenture.

ARTICLE II.

PROVISIONS OF BONDS OF POLLUTION CONTROL SERIES GG

Section 2.01.          There is hereby created, for issuance under the Original Indenture, a series of bonds designated Pollution Control Series GG, each of which shall bear the descriptive title “First Mortgage Bonds, Pollution Control Series GG” and the form thereof shall contain suitable provisions with respect to the matters specified in this section.  The Bonds of Pollution Control Series GG shall be printed, lithographed or typewritten and shall be substantially of the tenor and purport previously recited.  The Bonds of Pollution Control Series GG shall be issued as registered bonds without coupons in denominations of a multiple of $1,000 and shall be registered in the name of the Pollution Control Trustee.  The Bonds of Pollution Control Series GG shall be dated as of the date of their authentication.

The Bonds of Pollution Control Series GG shall be payable, both as to principal and interest, at the office of the Trustee in Chicago, Illinois, in lawful money of the United States of America.  The maturity of the obligation represented by the Bonds of Pollution Control Series GG is October 1, 2033.  The date of maturity of the obligation represented by the Bonds of Pollution Control Series GG is hereinafter referred to as the Final Maturity Date.  The Bonds of Pollution Control Series GG shall bear interest from the Initial Interest Accrual Date, as hereinafter defined, at the same rate or rates then and thereafter from time to time borne by the Pollution Control Revenue Bonds.

Section 2.02.          Except as provided in the next succeeding paragraph of this Section 2.02, in the event of a default under Section 9.1 of the Agreement or in the event of a default in the payment of the principal of, premium, if any, or interest (and such default in the payment of

13

interest continues for the full grace period, if any, permitted by the Pollution Control Indenture and the Pollution Control Revenue Bonds) on the Pollution Control Revenue Bonds, whether at maturity, by tender for purchase, by acceleration, by sinking fund, redemption or otherwise, as and when the same becomes due, the Bonds of Pollution Control Series GG shall be redeemable in whole upon receipt by the Trustee of a written demand (hereinafter called a “Redemption Demand”) from the Pollution Control Trustee stating that there has been such a default, stating that it is acting pursuant to the authorization granted by Section 9.02(c) of the Pollution Control Indenture, specifying the last date to which interest on the Pollution Control Revenue Bonds has been paid (such date being hereinafter referred to as the “Initial Interest Accrual Date”) and demanding redemption of the Bonds of Pollution Control Series GG.  The Trustee shall, within 10 days after receiving such Redemption Demand, mail a copy thereof to the Company marked to indicate the date of its receipt by the Trustee.  Promptly upon receipt by the Company of such copy of a Redemption Demand, the Company shall fix a date on which it will redeem the Bonds of Pollution Control Series GG so demanded to be redeemed (hereinafter called the “Demand Redemption Date”).  Notice of the date fixed as the Demand Redemption Date shall be mailed by the Company to the Trustee at least 30 days prior to such Demand Redemption Date.  The date to be fixed by the Company as and for the Demand Redemption Date may be any date up to and including the earlier of (i) the 120th day after receipt by the Trustee of the Redemption Demand or (ii) the Final Maturity Date, provided that if the Trustee shall not have received such notice fixing the Demand Redemption Date within 90 days after receipt by it of the Redemption Demand, the Demand Redemption Date shall be deemed to be the earlier of (i) the 120th day after receipt by the Trustee of the Redemption Demand or (ii) the Final Maturity Date.  The Trustee shall mail notice of the Demand Redemption Date (such notice being hereinafter called the “Demand Redemption Notice”) to the Pollution Control Trustee not more than 10 nor less than five days prior to the Demand Redemption Date.  Notwithstanding the foregoing, if a default to which this paragraph is applicable is existing on the Final Maturity Date, such date shall be deemed to be the Demand Redemption Date without further action (including actions specified in this paragraph) by the Pollution Control Trustee, the Trustee or the Company.  The Bonds of Pollution Control Series GG shall be redeemed by the Company on the Demand Redemption Date, upon surrender thereof by the Pollution Control Trustee to the Trustee, at a redemption price equal to the principal amount thereof, plus accrued interest thereon at the rate per annum set forth in Section 2.01 hereof, from the Initial Interest Accrual Date to the Demand Redemption Date.  If a Redemption Demand is rescinded by the Pollution Control Trustee by written notice to the Trustee prior to the Demand Redemption Date, no Demand Redemption Notice shall be given, or, if already given, shall be automatically annulled, and interest on the Bonds of Pollution Control Series GG shall cease to accrue, all interest accrued thereon shall be automatically rescinded and cancelled and the Company shall not be obligated to make any payments of principal of or interest on the Bonds of Pollution Control Series GG; but no such rescission shall extend to or affect any subsequent default or impair any right consequent thereon.

In the event that all of the bonds outstanding under the Indenture shall have become immediately due and payable, whether by declaration or otherwise, and such acceleration shall not have been annulled, the Bonds of Pollution Control Series GG shall bear interest at the rate

14

per annum set forth in Section 2.01 hereof, from the Interest Accrual Date, as specified in a written notice to the Trustee from the Pollution Control Trustee, and the principal of and interest on the Bonds of Pollution Control Series GG from the Initial Interest Accrual Date shall be payable in accordance with the provisions of the Indenture.

Anything herein contained to the contrary notwithstanding, the Trustee is not authorized to take any action pursuant to a Redemption Demand or a rescission thereof or a written notice required by this Section 2.02, and such Redemption Demand, rescission or notice shall be of no force or effect, unless it is executed in the name of the Pollution Control Trustee by one of its Vice Presidents.

Section 2.03.          Upon payment of the principal of and premium, if any, and interest on the Pollution Control Revenue Bonds, whether at maturity or prior to maturity by redemption or otherwise, and the surrender thereof to and cancellation thereof by the Pollution Control Trustee (other than any Pollution Control Revenue Bond that was cancelled by the Pollution Control Trustee and for which one or more other Pollution Control Revenue Bonds were delivered and authenticated pursuant to the Pollution Control Indenture in lieu of or in exchange or substitution for such cancelled Pollution Control Revenue Bond), or upon provision for the payment thereof having been made in accordance with the Pollution Control Indenture, Bonds of Pollution Control Series GG in a principal amount equal to the principal amount of the Pollution Control Revenue Bonds so surrendered and cancelled or for the provision for which payment has been made shall be deemed fully paid and the obligations of the Company thereunder shall be terminated, and such Bonds of Pollution Control Series GG shall be surrendered by the Pollution Control Trustee to the Trustee and shall be cancelled and disposed of by the Trustee.  From and after the Release Date (as defined below), the bonds of this Series shall be deemed fully paid, satisfied and discharged and the obligations of the Company hereunder and thereunder shall be terminated.  The Release Date shall be the date that the Bond Insurer (as such term is defined in the Pollution Control Indenture), at the request of the Company, consents to the release of the bonds of this Series as security for the Pollution Control Revenue Bonds, provided that in no event shall that date be later than the date as of which all bonds issued under the Indenture prior to the date of initial issuance of this bond (and excluding bonds of this Series and First Mortgage Bonds, Pollution Control Series Y, Z, AA, BB, CC, DD, EE and FF) have been retired through payment, redemption or otherwise (including those bonds “deemed to be redeemed” within the meaning of that term as used in Article X of the Original Indenture) at, before or after the maturity thereof.  On the Release Date, the bonds of this Series shall be surrendered by the Pollution Control Trustee to the Trustee whereupon the Bonds of said Series so surrendered shall be cancelled by the Trustee.

Section 2.04.          Prior to the Release Date, the Pollution Control Trustee as the registered holder of the Bonds of Pollution Control Series GG at its option may surrender the same at the office of the Trustee, in Chicago, Illinois, or elsewhere, if authorized by the Company, for cancellation, in exchange for other bonds of the same series of the same aggregate principal amount.  Thereupon, and upon receipt of any payment required under the provisions of Section 2.05 hereof, the Company shall execute and deliver to the Trustee and the Trustee shall

15

authenticate and deliver such other registered bonds to such registered holder at its office or at any other place specified as aforesaid.

Section 2.05.          No charge shall be made by the Company for any exchange or transfer of Bonds of Pollution Control Series GG other than for taxes or other governmental charges, if any, that may be imposed in relation thereto.

ARTICLE III.

MISCELLANEOUS

Section 3.01.          The recitals of fact herein and in the bonds (except the Trustee’s Certificate) shall be taken as statements of the Company and shall not be construed as made or warranted by the Trustee.  The Trustee makes no representations as to the value of any of the property subject to the lien of the Indenture, or any part thereof, or as to the title of the Company thereto, or as to the security afforded thereby and hereby, or as to the validity of this Supplemental Indenture and the Trustee shall incur no responsibility in respect of such matters.

Section 3.02.          This Supplemental Indenture shall be construed in connection with and as a part of the Original Indenture.

Section 3.03.          (a) If any provision of this Supplemental Indenture limits, qualifies or conflicts with another provision of the Original Indenture or this Supplemental Indenture required to be included in indentures qualified under the Trust Indenture Act of 1939, as amended (as enacted prior to the date of this Supplemental Indenture) by any of the provisions of Sections 310 to 317, inclusive, of the said Act, such required provision shall control.

(b)           In case any one or more of the provisions contained in this Supplemental Indenture or in the bonds issued hereunder shall be invalid, illegal, or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions contained herein and therein shall not in any way be affected, impaired, prejudiced or disturbed thereby.

Section 3.04.          Wherever in this Supplemental Indenture the word “Indenture” is used without either prefix, “Original” or “Supplemental,” such word was used intentionally to include in its meaning both the Original Indenture and all indentures supplemental thereto.

Section 3.05.          Wherever in this Supplemental Indenture either of the parties hereto is named or referred to, this shall be deemed to include the successors or assigns of such party, and all the covenants and agreements in this Supplemental Indenture contained by or on behalf of the Company or by or on behalf of the Trustee shall bind and inure to the benefit of the respective successors and assigns of such parties, whether so expressed or not.

Section 3.06.          (a) This Supplemental Indenture may be simultaneously executed in several counterparts, and all said counterparts executed and delivered, each as an original, shall

16

constitute but one and the same instrument.

(b)           The Table of Contents and the descriptive headings of the several Articles of this Supplemental Indenture were formulated, used and inserted in this Supplemental Indenture for convenience only and shall not be deemed to affect the meaning or construction of any of the provisions hereof.

17

IN WITNESS WHEREOF, the party of the first part has caused its corporate name and seal to be hereunto affixed and this Supplemental Indenture to be signed by its Treasurer and attested by its Executive Vice President, General Counsel and Corporate Secretary for and in its behalf, and the party of the second part to evidence its acceptance of the trust hereby created, has caused this Supplemental Indenture to be signed by one of its authorized officers for and in its behalf, all done as of the 1st day of October, 2003.

		LOUISVILLE GAS AND ELECTRIC COMPANY
		By:
			Daniel K. Arbough
			Treasurer
(CORPORATE SEAL)
ATTEST:
	John R. McCall
	Executive Vice President,
	General Counsel and
	Corporate Secretary
		BNY MIDWEST TRUST COMPANY
		By:
		Its:

COMMONWEALTH OF	)
KENTUCKY	)	SS:
	)
COUNTY OF JEFFERSON	)

BE IT REMEMBERED that on this            day of           , 2003, before me, a Notary Public duly commissioned in and for the County and Commonwealth aforesaid, personally appeared DANIEL K. ARBOUGH and JOHN R. MCCALL, respectively, Treasurer and Executive Vice President, General Counsel and Corporate Secretary of Louisville Gas and Electric Company, a corporation organized and existing under and by virtue of the laws of the Commonwealth of Kentucky, who are personally known to me to be such officers, respectively, and who are personally known to me to be the same persons who executed as officers the foregoing instrument of writing, and such persons duly acknowledged before me the execution of the foregoing instrument of writing to be their act and deed and the act and deed of said corporation.

WITNESS my hand and notarial seal this           day of                   , 2003.

Notary Public

Kentucky, Commonwealth at Large

(Notarial Seal)

My Commission Expires:

STATE OF ILLINOIS	)	SS:
	)
COUNTY OF COOK	)

BE IT REMEMBERED that on this          day of              , 2003, before me, a Notary Public duly commissioned in and for the County and State aforesaid, personally appeared                      ,                           of BNY Midwest Trust Company, a trust company organized and existing under and by virtue of the laws of the State of Illinois, who is personally known to me to be such officer and who is personally known to me to be the same person who executed as an officer the foregoing instrument of writing, and such person duly acknowledged before me the execution of the foregoing instrument of writing to be such officer’s act and deed and the act and deed of said corporation.

WITNESS my hand and notarial seal this         day of                   , 2003.

	Notary Public in and for the County of
	Cook and State of Illinois
	(Notarial Seal)
	My Commission Expires:
This Instrument Prepared by:
James Dimas
LG&E Energy Corp.
220 W. Main Street
Louisville, Kentucky  40202
By
James Dimas
(502) 627-3712

SCHEDULE A

The following property situated, lying and being in the County of Jefferson, State of Kentucky, to wit:

REAL PROPERTY

EX-4.23

EXHIBIT 4.23

30 April, 2003

Kentucky Utilities  

(as Borrower)

Fidelia Corporation

(as Lender) 

LOAN AGREEMENT

Contents

Clause
1.	DEFINITIONS
2.	TERM LOAN
3.	AVAILABILITY OF REQUESTS
4.	INTEREST
5.	REPAYMENT AND PREPAYMENT
6.	PAYMENTS
7.	TERMINATION EVENTS
8.	OPERATIONAL BREAKDOWN
9.	NOTICES
10.	ASSIGNMENT
11.	SEVERABILITY
12.	COUNTERPARTS
13.	LAW

THIS AGREEMENT made on April 30, 2003

Between

KENTUCKY UTILITIES, a Kentucky corporation, as borrower (the Borrower); and

FIDELIA CORPORATION, a Delaware corporation, as lender (the Lender).

Whereas

(A)The Lender and the Borrower hereby enter into an agreement for the provision by the Lender to the Borrower of a loan in the amount of  $100,000,000 (the Loan Amount).

Now it is hereby agreed as follows:

1.Definitions

1.1In this Agreement

Business Day means a day on which banks in New York are generally open

Default Interest Rate means: the rate, as determined by the Lender, applying to the principal element of an overdue amount under Clause 6.3, calculated as the sum of the interest rate in effect immediately before the due date of such amount, plus 1%;

Effective Date shall have the meaning given to it in Clause 2.1;

Final Repayment Date means April 30, 2013;

Interest Payment Date means April 30 and October 30 of each year during the term of this agreement, provided, that:

any Interest Payment Date which is not a Business Day shall be extended to the next succeeding Business Day;

Loan Amount  means $100,000,000;

Maturity Date means the Final Repayment Date;

1

Request means a request for the Loan Amount from the Borrower to the Lender under the terms of clause 3.1;

Termination Event means an event specified as such in Clause 7;

Value Date means the date upon which cleared funds are made available to the Borrower by the Lender pursuant to a Request made in accordance with Clause 3.1. Such date shall be a Business Day as defined herein.

2.Term Loan

2.1This Agreement shall come into effect on April 30, 2003 (the “Effective Date”).

2.2The Lender grants to the Borrower upon the terms and conditions of this Agreement a term loan in an amount of $100,000,000.

2.3The new indebtedness shall be evidenced by a note in substantially the form of Exhibit “A” attached hereto.

3.Availability of Requests

3.1On the Effective Date, the Borrower will submit a request (the “Request”) to the Lender for the Loan Amount, such Request specifying the Value Date, the Maturity Date and the bank account to which payment is to be made. The Request shall be submitted to the Lender by the Borrower and delivered in accordance with Clause 9.3.

4.Interest

4.1The rate of interest on the Loan Amount is 4.55%.

4.2Interest shall accrue on the basis of a 360-day year consisting of twelve 30 day months upon the Loan Amount.

4.3Interest shall be payable in arrears on each Interest Payment Date.

2

5.Repayment and Prepayment

5.1The Borrower shall repay the Loan Amount together with all interest accrued thereon and all other amounts due from the Borrower hereunder on the Final Repayment Date, whereupon this Agreement shall be terminated.

5.2On any Interest Payment Date, and with at least three business day’s prior written notice, the Borrower shall be entitled to prepay any amount of the loan outstanding, provided such payment is not less than $1,000,000 and, provided further, the Borrower shall pay a prepayment charge equal to the present value of the difference between (i) the interest payable provided in this loan agreement and (ii) the interest payable at the prevailing interest rate at the time of prepayment, for the period from the date of prepayment through the Maturity Date,  which difference, if negative, shall be deemed to be zero. The present value will be determined using the prevailing interest rate at the time of the prepayment as the discount rate.

5.3A certificate from the Lender as to the amount due at any time from the Borrower to the Lender under this Agreement shall, in the absence of manifest error, be conclusive.

6.Payments

6.1All payments of principal to be made to the Lender by the Borrower shall be made on the Final Repayment Date, or on an Interest Payment Date under Clause (5.2) to such account as the Lender shall have specified.

6.2Interest shall be payable in arrears on each Interest Payment Date.

6.3If and to the extent that full payment of any amount due hereunder is not made by the Borrower on the due date then, interest shall be charged at the Default Interest Rate on such overdue amount from the date of such default to the date payment is received by the Lender.

3

7.Termination Events

7.1The Borrower shall notify the Lender of any Event of Default (and the steps, if any, being taken to remedy it) promptly upon becoming aware of it.

7.2The following shall constitute an Event of Default hereunder:

7.2.1Default is made by the Borrower in the payment of any sum due under this Agreement and such default continues for a period of 10 Business Days;

7.2.2Bankruptcy proceedings are initiated against the Borrower;

7.2.3The Borrower leaves the E.ON Group (i.e. the companies consolidated in EON AG’s balance sheet);

7.2.4Securities and Exchange Commission or Public Utility Holding Company Act (PUHCA) requirements prohibit the transactions hereunder.

If a Termination Event occurs under Clause (7.2.2) of this section, the Loan Amount outstanding together with interest will become due and payable immediately.

If a Termination Event occurs according to Clauses (7.2.1) or (7.2.3) or (7.2.4) of this Section, Lender shall at its discretion grant Borrower a reasonable grace period unless such grace period shall be detrimental to the Lender. If the Termination Event is uncured at the expiration of such period, the Loan Amount outstanding together with interest will become due and payable immediately.

8.Operational Breakdown

8.1The Borrower is not liable for any damages incurred by the Lender and the Lender is not liable for any damages incurred by the Borrower caused by Acts of God or other circumstances incurred by one party for which the other party cannot be held responsible (i.e. power outages, strikes, lock-outs, domestic and foreign acts of government and the like).

4

9.Notices

9.1Each communication to be made in respect of this Agreement shall be made in writing but, unless otherwise stated, may be made by facsimile transmission or letter.

9.2Communications to the Borrower shall be addressed to: Kentucky Utilities, 220 W. Main St., Louisville, KY 40202, Attn: Treasurer fax# (502)627-4742 except for confirmations which should be sent to the attention of Mimi Kelly.

9.3Communications to the Lender shall be addressed to: Fidelia Corporation, 300 Delaware Avenue, Suite 545, Wilmington, Delaware 19801, fax# (302) 427-5913, Attn: President

10.Assignment

10.1The Lender may at any time assign, novate or otherwise transfer all or any part of its rights and obligations under this Agreement to any affiliate of the Lender.

11.Severability

11.1If any of the provisions of this Agreement becomes invalid, illegal or unenforceable in any respect under any law, the validity, legality and enforceability of the remaining provisions shall not in any way be affected or impaired.

12.Counterparts

12.1This Agreement may be executed in any number of counterparts that shall together constitute one Agreement. Any party may enter into an Agreement by signing any such counterpart.

5

13.Law

13.1This Agreement shall be governed by and construed for all purposes in accordance with the laws of Delaware.

IN WITNESS whereof the parties have executed this Agreement the day and year first above written.

SIGNED by	)
for and on behalf of	)
Kentucky Utilities	)
in the presence of:	)
SIGNED by	)
Udo Koch, President	)
Fidelia Corporation	)
SIGNED by	)

6

EXHIBIT “A”

PROMISSORY NOTE

U.S. $100,000,000.00 Louisville, Kentucky, April 30, 2003

Kentucky Utilities, for value received, hereby promises to pay to the order of FIDELIA Corporation (“FIDELIA”), in lawful money of the United States of America (in freely transferable U.S. dollars and in same day funds), in accordance with the method of payment specified in that certain Kentucky Utilities Loan Agreement dated as of April 30, 2003, between FIDELIA and Kentucky Utilities (“the Agreement”), the principal sum of $100,000,000.00, which amount shall be payable at such times as provided in the Agreement.

Kentucky Utilities promises also to pay interest on the unpaid principal amount hereof in like money and in like manner at the rates which shall be determined in accordance with the provisions of the Agreement, said interest to be payable at the time provided for in the Agreement.  This Note is referred to in the Agreement and is entitled to the benefits thereof and the security contemplated thereby.  This Note evidences a loan made by FIDELIA, during such time as such loan is being maintained.  This Note is subject to prepayment as specified in the Agreement.  In case Kentucky Utilities defaults on the loan, the principal and accrued interest on this Note may be declared to be due and payable in the manner and with the effect provided in the Agreement.

Kentucky Utilities hereby waives presentment, demand, protest or notice of any kind in connection with this Note.

This Note shall be governed and construed and interpreted in accordance with the laws of the State of Delaware.

Kentucky Utilities
By:
	Daniel K. Arbough
	Director of Corporate Finance & Treasurer
By:

7

EX-4.24

EXHIBIT 4.24

30 April, 2003

Louisville Gas and Electric Company
(as Borrower)

Fidelia Corporation
(as Lender) 

LOAN AGREEMENT

Contents

Clause

1.	DEFINITIONS
2.	TERM LOAN
3.	AVAILABILITY OF REQUESTS
4.	INTEREST
5.	REPAYMENT AND PREPAYMENT3
6.	PAYMENTS
7.	TERMINATION EVENTS
8.	OPERATIONAL BREAKDOWN
9.	NOTICES
10.	ASSIGNMENT
11.	SEVERABILITY
12.	COUNTERPARTS
13.	LAW

THIS AGREEMENT made on April 30, 2003

Between

LOUISVILLE GAS AND ELECTRIC COMPANY, a Kentucky corporation, as borrower (the Borrower); and

FIDELIA CORPORATION, a Delaware corporation, as lender (the Lender).

Whereas

(A)The Lender and the Borrower hereby enter into an agreement for the provision by the Lender to the Borrower of a loan in the amount of  $100,000,000 (the Loan Amount).

Now it is hereby agreed as follows:

1.Definitions

1.1In this Agreement

Business Day means a day on which banks in New York are generally open

Default Interest Rate means: the rate, as determined by the Lender, applying to the principal element of an overdue amount under Clause 6.3, calculated as the sum of the interest rate in effect immediately before the due date of such amount, plus 1%;

Effective Date shall have the meaning given to it in Clause 2.1;

Final Repayment Date means April 30, 2013;

Interest Payment Date means April 30 and October 30 of each year during the term of this agreement, provided, that:

any Interest Payment Date which  is not a Business Day shall be extended to the next succeeding Business Day;

Loan Amount  means $100,000,000;

Maturity Date means the Final Repayment Date;

1

Request means a request for the Loan Amount from the Borrower to the Lender under the terms of clause 3.1;

Termination Event  means an event specified as such in Clause 7;

Value Date means the date upon which cleared funds are made available to the Borrower by the Lender pursuant to a Request made in accordance with Clause 3.1. Such date shall be a Business Day as defined herein.

2.Term Loan

2.1This Agreement shall come into effect on April 30, 2003 (the “Effective Date”).

2.2The Lender grants to the Borrower upon the terms and conditions of this Agreement a term loan in an amount of $100,000,000.

2.3The new indebtedness shall be evidenced by a note in substantially the form of Exhibit “A” attached hereto.

3.Availability of Requests

3.1On the Effective Date, the Borrower will submit a request (the “Request”) to the Lender for the Loan Amount, such Request specifying the Value Date, the Maturity Date and the bank account to which payment is to be made. The Request shall be submitted to the Lender by the Borrower and delivered in accordance with Clause 9.3.

4.Interest

4.1The rate of interest on the Loan Amount is 4.55%.

4.2Interest shall accrue on the basis of a 360-day year consisting of twelve 30 day months upon the Loan Amount.

4.3Interest shall be payable in arrears on each Interest Payment Date.

2

5.Repayment and Prepayment

5.1The Borrower shall repay the Loan Amount together with all interest accrued thereon and all other amounts due from the Borrower hereunder on the Final Repayment Date, whereupon this Agreement shall be terminated.

5.2On any Interest Payment Date, and with at least three business day’s prior written notice, the Borrower shall be entitled to prepay any amount of the loan outstanding, provided such payment is not less than $1,000,000 and, provided further, the Borrower shall pay a prepayment charge equal to the present value of the difference between (i) the interest payable provided in this loan agreement and (ii) the interest payable at the prevailing interest rate at the time of prepayment, for the period from the date of prepayment through the Maturity Date,  which difference, if negative, shall be deemed to be zero. The present value will be determined using the prevailing interest rate at the time of the prepayment as the discount rate.

5.3A certificate from the Lender as to the amount due at any time from the Borrower to the Lender under this Agreement shall, in the absence of manifest error, be conclusive.

6.Payments

6.1All payments of principal to be made to the Lender by the Borrower shall be made on the Final Repayment Date, or on an Interest Payment Date under Clause (5.2) to such account as the Lender shall have specified.

6.2Interest shall be payable in arrears on each Interest Payment Date.

6.3If and to the extent that full payment of any amount due hereunder is not made by the Borrower on the due date then, interest shall be charged at the Default Interest Rate on such overdue amount from the date of such default to the date payment is received by the Lender.

3

7.Termination Events

7.1The Borrower shall notify the Lender of any Event of Default (and the steps, if any, being taken to remedy it) promptly upon becoming aware of it.

7.2The following shall constitute an Event of Default hereunder:

7.2.1Default is made by the Borrower in the payment of any sum due under this Agreement and such default continues for a period of 10 Business Days;

7.2.2Bankruptcy proceedings are initiated against the Borrower;

7.2.3The Borrower leaves the E.ON Group (i.e. the companies consolidated in EON AG’s balance sheet);

7.2.4Securities and Exchange Commission or Public Utility Holding Company Act (PUHCA) requirements prohibit the transactions hereunder.

If a Termination Event occurs under Clause (7.2.2) of this section, the Loan Amount outstanding together with interest will become due and payable immediately.

If a Termination Event occurs according to Clauses (7.2.1) or (7.2.3) or (7.2.4) of this Section, Lender shall at its discretion grant Borrower a reasonable grace period unless such grace period shall be detrimental to the Lender. If the Termination Event is uncured at the expiration of such period, the Loan Amount outstanding together with interest will become due and payable immediately.

8.Operational Breakdown

8.1The Borrower is not liable for any damages incurred by the Lender and the Lender is not liable for any damages incurred by the Borrower caused by Acts of God or other circumstances incurred by one party for which the other party cannot be held responsible (i.e. power outages, strikes, lock-outs, domestic and foreign acts of government and the like).

4

9.Notices

9.1Each communication to be made in respect of this Agreement shall be made in writing but, unless otherwise stated, may be made by facsimile transmission or letter.

9.2Communications to the Borrower shall be addressed to: Louisville Gas and Electric Company., 220 W. Main St., Louisville, KY 40202, Attn: Treasurer fax# (502)627-4742 except for confirmations which should be sent to the attention of Mimi Kelly.

9.3Communications to the Lender shall be addressed to: Fidelia Corporation, 300 Delaware Avenue, Suite 545, Wilmington, Delaware 19801, fax# (302) 427-5913, Attn: President

10.Assignment

10.1The Lender may at any time assign, novate or otherwise transfer all or any part of its rights and obligations under this Agreement to any affiliate of the Lender.

11.Severability

11.1If any of the provisions of this Agreement becomes invalid, illegal or unenforceable in any respect under any law, the validity, legality and enforceability of the remaining provisions shall not in any way be affected or impaired.

12.Counterparts

12.1This Agreement may be executed in any number of counterparts that shall together constitute one Agreement. Any party may enter into an Agreement by signing any such counterpart.

5

13.Law

13.1This Agreement shall be governed by and construed for all purposes in accordance with the laws of Delaware.

IN WITNESS whereof the parties have executed this Agreement the day and year first above written.

SIGNED by	)
for and on behalf of	)
Louisville Gas & Electric Co.	)
in the presence of:	)
SIGNED by	)
Udo Koch, President	)
Fidelia Corporation	)
SIGNED by	)

6

EXHIBIT “A”

PROMISSORY NOTE

U.S. $100,000,000.00 Louisville, Kentucky, April 30, 2003

Louisville Gas and Electric Company,  for value received, hereby promises to pay to the order of FIDELIA Corporation (“FIDELIA”), in lawful money of the United States of America (in freely transferable U.S. dollars and in same day funds), in accordance with the method of payment specified in that certain Louisville Gas and Electric Company Loan Agreement dated as of April 30, 2003, between FIDELIA and Louisville Gas and Electric Company (“the Agreement”), the principal sum of $100,000,000.00, which amount shall be payable at such times as provided in the Agreement.

Louisville Gas and Electric Company promises also to pay interest on the unpaid principal amount hereof in like money and in like manner at the rates which shall be determined in accordance with the provisions of the Agreement, said interest to be payable at the time provided for in the Agreement.  This Note is referred to in the Agreement and is entitled to the benefits thereof and the security contemplated thereby.  This Note evidences a loan made by FIDELIA, during such time as such loan is being maintained.  This Note is subject to prepayment as specified in the Agreement.  In case Louisville Gas and Electric Company defaults on the loan, the principal and accrued interest on this Note may be declared to be due and payable in the manner and with the effect provided in the Agreement.

Louisville Gas and Electric Company hereby waives presentment, demand, protest or notice of any kind in connection with this Note.

This Note shall be governed and construed and interpreted in accordance with the laws of the State of Delaware.

7

Louisville Gas and Electric Company
By:
	Daniel K. Arbough
	Director of Corporate Finance & Treasurer
By:

8

EX-4.25

EXHIBIT 4.25

January 15, 2004

Kentucky Utilities Company
(as Borrower)

Fidelia Corporation
(as Lender)

LOAN AGREEMENT

Contents

Clause

1.	DEFINITIONS
2.	TERM LOAN
3.	AVAILABILITY OF REQUESTS
4.	INTEREST
5.	REPAYMENT AND PREPAYMENT
6.	PAYMENTS
7.	TERMINATION EVENTS
8.	OPERATIONAL BREAKDOWN
9.	NOTICES
10.	ASSIGNMENT
11.	SEVERABILITY
12.	COUNTERPARTS
13.	LAW

THIS AGREEMENT made on January 15, 2004

Between

KENTUCKY UTILITIES COMPANY, a Kentucky corporation, as borrower (the Borrower); and

FIDELIA CORPORATION, a Delaware corporation, as lender (the Lender).

Whereas

(A)The Lender and the Borrower hereby enter into an agreement for the provision by the Lender to the Borrower of a loan in the amount of $50,000,000 (the Loan Amount).

Now it is hereby agreed as follows:

1.Definitions

1.1In this Agreement

Business Day means a day on which banks in New York are generally open

Default Interest Rate means: the rate, as determined by the Lender, applying to the principal element of an overdue amount under Clause 6.3, calculated as the sum of the interest rate in effect immediately before the due date of such amount, plus 1%;

Effective Date shall have the meaning given to it in Clause 2.1;

Final Repayment Date means January 16, 2012;

Interest Payment Date means January 15th and July 15th of each year during the term of this agreement, provided, that:

any Interest Payment Date which is not a Business Day shall be extended to the next succeeding Business Day;

Loan Amount means $50,000,000;

Maturity Date means the Final Repayment Date;

1

Request means a request for the Loan Amount from the Borrower to the Lender under the terms of clause 3.1;

Termination Event means an event specified as such in Clause 7;

Value Date means the date upon which cleared funds are made available to the Borrower by the Lender pursuant to a Request made in accordance with Clause 3.1. Such date shall be a Business Day as defined herein.

2.Term Loan

2.1This Agreement shall come into effect on January 15, 2004 (the “Effective Date”).

2.2The Lender grants to the Borrower upon the terms and conditions of this Agreement a term loan in an amount of $50,000,000.

2.3The new indebtedness shall be evidenced by a note in substantially the form of Exhibit “A” attached hereto.

3.Availability of Requests

3.1On the Effective Date, the Borrower will submit a request (the “Request”) to the Lender for the Loan Amount, such Request specifying the Value Date, the Maturity Date and the bank account to which payment is to be made. The Request shall be submitted to the Lender by the Borrower and delivered in accordance with Clause 9.3.

4.Interest

4.1The rate of interest on the Loan Amount is 4.39%.

4.2Interest shall accrue on the basis of a 360-day year consisting of twelve 30 day months upon the Loan Amount.

4.3Interest shall be payable in arrears on each Interest Payment Date.

2

5.Repayment and Prepayment

5.1The Borrower shall repay the Loan Amount together with all interest accrued thereon and all other amounts due from the Borrower hereunder on the Final Repayment Date, whereupon this Agreement shall be terminated.

5.2On any Interest Payment Date, and with at least three business day’s prior written notice, the Borrower shall be entitled to prepay any amount of the loan outstanding, provided such payment is not less than $1,000,000 and, provided further, the Borrower shall pay a prepayment charge equal to the present value of the difference between (i) the interest payable provided in this loan agreement and (ii) the interest payable at the prevailing interest rate at the time of prepayment, for the period from the date of prepayment through the Maturity Date,  which difference, if negative, shall be deemed to be zero. The present value will be determined using the prevailing interest rate at the time of the prepayment as the discount rate.

5.3A certificate from the Lender as to the amount due at any time from the Borrower to the Lender under this Agreement shall, in the absence of manifest error, be conclusive.

6.Payments

6.1All payments of principal to be made to the Lender by the Borrower shall be made on the Final Repayment Date, or on an Interest Payment Date under Clause (5.2) to such account as the Lender shall have specified.

6.2Interest shall be payable in arrears on each Interest Payment Date.

6.3If and to the extent that full payment of any amount due hereunder is not made by the Borrower on the due date then, interest shall be charged at the Default Interest Rate on such overdue amount from the date of such default to the date payment is received by the Lender.

3

7.Termination Events

7.1The Borrower shall notify the Lender of any Event of Default (and the steps, if any, being taken to remedy it) promptly upon becoming aware of it.

7.2The following shall constitute an Event of Default hereunder:

7.2.1Default is made by the Borrower in the payment of any sum due under this Agreement and such default continues for a period of 10 Business Days;

7.2.2Bankruptcy proceedings are initiated against the Borrower;

7.2.3The Borrower leaves the E.ON Group (i.e. the companies consolidated in EON AG’s balance sheet);

7.2.4Securities and Exchange Commission or Public Utility Holding Company Act (PUHCA) requirements prohibit the transactions hereunder.

If a Termination Event occurs under Clause (7.2.2) of this section, the Loan Amount outstanding together with interest will become due and payable immediately.

If a Termination Event occurs according to Clauses (7.2.1) or (7.2.3) or (7.2.4) of this Section, Lender shall at its discretion grant Borrower a reasonable grace period unless such grace period shall be detrimental to the Lender. If the Termination Event is uncured at the expiration of such period, the Loan Amount outstanding together with interest will become due and payable immediately.

8.Operational Breakdown

8.1The Borrower is not liable for any damages incurred by the Lender and the Lender is not liable for any damages incurred by the Borrower caused by Acts of God or other circumstances incurred by one party for which the other party cannot be held responsible (i.e. power outages, strikes, lock-outs, domestic and foreign acts of government and the like).

4

9.Notices

9.1Each communication to be made in respect of this Agreement shall be made in writing but, unless otherwise stated, may be made by facsimile transmission or letter.

9.2Communications to the Borrower shall be addressed to: Kentucky Utilities Company, 220 W. Main St., Louisville, KY 40202, Attn: Treasurer fax# (502) 627-4742 except for confirmations which should be sent to the attention of Mimi Kelly.

9.3Communications to the Lender shall be addressed to: Fidelia Corporation, 919 N. Market Street, Suite 504, Wilmington, Delaware 19801, fax# (302) 778-5014, Attn: President.

10.Assignment

10.1The Lender may at any time assign, novate or otherwise transfer all or any part of its rights and obligations under this Agreement to any affiliate of the Lender.

11.Severability

11.1If any of the provisions of this Agreement becomes invalid, illegal or unenforceable in any respect under any law, the validity, legality and enforceability of the remaining provisions shall not in any way be affected or impaired.

12.Counterparts

12.1This Agreement may be executed in any number of counterparts that shall together constitute one Agreement. Any party may enter into an Agreement by signing any such counterpart.

5

13.          Law

13.1         This Agreement shall be governed by and construed for all purposes in accordance with the laws of Delaware.

In witness whereof the parties have executed this Agreement the day and year first above written.

SIGNED by	)
for and on behalf of	)
Kentucky Utilities	)
SIGNED by	)
Udo Koch, President	)
Fidelia Corporation	)

6

EX-4.26

EXHIBIT 4.26

LOAN AND SECURITY AGREEMENT

Dated as of August 15, 2003

between

KENTUCKY UTILITIES COMPANY

and

FIDELIA CORPORATION

TABLE OF CONTENTS

1.	DEFINITIONS
	1.1	General Terms
	1.2	Accounting Terms
	1.3	Others Terms Defined in the Code
	1.4	Computation of Time Periods
	1.5	Headings and References
2.	TERM LOANS
	2.1	Loans
	2.2	Request for Purchase
	2.3	Interest
	2.4	Notes
	2.5	Closings
	2.6	Payments
	2.7	Term of This Agreement
3.	CONDITIONS OF ADVANCES
	3.1	Documents
	3.2	No Default
	3.3	Reaffirmation of Representations and Warranties
4.	COLLATERAL
	4.1	Security Interest
	4.2	Appointment of the Lender as the Borrower’s Attorney-in-Fact
	4.3	Preservation of Collateral and Perfection of Security Interests
	4.4	Reasonable Care
	4.5	Termination of Security Interest and Liens
5.	REPRESENTATIONS AND WARRANTIES
	5.1	Existence
	5.2	Authority
	5.3	Binding Effect
	5.4	Financial Statements
	5.5	Collateral
	5.6	Chief Executive Office Jurisdiction of Incorporation
	5.7	Other Corporate Names
	5.8	Margin Security
	5.9	Survival of Warranties
	5.10	Compliance with Laws and Regulations
6.	COVENANTS
	6.1	Financial Statements; Notices; Reports
	6.2	Books, Records and Inspections
	6.3	Conduct of Business
7.	EVENTS OF DEFAULT, RIGHTS AND REMEDIES OF LENDER
	7.1	Events of Default

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	7.2		Rights and Remedies Generally
	7.3		Waiver of Demand
	7.4		Marshalling; Payments Set Aside
8.	SUBORDINATION
	8.1		Agreement to Subordinate
	8.2		Administration of Collateral
	8.3		Delivery of Proceeds of Collateral
	8.4		Agreement Not to Contest
	8.5		Release of Collateral
	8.6		Release of Security Interest
	8.7		Obligations under this Agreement Not Affected
	8.8		Bankruptcy
	8.9		Third Party Beneficiary
9.	MISCELLANEOUS
	9.1		Amendments and Waivers
	9.2		Severability
	9.3		Notices
	9.4		Counterparts
	9.5		Prior Agreements
	9.6		Successors and Assigns
	9.7		CHOICE OF LAW
			EXHIBITS
EXHIBIT A		—		Form of Note

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LOAN AND SECURITY AGREEMENT

This LOAN AND SECURITY AGREEMENT, dated as of August 15, 2003 (this “Agreement”), is made between KENTUCKY UTILITIES COMPANY, a Kentucky and Virginia corporation, as borrower (the “Borrower”), and FIDELIA CORPORATION, a Delaware corporation, as lender (the “Lender”).

W I T N E S S E T H:

WHEREAS, the Borrower has requested that the Lender provide the Borrower with term loans;

WHEREAS, to induce the Lender to make such term loans available to the Borrower, the Borrower has agreed to secure its obligations to the Lender by granting the Lender a security interest in, and lien upon, the Collateral (as defined herein); and

WHEREAS, the Lender is willing to make such term loans available to the Borrower  upon the terms and conditions set forth in this Agreement;

NOW, THEREFORE, in consideration of the foregoing and the mutual agreements contained in this Agreement, the Borrower and the Lender agree as follows:

1.DEFINITIONS.

1.1          General Terms.  When used in this Agreement, the following terms have the following meanings (such meanings to be equally applicable to both the singular and plural forms of the terms defined):

“Affiliate”, with respect to any Person, means another Person (i) that directly or indirectly, through one or more intermediaries, controls or is controlled by or is under common control with such Person, (ii) that directly or beneficially owns or holds 5% or more of any class of the voting stock of such Person or (iii) 5% or more of the voting stock (or in the case of a Person that is not a corporation, 5% or more of the equity interest) of which is owned directly or beneficially or held by such Person.

“Agreement” has the meaning set forth in the preamble.

“Authorized Officer” means at any time an individual whose signature has been certified to the Lender on behalf of the Borrower by a certificate now or hereafter executed on behalf of the Borrower and delivered to the Lender and whose authority has not been revoked prior to such time.

“Bond Trustee” means U.S. Bank National Association, as successor trustee under the First Mortgage Bond Indenture, or any successor trustee thereunder.

“Borrower” has the meaning set forth in the preamble.

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“Business Day” means a day (other than a Saturday or Sunday) on which banks are open for business in Louisville, Kentucky and Wilmington, Delaware.

“Code” means the Uniform Commercial Code of the Commonwealth of Kentucky as in effect on the Closing Date.

“Collateral” has the meaning set forth in Section 4.1.

“Default” means any event that, with lapse of time or notice or lapse of time and notice, will constitute an Event of Default if it continues uncured.

“Dollars” and the “$” each means lawful money of the United States of America.

“Equipment” has the meaning set forth in the Code and includes, without limitation, any and all of the Borrower’s now owned or hereafter acquired machinery, equipment, furniture, furnishings and all tangible personal property similar to any of the foregoing (other than Inventory), together with all improvements, accessions and appurtenances thereto and any proceeds of any of the foregoing, including insurance proceeds and condemnation awards, excluding, however, any Equipment which is not subject to a Lien now or at any time hereafter pursuant to the First Mortgage Bond Indenture.

“Event of Default” means the occurrence or existence of any one of more of the events described in Section 7.1.

“First Mortgage Bond Indenture” means the Indenture of Trust dated as of May 1, 1947 from the Borrower to the Bond Trustee, and any and all supplemental indentures thereof, as further amended and supplemented from time to time.

“GAAP” means generally accepted accounting principles, as in effect in the United States from time to time.

“Governmental Authority” means any nation or government, any federal, state, local or other political subdivision thereof and any entity exercising executive, legislative, judicial, regulatory or administrative functions of or pertaining to government.

“Lender” has the meaning set forth in the preamble.

“Liabilities” means all of the Borrower’s liabilities, obligations, and indebtedness to the Lender for monetary amounts, whether now or hereafter owing, arising, due or payable under this Agreement and the Notes howsoever evidenced, created, incurred, acquired, or owing.

“Lien” means any mortgage, deed of trust, pledge, hypothecation, assignment, collateral deposit arrangement, security interest, encumbrance for the payment of money, lien (statutory or other), preference, right of setoff, priority or other security agreement or preferential arrangement of any kind or nature whatsoever, including, without limitation, any conditional sale or other title retention agreement, or the interest of a lessor under a capital lease.

“Loan” has the meaning set forth in Section 2.1.

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 “Material Adverse Effect” means a material adverse effect upon (i) the business, assets,  properties or condition (financial or otherwise), or results of operations of the Borrower, or (ii) upon the ability of the Borrower to perform or cause to be performed any of its obligations under this Agreement or the rights or remedies of the Lender under this Agreement.

“Note” has the meaning set forth in Section 2.4.

“Permitted Lien” means Liens created under or in connection with the First Mortgage Bond Indenture and Liens permitted by the First Mortgage Bond Indenture.

“Person” means any natural person, firm, enterprise, institution, corporation, association, partnership, trust, unincorporated organization, sole proprietorship, joint venture, limited liability company or Governmental Authority.

1.2          Accounting Terms.  Any accounting terms used in this Agreement which are not specifically defined in this Agreement have the meanings customarily given them in accordance with GAAP.

1.3          Others Terms Defined in the Code.  All other terms contained in this Agreement (and which are not otherwise specifically defined in the Agreement) have the meanings provided by the Code to the extent the same are used or defined in the Code.

1.4          Computation of Time Periods.  In this Agreement in the computation of periods of time from a specified date to a later specified date, the words “from” or “commencing on” means “from and including” and the words “to,” “through,” “ending on” and “until” each mean “to but excluding.”

1.5          Headings and References.  Section and other headings are for reference only, and shall not affect the interpretation or meaning of any provision of this Agreement.  Any Section or clause references are to this Agreement, unless otherwise specified.  References in this Agreement or any other agreement include this Agreement and other agreements as the same may be amended, restated, supplemented or otherwise modified from time to time pursuant to the provisions hereof or thereof.  A reference to any law, statute or regulation shall mean that law, statute or regulation as it may be amended, supplemented or otherwise modified from time to time, and any successor law, statute or regulation.

2.TERM LOANS.

2.1          Loans.  The Lender, at its discretion, may make available to the Borrower term loans (the “Loans”) from time to time pursuant to this Agreement, upon telephonic or written communication of a borrowing request from the Borrower as provided in Section 2.2.

2.2          Request for Loans.  The Borrower may from time to time make requests for Loans (each such request being a “Borrowing Notice”) hereunder.  Each Borrowing Notice shall (i) specify the principal amount of the Loan requested, (ii) specify the final maturity not to be less than one year from the Borrowing Date, (iii) specify the proposed date for the borrowing of the Loan (the “Borrowing Date”), (iv) specify whether the Loan shall bear interest at a fixed rate or a floating rate, (v) specify the dates on which interest is to be paid, and (vi) specify the

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number of the account and the name and address of the depository institution to which the proceeds of the Loan are to be transferred on the Borrowing Date.  Each Borrowing Notice may be given telephonically or in writing.  Each such request for a Loan is subject to acceptance by the Lender, in its sole discretion.

2.3          Interest.

(A)          Interest Rate.  The interest rate payable by the Borrower on any Loan shall be set at such interest rate as the Borrower and the Lender shall agree, but in no event greater than the lowest of (i) the effective cost of capital of E.ON AG, (ii) the effective cost of capital of the Lender and (iii) the Borrower’s effective cost of capital determined by reference to the effective cost of a direct borrowing by the Borrower from a nonassociate for a comparable term loan that could be entered into at such time.  Such interest rate may be determined as a fixed interest rate or a floating rate, as specified by the Borrower in the Borrowing Notice.

(B)          Interest Payments.  Accrued but unpaid interest on each Loan is payable in arrears on dates agreed to by the Borrower and the Lender as specified in the Borrowing Notice and upon payment in full of such Loan.  Interest on the Loans is computed on the basis of a 360-day year consisting of twelve 30-day months.

(C)          Highest Lawful Rate.  In no contingency or event whatsoever will interest charged on the Loans, however, such interest may be characterized or computed, exceed the highest rate permissible under any law which a court of competent jurisdiction, in a final determination, deems applicable to the Loans. In the event that such a court determines that the Lender has received interest under the Loans in excess of the highest rate applicable to the Loans, any such excess interest collected by the Lender is deemed to have been a repayment of principal and will be so applied.

2.4          Notes.  On each Borrowing Date, the Borrower shall issue to the Lender a promissory note (the “Notes”) in a principal amount equal to the principal amount of the Loan to be made on such Borrowing Date; to bear interest on the unpaid balance thereof from the date thereof at the rate per annum as determined in accordance with Section 2.3(A); and to be substantially in the form of Exhibit A attached hereto.  The term “Notes” as used herein shall include each Note delivered pursuant to this Agreement and each Note delivered in substitution or exchange for any such Note.

2.5          Closings.  Not later than 11:30 A.M. (New York City local time) on the Borrowing Date for any Loan, the Borrower will deliver to the Lender at the offices of the Lender, a Note dated the Borrowing Date, evidencing the Loan to be made on such Borrowing Date, against payment of the Loan proceeds by transfer of immediately available funds for credit to the Borrower’s account specified in the Borrowing Notice.

2.6          Payments.

(A)          Place of Payments.  The Borrower will make each payment under this Agreement and under the Notes not later than 2:00 p.m. (New York time) on the day when due to the Lender at its address set forth in Section 9.3 in immediately available funds.  The Borrower’s

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obligations to the Lender with respect to such payments will be discharged by making such payments to the Lender under this Section 2.6.

(B)          Timing of Payments.  If any payment of any interest or fees owing under this Agreement falls due on a day that is not a Business Day, then such due date is extended to the next following Business Day.

(C)          Optional Prepayments.  On any interest payment date, and with at least three business day’s prior written notice, the Borrower shall be entitled to prepay any amount of the loan outstanding, provided such payment is not less than $1,000,000 and, provided further, the Borrower shall pay a prepayment charge equal to the present value of the difference between (i) the interest payable provided in this loan agreement and (ii) the interest payable at the prevailing interest rate at the time of prepayment, for the period from the date of prepayment through the final maturity date,  which difference, if negative, shall be deemed to be zero. The present value will be determined using the prevailing interest rate at the time of the prepayment as the discount rate.

2.7          Term of This Agreement.  This Agreement shall remain in full force and effect until the second Business Day after the Borrower or the Lender gives notice to the other party hereto stating that it elects to terminate this Agreement.  Notwithstanding the termination of this Agreement, until all of the Loans under this Agreement have been paid in full and all financing arrangements between the Borrower and the Lender under this Agreement have been terminated, all of the Lender’s rights and remedies under this Agreement survive and the Lender is entitled to retain its security interest in and to all existing and future Collateral.

3.CONDITIONS OF ADVANCES.

Notwithstanding any other provisions contained in this Agreement to the contrary, the making of each Loan provided for in this Agreement is conditioned upon the following:

3.1          Documents.  The Lender has received all of the following (or the delivery of such has been waived), each duly executed, in form and substance satisfactory to the Lender, and delivered on or prior to the applicable Borrowing Date:

(i)This Agreement, duly executed by the Borrower.

(ii)The Note, evidencing such Loan, duly executed by the Borrower.

(iii)UCC-1 financing statements listing the Borrower as debtor, and the Lender, as secured party, covering the Collateral.

(iv)Certified copies of all documents evidencing any necessary corporate action, consents and governmental approvals, if any, with respect to this Agreement and the Notes.

(v)A signature authorization certificate for the Borrower.

(vi)Such other documents as the Lender may reasonably request.

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3.2          No Default.  No Default or Event of Default has occurred and is continuing.

3.3          Reaffirmation of Representations and Warranties ..  The representations and warranties contained in Section 5 are true and correct in all material aspects on and as of the Borrowing Date.

4.COLLATERAL.

4.1          Security Interest.  To secure payment of the Liabilities and performance of its obligations under this Agreement and the Notes, the Borrower grants, mortgages, hypothecates and pledges to the Lender a continuing lien upon and security interest in all of the Borrower’s right, title and interest in the Collateral, wherever located, whether now or hereafter existing, owned, licensed, leased (to the extent of the Borrower’s leasehold interest in such property), consigned (to the extent of the Borrower’s ownership interest in such property), arising or acquired, subject, however, in all respects to the provisions of Section 8.  The “Collateral” shall consist of:  (i) the Equipment; (ii) all insurance proceeds of or relating thereto, (iii) all of the Borrower’s books and records relating to any of the foregoing; and (iv) all accessions and additions to, substitutions for, and replacements, products and proceeds of any of the foregoing.

4.2          Appointment of the Lender as the Borrower’s Attorney-in-Fact.  The Borrower irrevocably designates, makes, constitutes and appoints the Lender (and all persons designated by the Lender) as the Borrower’s true and lawful attorney-in-fact, and authorizes the Lender, in the Borrower’s or the Lender’s name, upon the occurrence and during the continuation of an Event of Default, with respect to any item of Collateral or the proceeds of such Collateral, to do all acts and things which are necessary, in the Lender’s sole discretion, to fulfill the Borrower’s obligations under this Agreement.

4.3          Preservation of Collateral and Perfection of Security Interests.  The Borrower will execute and deliver, or cause to be executed and delivered, to the Lender at any time or times after the date of this Agreement at the request of the Lender, all (i) financing statements or (ii) other documents (and, in each case, pay the cost of filing or recording the same in all public offices deemed necessary by the Lender), as the Lender may request, in a form satisfactory to the Lender, to perfect and keep perfected the security interest, and preserve the priority of such security interest, in the Collateral granted by the Borrower to the Lender or to otherwise protect and preserve the Collateral and the Lender’s security interest in the Collateral.  Should the Borrower fail to do so, the Lender is authorized to sign any such financing statements as the Borrower’s agent.  The Borrower further agrees that a carbon, photographic or other reproduction of this Agreement or of a financing statement is sufficient as a financing statement.

4.4          Reasonable Care.  The Lender is deemed to have exercised reasonable care in the custody and preservation of any of the Collateral in its possession if it takes such action for that purpose as the Borrower requests in writing, but the Lender’s failure to comply with any such request will not of itself be deemed a failure to exercise reasonable care.

4.5          Termination of Security Interest and Liens. The Lender’s security interest and other liens in, on and to the Collateral terminates when all the Liabilities have been paid in full and this Agreement has been terminated, at which time the Lender will reassign and redeliver (or

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cause to be reassigned and redelivered) to the Borrower, or to such Person as the Borrower designates, against receipt, such of the Collateral (if any) assigned by the Borrower to the Lender (or otherwise held by the Lender) as has not been sold or otherwise applied by the Lender under the terms of this Agreement and is still held by it under this Agreement, together with appropriate instruments of reassignment and release.  Any such reassignment is without recourse upon or representation or warranty by the Lender and will be at the Borrower’s cost and expense.

5.REPRESENTATIONS AND WARRANTIES.

The Borrower represents and warrants that as of the date of this Agreement and as of each Borrowing Date.

5.1          Existence.  The Borrower is a corporation duly organized, validly existing and in good standing under the laws of the Commonwealth of Kentucky and the Commonwealth of Virginia and is duly qualified as a foreign entity and is in good standing in all jurisdictions where the nature and extent of the business transacted by it or the ownership of its assets makes such qualification necessary, except for those jurisdictions in which the failure so to qualify or to be in good standing would not have a Material Adverse Effect.

5.2          Authority.  The execution and delivery by the Borrower of this Agreement and the Notes and the performance of the Borrower’s obligations under this Agreement and the Notes:  (i) are within the Borrower’s corporate powers; (ii) are duly authorized by the Borrower’s board of directors or other governing body; (iii) are not in contravention of the terms of the Borrower’s certificate of incorporation or bylaws or of any material indenture, agreement or undertaking to which the Borrower is a party or by which the Borrower or any of its property is bound; (iv) does not require any consent, registration or approval of any Governmental Authority, which has not been obtained; (v) does not contravene any material contractual or governmental restriction binding upon the Borrower; and (vi) will not, except as contemplated in this Agreement, result in the imposition of any Lien, claim or encumbrance upon any property of the Borrower under any existing material indenture, mortgage, deed of trust, loan or credit agreement or other material agreement or instrument to which the Borrower is a party or by which it or its property may be bound or affected.

5.3          Binding Effect.  This Agreement and the Notes are the legal, valid and binding obligations of the Borrower and are enforceable against the Borrower in accordance with their respective terms.

5.4          Financial Statements.  The financial statements of the Borrower filed with the Securities and Exchange Commission since December 31, 2001 are in accordance with the books and records of the Borrower and fairly present the financial condition of the Borrower at the dates of such financial statements and the results of operations for the periods indicated (subject, in the case of unaudited financial statements, to normal year-end adjustments), and such financial statements were prepared in conformity with GAAP (other than the absence of notes to such financial statements).

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5.5          Collateral.  Except for Permitted Liens and as otherwise provided in Section 8.5, all of the Collateral is and will continue to be owned by the Borrower free and clear of all Liens, claims and encumbrances.

5.6          Chief Executive Office Jurisdiction of Incorporation.  As of the date hereof, the principal place of business and chief executive office of the Borrower is located at 1 Quality Street, Lexington, Kentucky 40507 and the Borrower has been duly incorporated in the Commonwealth of Kentucky and the Commonwealth of Virginia.

5.7          Other Corporate Names. The Borrower has not used any other corporate or fictitious names in the past five years.

5.8          Margin Security.  The Borrower owns no margin security and none of the proceeds of the Loans advanced under this Agreement will be used for the purpose of purchasing or carrying any margin securities or for the purpose of reducing or retiring any Indebtedness which was originally incurred to purchase any margin securities or for any other purpose not permitted by Regulations T, U or X of the Board of Governors of the Federal Reserve System.

5.9          Survival of Warranties.  All representations contained in this Agreement survive the execution and delivery of this Agreement.

5.10        Compliance with Laws and Regulations.  The execution and delivery by the Borrower of this Agreement and the performance of the Borrower’s obligations under this Agreement and the Notes are not in contravention of any laws.  The Borrower is in compliance with all laws, orders, regulations and ordinances of all federal, foreign, state and local governmental authorities relating to the business, operations and the assets of the Borrower, including, without limitation, Regulations T, U and X of the Board of Governors of the Federal Reserve System, except for laws, orders, regulations and ordinances the violation of which are not likely to have a Material Adverse Effect.

6.COVENANTS.

The Borrower covenants and agrees that, so long as any of the Liabilities remain outstanding:

6.1          Financial Statements; Notices; Reports.  The Borrower will keep, in all material respects, proper books of record and account in which entries will be made of all dealings or transactions of or in relation to the business and affairs of the Borrower, in accordance with GAAP consistently applied.  The Borrower will furnish to the Lender:

(A)          SEC Reports.  Copies of annual reports and quarterly reports filed by the Borrower with the Securities and Exchange Commission on Forms 10-K and 10-Q, within 20 Business Days of the date of filing of such report;

(B)          Default Notices.  As soon as practicable (but in any event not more than two Business Days after any Authorized Officer of the Borrower obtains knowledge of the occurrence of an event or the existence of a circumstance giving rise to a Default or an Event of Default), notice of any and all Defaults or Events of Default;

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(C)          Notice of Change of Name.  Notice in writing to the Lender, as soon as practicable and in any event within five days after the occurrence of any change in the name, address or jurisdiction of incorporation of the Borrower or the location of the books and records of the Borrower; and

(D)          Other Information.  With reasonable promptness, such other business or financial data as the Lender may reasonably request.

The Lender will take reasonable efforts to keep such information, and all information acquired as a result of any inspection conducted in accordance with Section 6.2 (and any other information provided to the Lender under this Agreement), confidential, provided that the Lender may communicate such information (i) in accordance with the Borrower’s written authorization, (ii) to any regulatory authority having jurisdiction over the Lender, (iii) to any other Person in connection with the exercise of the Lender’s rights under this Agreement, (iv) to any Person in any litigation in which the Lender is a party or (v) to any other Person if the Lender believes in its sole discretion that disclosure is necessary in connection with any legal process or informal investigative demand, whether issued by a court, judicial or administrative or legislative body or committee or other governmental authority.  Notwithstanding the foregoing, information will not be deemed to be confidential to the extent such information (a) is available in the public domain, (b) becomes available in the public domain other than as a result of unauthorized disclosure by the Lender or (c) is acquired from a Person not known by the Lender to be in breach of an obligation of secrecy to the Borrower.

6.2          Books, Records and Inspections.  The Lender, or any agent or employee designated by the Lender in writing, has the right, from time to time after the date of this Agreement, to call at the Borrower’s place or places of business (or any other place where the Collateral or any information relating to the Collateral is kept or located) during reasonable business hours and, without unreasonable hindrance or delay, (i) to inspect, audit, check and make copies of and extracts from the Borrower’s books, records, journals, orders, receipts and any correspondence and other data relating to the Borrower’s business or to any transactions between the parties thereto, (ii) to make such verification concerning the Collateral as the Lender may consider reasonable under the circumstances and (iii) to discuss the affairs, finances and business of the Borrower with any officers, employees or directors of the Borrower.

6.3          Conduct of Business.  Except as contemplated in this Agreement, the Borrower will (i) maintain its existence, (ii) continue in, and limit its operations to, the same general lines of business as that presently conducted by it or other businesses reasonably related thereto and (iii) comply with all laws, orders, regulations and ordinances of any federal, foreign, state or local governmental authority, except for such laws, orders, regulations and ordinances the violation of which has no reasonable likelihood of having a Material Adverse Effect.

7.EVENTS OF DEFAULT, RIGHTS AND REMEDIES OF LENDER.

7.1          Events of Default.  If any one or more of the following events (“Events of Default”) occurs:

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(A)          the Borrower fails to pay any of the principal of or interest on the Loans, or any Commitment Fees or other amounts due hereunder, within 10 Business Days after such amounts are due (whether by scheduled maturity, acceleration or otherwise);

(B)          the Borrower fails or neglects to perform, keep or observe any of its covenants, conditions or agreements contained in this Agreement;

(C)          any warranty or representation now or hereafter made by the Borrower under this Agreement is untrue or incorrect in any material respect when made;

(D)          a proceeding under any bankruptcy, reorganization, arrangement of debt, insolvency, readjustment of debt or receivership law or statute is filed by or against the Borrower, the Borrower makes an assignment for the benefit of creditors or the Borrower takes any requisite action to authorize any of the foregoing and, in the case of an involuntary proceeding filed against the Borrower, such proceeding is not discharged or dismissed within 30 days;

(E)           the Borrower voluntarily or involuntarily dissolves or is dissolved;

(F)           the Borrower becomes insolvent or fails generally to pay its debts as they become due;

(G)          the Lender shall cease to have a valid, perfected security interest in all or any material portion of the Collateral; or

(H)          E.ON AG shall cease to own, directly or indirectly, at least 80% of the voting capital stock of the Borrower;

then the Lender, upon notice to the Borrower, may declare the Loans to be immediately due and payable, whereupon the Loans will become immediately due and payable; provided, that if an Event of Default described in Section 7.1(D) exists or occurs, the Loans shall automatically, without notice of any kind, become immediately due and payable.

7.2          Rights and Remedies Generally.  Subject to the subordination provisions of Section 8, upon the occurrence and continuance of an Event of Default, the Lender has, in addition to any other rights and remedies contained in this Agreement, all of the rights and remedies of a secured party under the Code or other applicable laws, all of which rights and remedies are cumulative, and none exclusive, to the extent permitted by law.  Any single or partial exercise by the Lender of any right or remedy for a default or breach of any term, covenant, condition or agreement in this Agreement does not affect its rights and does not waive, alter, affect, or prejudice any other right or remedy to which the Lender may be lawfully entitled for the same default or breach.

7.3          Waiver of Demand.  Demand, presentment, protest and notice of nonpayment are waived by the Borrower.  The Borrower also waives the benefit of all valuation, appraisal and exemption laws.

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7.4          Marshalling; Payments Set Aside.  The Lender is under no obligation to marshall any assets in favor of the Borrower or any other party or against or in payment of any or all of the Liabilities.  To the extent that the Borrower makes a payment or payments to the Lender or the Lender enforces its security interests or exercises its rights of setoff, and such payment or payments or the proceeds of such enforcement or setoff or any part thereof are subsequently invalidated, declared to be fraudulent or preferential, set aside and/or required to be repaid to a trustee, receiver or any other party under any bankruptcy law, state or federal law, common law or equitable cause, then to the extent of such recovery, the obligation or part thereof originally intended to be satisfied will be revived and continue in full force and effect as if such payment had not been made or such enforcement or setoff had not occurred.

8.SUBORDINATION.

8.1          Agreement to Subordinate.

(A)          Terms of Subordination.  The Lender and the Borrower agree that the lien granted by the Borrower hereunder to secure the Liabilities is subordinate, to the extent and in the manner set forth in this Agreement, to the lien of the First Mortgage Bond Indenture and any and all of the bonds outstanding from time to time thereunder (the “Senior Obligations”).  Notwithstanding the order or time of creation, acquisition, attachment, or the order, time, or manner of perfection, or the order or time of filing or recordation of any document or instrument, or other method of perfecting a security interest or Lien on and against any of the Collateral or other assets of the Borrower, the Lender agrees that any Lien or security interest now or hereafter existing in and to the Collateral in favor of the Lender shall be and at all times remain subject and subordinate in all respects to any Lien or security interest which may now or hereafter at any time or from time to time be granted pursuant to the First Mortgage Bond Indenture on or in any or all of the Collateral as security for the Senior Obligations.

(B)          Further Assurances.  The Lender and the Borrower will, at the Borrower’s expense and at any time and from time to time, promptly execute and deliver all further instruments and documents, and take all further action, that may be necessary, or that the Bond Trustee may reasonably request, in order to protect any right or interest granted or purported to be granted by this Agreement or to enable the Bond Trustee to exercise and enforce its rights and remedies under this Agreement.

8.2          Administration of Collateral.  The Bond Trustee shall have complete and sole discretion in, and shall not be liable to the Lender for, determining how, when and in what manner the Bond Trustee administers the Senior Obligations or forecloses or otherwise realizes upon the Collateral or exercises any rights or remedies of a secured party or lien creditor or any other rights with respect to the Collateral or otherwise takes any action with respect thereto.  Without in any way limiting the foregoing, the Lender specifically acknowledges and agrees that the Bond Trustee may take such action as it deems appropriate to enforce the Senior Obligations and its Lien on and security interest in the Collateral, whether or not such action is beneficial or detrimental to the Lender’s interest.  The Lender agrees that it shall not take any action to foreclose or otherwise realize upon the Collateral or exercise any rights or remedies of a secured party with respect to the Collateral, unless and until the Senior Obligations have been paid in full.  Also without in any way limiting the foregoing, the Lender hereby expressly waives and

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releases any and all rights to have the Collateral or any part thereof marshaled upon any foreclosure, sale or other realization thereon.  There shall be no obligation on the part of the Bond Trustee, at any time, to resort for payment of the Senior Obligations to any obligor thereon or any guarantor thereof, or to any other person or corporation, their properties or estates, or to resort to any other collateral or any other rights or remedies whatsoever, and the Bond Trustee shall have the right to foreclose or otherwise realize upon the Collateral upon which it has a security interest irrespective of whether or not other proceedings or steps are pending seeking resort to or realization upon or from any of the foregoing.

8.3          Delivery of Proceeds of Collateral.  So long as the Senior Obligations are outstanding, the Lender will without demand or request being made upon it deliver any parts or proceeds of the Collateral which shall come into its possession, control or custody to the Bond Trustee for application as set forth in the First Mortgage Bond Indenture.

8.4          Agreement Not to Contest.  The Lender hereby agrees that it shall not contest the validity, perfection, priority or enforceability of any security interest or Lien granted to the Bond Trustee pursuant to the First Mortgage Bond Indenture.

8.5          Release of Collateral.  The Lender agrees that in the event the Bond Trustee shall come into the possession, custody and control of any property or assets of the Borrower as the result of any security interest granted to secure the Senior Obligations, the Bond Trustee may, to the extent the Bond Trustee does not apply the same to the payment or partial payment of the Senior Obligations, release the same to or upon the order of the Borrower, without notice, or accounting for the same, to the Lender or any other person, firm or corporation whomsoever, it being specifically understood and agreed that any property so released shall remain subject to all claims of the Lender and the Bond Trustee thereto in accordance herewith.  Without limiting the foregoing, the Lender acknowledges and agrees that the Bond Trustee may from time to time in its discretion release proceeds of the Collateral in which the Bond Trustee has a security interest to the Borrower or otherwise deal with the Collateral in which the Bond Trustee has a security interest, without any notice or accounting to the Lender whatsoever.

8.6          Release of Security Interest.  The Lender agrees that, whether or not a default has occurred in payment of the Loans, its Lien on the Collateral or any portion thereof shall automatically be released ipso facto as to all indebtedness secured thereby owing to the Lender if, when and to the same extent that the Bond Trustee releases its Lien on such Collateral or portion thereof.  The Lender further hereby agrees to execute and deliver such further instruments and do such further acts as the Borrower or the Bond Trustee may deem necessary or proper to carry out more effectively the foregoing.

8.7          Obligations under this Agreement Not Affected.  Except as specifically described in this Agreement, nothing contained in this Agreement or in any Note is intended to or impairs, as between the Borrower, its creditors other than the Bond Trustee and the Lender, the obligations of the Borrower, which are absolute and unconditional, to pay to the Lender the Liabilities as and when they become due and payable in accordance with the terms of this Agreement, subject, however, to the terms of this Section 8.  Except as specifically described in this Agreement, nothing contained in this Agreement or in any Note is intended to or affects the relative rights of the Lender and creditors of the Borrower other than the Bond Trustee.

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8.8          Bankruptcy.  The Lender agrees that in the event bankruptcy proceedings are instituted by or against the Borrower, the Bond Trustee may consent to the use of cash collateral or provide postpetition financing under section 364 of the United States Bankruptcy Code, 11 U.S.C. § 364, to the Borrower on such terms and conditions and in such amounts as the Bond Trustee, in its sole discretion, may decide.  The Lender waives any rights it may have under applicable law to object to such use of such cash collateral or postpetition financing.

8.9          Third Party Beneficiary.  The Bond Trustee shall be a third party beneficiary of this Section 8.

9.MISCELLANEOUS.

9.1          Amendments and Waivers.  No modification or waiver of, nor any consent to the departure by the Borrower from, any provision of this Agreement will be effective unless it is in writing from the Lender and then such modification, waiver or consent will be effective only on the specific instance and for the purpose for which it is given.

9.2          Severability.  Wherever possible, each provision of this Agreement must be interpreted in such manner as to be effective and valid under applicable law, but if any provision of this Agreement is prohibited by or invalid under applicable law, such provision is ineffective only to the extent of such prohibition or invalidity, without invalidating the remainder of such provisions or the remaining provisions of this Agreement.

9.3          Notices.  Except as otherwise expressly provided in this Agreement, any notice required or desired to be served, given or delivered under this Agreement must be in writing and is deemed to have been validly served, given or delivered (i) three days after deposit in the United States mails, with proper postage prepaid, (ii) when sent after receipt of confirmation if sent by telecopy or other similar facsimile transmission, (iii) one Business Day after deposit with a reputable overnight courier with all charges prepaid or (iv) when delivered, if hand delivered by messenger, all of which must be properly addressed to the party to be notified and sent to the address or number indicated on the signature page hereof or to such other address or number as each party designates to the other in the manner prescribed in this Section 9.3.

9.4          Counterparts.  This Agreement and any amendment or supplement to this Agreement or any waiver granted in connection with this Agreement may be executed in any number of counterparts and by the different parties on separate counterparts and each such counterpart is deemed to be an original, but all such counterparts together constitute but one and the same Agreement.

9.5          Prior Agreements.  The terms and conditions set forth in this Agreement supersede all prior agreements, discussions, correspondence, memoranda and understandings (whether written or oral) of the Borrower and the Lender concerning or relating to the subject matter of this Agreement.

9.6          Successors and Assigns.  This Agreement is binding upon the Borrower and the Lender and their respective successors and assigns and inures to the benefit of the Borrower and the Lender and their respective successors and permitted assigns.  The Borrower has no right to assign its rights or delegate its duties under this Agreement, without the prior written consent

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of the Lender.  The Lender has the right to assign to any Affiliate of the Lender all or a portion of its rights and obligations under this Agreement.  Upon any such assignment by the Lender, (i) the assignee becomes a party to this Agreement and, to the extent of such assignment, has all rights and obligations of the Lender under this Agreement and (ii) the Lender will, to the extent of such assignment, relinquish its rights and be released from its obligations under this Agreement.  The Borrower and the Lender agree to execute and deliver such documents, and to take such other actions, as the other party may reasonably request to accomplish the foregoing.

9.7          CHOICE OF LAW.  THIS AGREEMENT SHALL BE GOVERNED BY AND CONSTRUED FOR ALL PURPOSES IN ACCORDANCE WITH THE INTERNAL LAWS OF THE STATE OF DELAWARE.

*  *  *  *  *

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IN WITNESS WHEREOF, the parties have executed this Agreement as of the day and year first above written.

KENTUCKY UTILITIES COMPANY
Address:	1 Quality Street
	Lexington, Kentucky 40507
	Attn:   Treasurer
Facsimile:	502-627-4742
By:
Name:
Title:
FIDELIA CORPORATION
Address:	300 Delaware Avenue
	Wilmington, Delaware 19801
	Attn:   Executive Vice President
Facsimile:	302-417-5913
By:
Name:
Title:

EXHIBIT A

FORM OF NOTE

$ Date:                    

FOR VALUE RECEIVED, on _______________ “Maturity Date”) the undersigned, KENTUCKY UTILITIES COMPANY, a Kentucky and Virginia corporation (the “Borrower”), unconditionally promises to pay to FIDELIA CORPORATION (the “Lender”), at the Lender’s office at 300 Delaware Avenue, Wilmington, Delaware  19801, or at such other place as the holder of this Note may from time to time designate in writing, in lawful money of the United States of America and immediately available funds, the principal sum of $___________.  This Note is referred to in and was executed and delivered under the Loan and Security Agreement dated as of August 15, 2003 (the “Loan Agreement”) between the Borrower and the Lender, to which reference is made for a more complete statement of the terms and conditions under which the loan evidenced by this Note was made and is to be repaid.  Capitalized terms used in this Note and not otherwise defined have the meanings assigned to such terms in the Loan Agreement.

Unless otherwise paid sooner under the provisions of Section 2.6(c) or 7.1 of the Loan Agreement, the principal indebtedness represented by this Note is payable on the Maturity Date.  The Borrower further promises to pay interest on the outstanding principal amount of the indebtedness represented by this Note from the date of this Note until payment in full at the applicable rates determined in accordance with Section 2.3(A) of the Loan Agreement.  Except as otherwise provided in the Loan Agreement, interest is payable quarterly in arrears not later than the last Business Day of each calendar quarter and is computed on the basis of a 360-day year consisting of twelve 30-day months.

If payment under this Note becomes due and payable on a Business Day, the due date of such payment is extended to the next succeeding Business Day.  In no contingency or event whatsoever will interest charged under this Note, however such interest may be characterized or computed, exceed the highest rate permissible under any law which a court of competent jurisdiction, in a final determination, deems applicable to this Note.  In the event that such a court determines that the Lender has received interest under this Note in excess of the highest rate applicable to this Note, any such excess interest collected by the Lender is deemed to have been a repayment of principal and be so applied.

The obligations of the Borrower under this Note is secured by certain collateral as and to the extent set forth in the Loan Agreement.  This Note is subject to prepayment at the option of the Borrower as provided in the Loan Agreement.

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DEMAND, PRESENTMENT, PROTEST AND NOTICE OF NONPAYMENT AND PROTEST ARE WAIVED BY THE BORROWER.

This Note has been delivered and is deemed to have been made, at Wilmington, Delaware and will be interpreted in accordance with the internal law as (as opposed to conflicts of law provisions) and decisions of the State of Delaware.  Whenever possible each provision of this Note will be interpreted in such manner as to be effective and valid under applicable law, but if any provision of this Note is prohibited by or invalid under applicable law, such provision will be ineffective to the extent of such prohibition or invalidity, without invalidating the remainder of such provision or the remaining provisions of this Note.  Whenever in this Note reference is made to the Lender or the Borrower, such reference is deemed to include, as applicable, a reference to their respective successors and assigns.  The provisions of this Note are binding upon and inure to the benefit of said successors and assigns.  The Borrower’s successors and assigns include, without limitation, a receiver,  trustee or debtor-in-possession of or for the Borrower.

KENTUCKY UTILITIES COMPANY
By:
	Title:

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NOTE

$75,000,000.00 Date:  August 15, 2003

FOR VALUE RECEIVED, on August 15, 2013 “Maturity Date”) the undersigned, KENTUCKY UTILITIES COMPANY, a Kentucky and Virginia corporation (the “Borrower”), unconditionally promises to pay to FIDELIA CORPORATION (the “Lender”), at the Lender’s office at 300 Delaware Avenue, Wilmington, Delaware  19801, or at such other place as the holder of this Note may from time to time designate in writing, in lawful money of the United States of America and immediately available funds, the principal sum of $75,000,000.  This Note is referred to in and was executed and delivered under the Loan and Security Agreement dated as of August 15, 2003 (the “Loan Agreement”) between the Borrower and the Lender, to which reference is made for a more complete statement of the terms and conditions under which the loan evidenced by this Note was made and is to be repaid.  Capitalized terms used in this Note and not otherwise defined have the meanings assigned to such terms in the Loan Agreement.

Unless otherwise paid sooner under the provisions of Section 2.6(c) or 7.1 of the Loan Agreement, the principal indebtedness represented by this Note is payable on the Maturity Date.  The Borrower further promises to pay interest on the outstanding principal amount of the indebtedness represented by this Note from the date of this Note until payment in full at the applicable rates determined in accordance with Section 2.3(A) of the Loan Agreement.  Except as otherwise provided in the Loan Agreement, interest is payable quarterly in arrears not later than the last Business Day of each calendar quarter and is computed on the basis of a 360-day year consisting of twelve 30-day months.

If payment under this Note becomes due and payable on a Business Day, the due date of such payment is extended to the next succeeding Business Day.  In no contingency or event whatsoever will interest charged under this Note, however such interest may be characterized or computed, exceed the highest rate permissible under any law which a court of competent jurisdiction, in a final determination, deems applicable to this Note.  In the event that such a court determines that the Lender has received interest under this Note in excess of the highest rate applicable to this Note, any such excess interest collected by the Lender is deemed to have been a repayment of principal and be so applied.

The obligations of the Borrower under this Note is secured by certain collateral as and to the extent set forth in the Loan Agreement.  This Note is subject to prepayment at the option of the Borrower as provided in the Loan Agreement.

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DEMAND, PRESENTMENT, PROTEST AND NOTICE OF NONPAYMENT AND PROTEST ARE WAIVED BY THE BORROWER.

This Note has been delivered and is deemed to have been made, at Wilmington, Delaware and will be interpreted in accordance with the internal law as (as opposed to conflicts of law provisions) and decisions of the State of Delaware.  Whenever possible each provision of this Note will be interpreted in such manner as to be effective and valid under applicable law, but if any provision of this Note is prohibited by or invalid under applicable law, such provision will be ineffective to the extent of such prohibition or invalidity, without invalidating the remainder of such provision or the remaining provisions of this Note.  Whenever in this Note reference is made to the Lender or the Borrower, such reference is deemed to include, as applicable, a reference to their respective successors and assigns.  The provisions of this Note are binding upon and inure to the benefit of said successors and assigns.  The Borrower’s successors and assigns include, without limitation, a receiver,  trustee or debtor-in-possession of or for the Borrower.

KENTUCKY UTILITIES COMPANY

By:

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EX-4.27

EXHIBIT 4.27

LOAN AND SECURITY AGREEMENT

Dated as of August 15, 2003

between

LOUISVILLE GAS AND ELECTRIC COMPANY

and

FIDELIA CORPORATION

TABLE OF CONTENTS

1.	DEFINITIONS
	1.1	General Terms
	1.2	Accounting Terms
	1.3	Others Terms Defined in the Code
	1.4	Computation of Time Periods
	1.5	Headings and References
2.	TERM LOANS
	2.1	Loans
	2.2	Request for Purchase
	2.3	Interest
	2.4	Notes
	2.5	Closings
	2.6	Payments
	2.7	Term of This Agreement
3.	CONDITIONS OF ADVANCES
	3.1	Documents
	3.2	No Default
	3.3	Reaffirmation of Representations and Warranties
4.	COLLATERAL
	4.1	Security Interest
	4.2	Appointment of the Lender as the Borrower’s Attorney-in-Fact
	4.3	Preservation of Collateral and Perfection of Security Interests
	4.4	Reasonable Care
	4.5	Termination of Security Interest and Liens
5.	REPRESENTATIONS AND WARRANTIES
	5.1	Existence
	5.2	Authority
	5.3	Binding Effect
	5.4	Financial Statements
	5.5	Collateral
	5.6	Chief Executive Office Jurisdiction of Incorporation
	5.7	Other Corporate Names
	5.8	Margin Security
	5.9	Survival of Warranties
	5.10	Compliance with Laws and Regulations
6.	COVENANTS
	6.1	Financial Statements; Notices; Reports
	6.2	Books, Records and Inspections
	6.3	Conduct of Business
7.	EVENTS OF DEFAULT, RIGHTS AND REMEDIES OF LENDER
	7.1	Events of Default

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	7.2	Rights and Remedies Generally
	7.3	Waiver of Demand
	7.4	Marshalling; Payments Set Aside
8.	SUBORDINATION
	8.1	Agreement to Subordinate
	8.2	Administration of Collateral
	8.3	Delivery of Proceeds of Collateral
	8.4	Agreement Not to Contest
	8.5	Release of Collateral
	8.6	Release of Security Interest
	8.7	Obligations under this Agreement Not Affected
	8.8	Bankruptcy
	8.9	Third Party Beneficiary
9.	MISCELLANEOUS
	9.1	Amendments and Waivers
	9.2	Severability
	9.3	Notices
	9.4	Counterparts
	9.5	Prior Agreements
	9.6	Successors and Assigns
	9.7	CHOICE OF LAW

EXHIBITS
EXHIBIT A	—	Form of Note

ii

LOAN AND SECURITY AGREEMENT

This LOAN AND SECURITY AGREEMENT, dated as of August 15, 2003 (this “Agreement”), is made between LOUISVILLE GAS AND ELECTRIC COMPANY a Kentucky corporation, as borrower (the “Borrower”), and FIDELIA CORPORATION, a Delaware corporation, as lender (the “Lender”).

W I T N E S S E T H:

WHEREAS, the Borrower has requested that the Lender provide the Borrower with term loans;

WHEREAS, to induce the Lender to make such term loans available to the Borrower, the Borrower has agreed to secure its obligations to the Lender by granting the Lender a security interest in, and lien upon, the Collateral (as defined herein); and

WHEREAS, the Lender is willing to make such term loans available to the Borrower  upon the terms and conditions set forth in this Agreement;

NOW, THEREFORE, in consideration of the foregoing and the mutual agreements contained in this Agreement, the Borrower and the Lender agree as follows:

1.DEFINITIONS.

1.1General Terms.  When used in this Agreement, the following terms have the following meanings (such meanings to be equally applicable to both the singular and plural forms of the terms defined):

“Affiliate”, with respect to any Person, means another Person (i) that directly or indirectly, through one or more intermediaries, controls or is controlled by or is under common control with such Person, (ii) that directly or beneficially owns or holds 5% or more of any class of the voting stock of such Person or (iii) 5% or more of the voting stock (or in the case of a Person that is not a corporation, 5% or more of the equity interest) of which is owned directly or beneficially or held by such Person.

“Agreement” has the meaning set forth in the preamble.

“Authorized Officer” means at any time an individual whose signature has been certified to the Lender on behalf of the Borrower by a certificate now or hereafter executed on behalf of the Borrower and delivered to the Lender and whose authority has not been revoked prior to such time.

“Bond Trustee” means BNY Midwest Trust Company as trustee under the First Mortgage Bond Indenture, or any successor trustee thereunder.

“Borrower” has the meaning set forth in the preamble.

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“Business Day” means a day (other than a Saturday or Sunday) on which banks are open for business in Louisville, Kentucky and Wilmington, Delaware.

“Code” means the Uniform Commercial Code of the Commonwealth of Kentucky as in effect on the Closing Date.

“Collateral” has the meaning set forth in Section 4.1.

“Default” means any event that, with lapse of time or notice or lapse of time and notice, will constitute an Event of Default if it continues uncured.

“Dollars” and the “$” each means lawful money of the United States of America.

“Equipment” has the meaning set forth in the Code and includes, without limitation, any and all of the Borrower’s now owned or hereafter acquired machinery, equipment, furniture, furnishings and all tangible personal property similar to any of the foregoing (other than Inventory), together with all improvements, accessions and appurtenances thereto and any proceeds of any of the foregoing, including insurance proceeds and condemnation awards, excluding, however, any Equipment which is not subject to a Lien now or at any time hereafter pursuant to the First Mortgage Bond Indenture.

“Event of Default” means the occurrence or existence of any one of more of the events described in Section 7.1.

“First Mortgage Bond Indenture” means the Trust Indenture dated November 1, 1949 from the Borrower to the Bond Trustee, and any and all supplemental indentures thereof, as further amended and supplemented from time to time.

“GAAP” means generally accepted accounting principles, as in effect in the United States from time to time.

“Governmental Authority” means any nation or government, any federal, state, local or other political subdivision thereof and any entity exercising executive, legislative, judicial, regulatory or administrative functions of or pertaining to government.

“Lender” has the meaning set forth in the preamble.

“Liabilities” means all of the Borrower’s liabilities, obligations, and indebtedness to the Lender for monetary amounts, whether now or hereafter owing, arising, due or payable under this Agreement and the Notes howsoever evidenced, created, incurred, acquired, or owing.

“Lien” means any mortgage, deed of trust, pledge, hypothecation, assignment, collateral deposit arrangement, security interest, encumbrance for the payment of money, lien (statutory or other), preference, right of setoff, priority or other security agreement or preferential arrangement of any kind or nature whatsoever, including, without limitation, any conditional sale or other title retention agreement, or the interest of a lessor under a capital lease.

“Loan” has the meaning set forth in Section 2.1.

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 “Material Adverse Effect” means a material adverse effect upon (i) the business, assets,  properties or condition (financial or otherwise), or results of operations of the Borrower, or (ii) upon the ability of the Borrower to perform or cause to be performed any of its obligations under this Agreement or the rights or remedies of the Lender under this Agreement.

“Note” has the meaning set forth in Section 2.4.

“Permitted Lien” means Liens created under or in connection with the First Mortgage Bond Indenture and Liens permitted by the First Mortgage Bond Indenture.

“Person” means any natural person, firm, enterprise, institution, corporation, association, partnership, trust, unincorporated organization, sole proprietorship, joint venture, limited liability company or Governmental Authority.

1.2Accounting Terms.  Any accounting terms used in this Agreement which are not specifically defined in this Agreement have the meanings customarily given them in accordance with GAAP.

1.3Others Terms Defined in the Code.  All other terms contained in this Agreement (and which are not otherwise specifically defined in the Agreement) have the meanings provided by the Code to the extent the same are used or defined in the Code.

1.4Computation of Time Periods.  In this Agreement in the computation of periods of time from a specified date to a later specified date, the words “from” or “commencing on” means “from and including” and the words “to,” “through,” “ending on” and “until” each mean “to but excluding.”

1.5Headings and References.  Section and other headings are for reference only, and shall not affect the interpretation or meaning of any provision of this Agreement.  Any Section or clause references are to this Agreement, unless otherwise specified.  References in this Agreement or any other agreement include this Agreement and other agreements as the same may be amended, restated, supplemented or otherwise modified from time to time pursuant to the provisions hereof or thereof.  A reference to any law, statute or regulation shall mean that law, statute or regulation as it may be amended, supplemented or otherwise modified from time to time, and any successor law, statute or regulation.

2.TERM LOANS.

2.1Loans.  The Lender, at its discretion, may make available to the Borrower term loans (the “Loans”) from time to time pursuant to this Agreement, upon telephonic or written communication of a borrowing request from the Borrower as provided in Section 2.2.

2.2Request for Loans.  The Borrower may from time to time make requests for Loans (each such request being a “Borrowing Notice”) hereunder.  Each Borrowing Notice shall (i) specify the principal amount of the Loan requested, (ii) specify the final maturity not to be less than one year from the Borrowing Date, (iii) specify the proposed date for the borrowing of the Loan (the “Borrowing Date”), (iv) specify whether the Loan shall bear interest at a fixed rate or a floating rate, (v) specify the dates on which interest is to be paid, and (vi) specify the

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number of the account and the name and address of the depository institution to which the proceeds of the Loan are to be transferred on the Borrowing Date.  Each Borrowing Notice may be given telephonically or in writing.  Each such request for a Loan is subject to acceptance by the Lender, in its sole discretion.

2.3Interest.

(A)Interest Rate.  The interest rate payable by the Borrower on any Loan shall be set at such interest rate as the Borrower and the Lender shall agree, but in no event greater than the lowest of (i) the effective cost of capital of E.ON AG, (ii) the effective cost of capital of the Lender and (iii) the Borrower’s effective cost of capital determined by reference to the effective cost of a direct borrowing by the Borrower from a nonassociate for a comparable term loan that could be entered into at such time.  Such interest rate may be determined as a fixed interest rate or a floating rate, as specified by the Borrower in the Borrowing Notice.

(B)Interest Payments.  Accrued but unpaid interest on each Loan is payable in arrears on dates agreed to by the Borrower and the Lender as specified in the Borrowing Notice and upon payment in full of such Loan.  Interest on the Loans is computed on the basis of a 360-day year consisting of twelve 30-day months.

(C)Highest Lawful Rate.  In no contingency or event whatsoever will interest charged on the Loans, however, such interest may be characterized or computed, exceed the highest rate permissible under any law which a court of competent jurisdiction, in a final determination, deems applicable to the Loans. In the event that such a court determines that the Lender has received interest under the Loans in excess of the highest rate applicable to the Loans, any such excess interest collected by the Lender is deemed to have been a repayment of principal and will be so applied.

2.4Notes.  On each Borrowing Date, the Borrower shall issue to the Lender a promissory note (the “Notes”) in a principal amount equal to the principal amount of the Loan to be made on such Borrowing Date; to bear interest on the unpaid balance thereof from the date thereof at the rate per annum as determined in accordance with Section 2.3(A); and to be substantially in the form of Exhibit A attached hereto.  The term “Notes” as used herein shall include each Note delivered pursuant to this Agreement and each Note delivered in substitution or exchange for any such Note.

2.5Closings.  Not later than 11:30 A.M. (New York City local time) on the Borrowing Date for any Loan, the Borrower will deliver to the Lender at the offices of the Lender, a Note dated the Borrowing Date, evidencing the Loan to be made on such Borrowing Date, against payment of the Loan proceeds by transfer of immediately available funds for credit to the Borrower’s account specified in the Borrowing Notice.

2.6Payments.

(A)Place of Payments.  The Borrower will make each payment under this Agreement and under the Notes not later than 2:00 p.m. (New York time) on the day when due to the Lender at its address set forth in Section 9.3 in immediately available funds.  The Borrower’s

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obligations to the Lender with respect to such payments will be discharged by making such payments to the Lender under this Section 2.6.

(B)Timing of Payments.  If any payment of any interest or fees owing under this Agreement falls due on a day that is not a Business Day, then such due date is extended to the next following Business Day.

(C)Optional Prepayments.  On any interest payment date, and with at least three business day’s prior written notice, the Borrower shall be entitled to prepay any amount of the loan outstanding, provided such payment is not less than $1,000,000 and, provided further, the Borrower shall pay a prepayment charge equal to the present value of the difference between (i) the interest payable provided in this loan agreement and (ii) the interest payable at the prevailing interest rate at the time of prepayment, for the period from the date of prepayment through the final maturity date,  which difference, if negative, shall be deemed to be zero. The present value will be determined using the prevailing interest rate at the time of the prepayment as the discount rate.

2.7Term of This Agreement.  This Agreement shall remain in full force and effect until the second Business Day after the Borrower or the Lender gives notice to the other party hereto stating that it elects to terminate this Agreement.  Notwithstanding the termination of this Agreement, until all of the Loans under this Agreement have been paid in full and all financing arrangements between the Borrower and the Lender under this Agreement have been terminated, all of the Lender’s rights and remedies under this Agreement survive and the Lender is entitled to retain its security interest in and to all existing and future Collateral.

3.CONDITIONS OF ADVANCES.

Notwithstanding any other provisions contained in this Agreement to the contrary, the making of each Loan provided for in this Agreement is conditioned upon the following:

3.1Documents.  The Lender has received all of the following (or the delivery of such has been waived), each duly executed, in form and substance satisfactory to the Lender, and delivered on or prior to the applicable Borrowing Date:

(i)This Agreement, duly executed by the Borrower.

(ii)The Note, evidencing such Loan, duly executed by the Borrower.

(iii)UCC-1 financing statements listing the Borrower as debtor, and the Lender, as secured party, covering the Collateral.

(iv)Certified copies of all documents evidencing any necessary corporate action, consents and governmental approvals, if any, with respect to this Agreement and the Notes.

(v)A signature authorization certificate for the Borrower.

(vi)Such other documents as the Lender may reasonably request.

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3.2No Default.  No Default or Event of Default has occurred and is continuing.

3.3Reaffirmation of Representations and Warranties ..  The representations and warranties contained in Section 5 are true and correct in all material aspects on and as of the Borrowing Date.

4.COLLATERAL.

4.1Security Interest.  To secure payment of the Liabilities and performance of its obligations under this Agreement and the Notes, the Borrower grants, mortgages, hypothecates and pledges to the Lender a continuing lien upon and security interest in all of the Borrower’s right, title and interest in the Collateral, wherever located, whether now or hereafter existing, owned, licensed, leased (to the extent of the Borrower’s leasehold interest in such property), consigned (to the extent of the Borrower’s ownership interest in such property), arising or acquired, subject, however, in all respects to the provisions of Section 8.  The “Collateral” shall consist of:  (i) the Equipment; (ii) all insurance proceeds of or relating thereto, (iii) all of the Borrower’s books and records relating to any of the foregoing; and (iv) all accessions and additions to, substitutions for, and replacements, products and proceeds of any of the foregoing.

4.2Appointment of the Lender as the Borrower’s Attorney-in-Fact.  The Borrower irrevocably designates, makes, constitutes and appoints the Lender (and all persons designated by the Lender) as the Borrower’s true and lawful attorney-in-fact, and authorizes the Lender, in the Borrower’s or the Lender’s name, upon the occurrence and during the continuation of an Event of Default, with respect to any item of Collateral or the proceeds of such Collateral, to do all acts and things which are necessary, in the Lender’s sole discretion, to fulfill the Borrower’s obligations under this Agreement.

4.3Preservation of Collateral and Perfection of Security Interests.  The Borrower will execute and deliver, or cause to be executed and delivered, to the Lender at any time or times after the date of this Agreement at the request of the Lender, all (i) financing statements or (ii) other documents (and, in each case, pay the cost of filing or recording the same in all public offices deemed necessary by the Lender), as the Lender may request, in a form satisfactory to the Lender, to perfect and keep perfected the security interest, and preserve the priority of such security interest, in the Collateral granted by the Borrower to the Lender or to otherwise protect and preserve the Collateral and the Lender’s security interest in the Collateral.  Should the Borrower fail to do so, the Lender is authorized to sign any such financing statements as the Borrower’s agent.  The Borrower further agrees that a carbon, photographic or other reproduction of this Agreement or of a financing statement is sufficient as a financing statement.

4.4Reasonable Care.  The Lender is deemed to have exercised reasonable care in the custody and preservation of any of the Collateral in its possession if it takes such action for that purpose as the Borrower requests in writing, but the Lender’s failure to comply with any such request will not of itself be deemed a failure to exercise reasonable care.

4.5Termination of Security Interest and Liens.  The Lender’s security interest and other liens in, on and to the Collateral terminates when all the Liabilities have been paid in full and this Agreement has been terminated, at which time the Lender will reassign and redeliver (or

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cause to be reassigned and redelivered) to the Borrower, or to such Person as the Borrower designates, against receipt, such of the Collateral (if any) assigned by the Borrower to the Lender (or otherwise held by the Lender) as has not been sold or otherwise applied by the Lender under the terms of this Agreement and is still held by it under this Agreement, together with appropriate instruments of reassignment and release.  Any such reassignment is without recourse upon or representation or warranty by the Lender and will be at the Borrower’s cost and expense.

5.REPRESENTATIONS AND WARRANTIES.

The Borrower represents and warrants that as of the date of this Agreement and as of each Borrowing Date.

5.1Existence.  The Borrower is a corporation duly organized, validly existing and in good standing under the laws of the Commonwealth of Kentucky and is duly qualified as a foreign entity and is in good standing in all jurisdictions where the nature and extent of the business transacted by it or the ownership of its assets makes such qualification necessary, except for those jurisdictions in which the failure so to qualify or to be in good standing would not have a Material Adverse Effect.

5.2Authority.  The execution and delivery by the Borrower of this Agreement and the Notes and the performance of the Borrower’s obligations under this Agreement and the Notes:  (i) are within the Borrower’s corporate powers; (ii) are duly authorized by the Borrower’s board of directors or other governing body; (iii) are not in contravention of the terms of the Borrower’s certificate of incorporation or bylaws or of any material indenture, agreement or undertaking to which the Borrower is a party or by which the Borrower or any of its property is bound; (iv) does not require any consent, registration or approval of any Governmental Authority, which has not been obtained; (v) does not contravene any material contractual or governmental restriction binding upon the Borrower; and (vi) will not, except as contemplated in this Agreement, result in the imposition of any Lien, claim or encumbrance upon any property of the Borrower under any existing material indenture, mortgage, deed of trust, loan or credit agreement or other material agreement or instrument to which the Borrower is a party or by which it or its property may be bound or affected.

5.3Binding Effect.  This Agreement and the Notes are the legal, valid and binding obligations of the Borrower and are enforceable against the Borrower in accordance with their respective terms.

5.4Financial Statements.  The financial statements of the Borrower filed with the Securities and Exchange Commission since December 31, 2001 are in accordance with the books and records of the Borrower and fairly present the financial condition of the Borrower at the dates of such financial statements and the results of operations for the periods indicated (subject, in the case of unaudited financial statements, to normal year-end adjustments), and such financial statements were prepared in conformity with GAAP (other than the absence of notes to such financial statements).

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5.5Collateral.  Except for Permitted Liens and as otherwise provided in Section 8.5, all of the Collateral is and will continue to be owned by the Borrower free and clear of all Liens, claims and encumbrances.

5.6Chief Executive Office Jurisdiction of Incorporation.  As of the date hereof, the principal place of business and chief executive office of the Borrower is located at 220 West Main Street, Louisville, Kentucky 40202 and the Borrower has been duly incorporated in the Commonwealth of Kentucky.

5.7Other Corporate Names.  The Borrower has not used any other corporate or fictitious names in the past five years.

5.8Margin Security.  The Borrower owns no margin security and none of the proceeds of the Loans advanced under this Agreement will be used for the purpose of purchasing or carrying any margin securities or for the purpose of reducing or retiring any Indebtedness which was originally incurred to purchase any margin securities or for any other purpose not permitted by Regulations T, U or X of the Board of Governors of the Federal Reserve System.

5.9Survival of Warranties.  All representations contained in this Agreement survive the execution and delivery of this Agreement.

5.10Compliance with Laws and Regulations.  The execution and delivery by the Borrower of this Agreement and the performance of the Borrower’s obligations under this Agreement and the Notes are not in contravention of any laws.  The Borrower is in compliance with all laws, orders, regulations and ordinances of all federal, foreign, state and local governmental authorities relating to the business, operations and the assets of the Borrower, including, without limitation, Regulations T, U and X of the Board of Governors of the Federal Reserve System, except for laws, orders, regulations and ordinances the violation of which are not likely to have a Material Adverse Effect.

6.COVENANTS.

The Borrower covenants and agrees that, so long as any of the Liabilities remain outstanding:

6.1Financial Statements; Notices; Reports.  The Borrower will keep, in all material respects, proper books of record and account in which entries will be made of all dealings or transactions of or in relation to the business and affairs of the Borrower, in accordance with GAAP consistently applied.  The Borrower will furnish to the Lender:

(A)SEC Reports.  Copies of annual reports and quarterly reports filed by the Borrower with the Securities and Exchange Commission on Forms 10-K and 10-Q, within 20 Business Days of the date of filing of such report;

(B)Default Notices.  As soon as practicable (but in any event not more than two Business Days after any Authorized Officer of the Borrower obtains knowledge of the occurrence of an event or the existence of a circumstance giving rise to a Default or an Event of Default), notice of any and all Defaults or Events of Default;

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(C)Notice of Change of Name.  Notice in writing to the Lender, as soon as practicable and in any event within five days after the occurrence of any change in the name, address or jurisdiction of incorporation of the Borrower or the location of the books and records of the Borrower; and

(D)Other Information.  With reasonable promptness, such other business or financial data as the Lender may reasonably request.

The Lender will take reasonable efforts to keep such information, and all information acquired as a result of any inspection conducted in accordance with Section 6.2 (and any other information provided to the Lender under this Agreement), confidential, provided that the Lender may communicate such information (i) in accordance with the Borrower’s written authorization, (ii) to any regulatory authority having jurisdiction over the Lender, (iii) to any other Person in connection with the exercise of the Lender’s rights under this Agreement, (iv) to any Person in any litigation in which the Lender is a party or (v) to any other Person if the Lender believes in its sole discretion that disclosure is necessary in connection with any legal process or informal investigative demand, whether issued by a court, judicial or administrative or legislative body or committee or other governmental authority.  Notwithstanding the foregoing, information will not be deemed to be confidential to the extent such information (a) is available in the public domain, (b) becomes available in the public domain other than as a result of unauthorized disclosure by the Lender or (c) is acquired from a Person not known by the Lender to be in breach of an obligation of secrecy to the Borrower.

6.2Books, Records and Inspections.  The Lender, or any agent or employee designated by the Lender in writing, has the right, from time to time after the date of this Agreement, to call at the Borrower’s place or places of business (or any other place where the Collateral or any information relating to the Collateral is kept or located) during reasonable business hours and, without unreasonable hindrance or delay, (i) to inspect, audit, check and make copies of and extracts from the Borrower’s books, records, journals, orders, receipts and any correspondence and other data relating to the Borrower’s business or to any transactions between the parties thereto, (ii) to make such verification concerning the Collateral as the Lender may consider reasonable under the circumstances and (iii) to discuss the affairs, finances and business of the Borrower with any officers, employees or directors of the Borrower.

6.3Conduct of Business.  Except as contemplated in this Agreement, the Borrower will (i) maintain its existence, (ii) continue in, and limit its operations to, the same general lines of business as that presently conducted by it or other businesses reasonably related thereto and (iii) comply with all laws, orders, regulations and ordinances of any federal, foreign, state or local governmental authority, except for such laws, orders, regulations and ordinances the violation of which has no reasonable likelihood of having a Material Adverse Effect.

7.EVENTS OF DEFAULT, RIGHTS AND REMEDIES OF LENDER.

7.1Events of Default.  If any one or more of the following events (“Events of Default”) occurs:

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(A)the Borrower fails to pay any of the principal of or interest on the Loans, or any Commitment Fees or other amounts due hereunder, within 10 Business Days after such amounts are due (whether by scheduled maturity, acceleration or otherwise);

(B)the Borrower fails or neglects to perform, keep or observe any of its covenants, conditions or agreements contained in this Agreement;

(C)any warranty or representation now or hereafter made by the Borrower under this Agreement is untrue or incorrect in any material respect when made;

(D)a proceeding under any bankruptcy, reorganization, arrangement of debt, insolvency, readjustment of debt or receivership law or statute is filed by or against the Borrower, the Borrower makes an assignment for the benefit of creditors or the Borrower takes any requisite action to authorize any of the foregoing and, in the case of an involuntary proceeding filed against the Borrower, such proceeding is not discharged or dismissed within 30 days;

(E)the Borrower voluntarily or involuntarily dissolves or is dissolved;

(F)the Borrower becomes insolvent or fails generally to pay its debts as they become due;

(G)the Lender shall cease to have a valid, perfected security interest in all or any material portion of the Collateral; or

(H)E.ON AG shall cease to own, directly or indirectly, at least 80% of the voting capital stock of the Borrower;

then the Lender, upon notice to the Borrower, may declare the Loans to be immediately due and payable, whereupon the Loans will become immediately due and payable; provided, that if an Event of Default described in Section 7.1(D) exists or occurs, the Loans shall automatically, without notice of any kind, become immediately due and payable.

7.2Rights and Remedies Generally.  Subject to the subordination provisions of Section 8, upon the occurrence and continuance of an Event of Default, the Lender has, in addition to any other rights and remedies contained in this Agreement, all of the rights and remedies of a secured party under the Code or other applicable laws, all of which rights and remedies are cumulative, and none exclusive, to the extent permitted by law.  Any single or partial exercise by the Lender of any right or remedy for a default or breach of any term, covenant, condition or agreement in this Agreement does not affect its rights and does not waive, alter, affect, or prejudice any other right or remedy to which the Lender may be lawfully entitled for the same default or breach.

7.3Waiver of Demand.  Demand, presentment, protest and notice of nonpayment are waived by the Borrower.  The Borrower also waives the benefit of all valuation, appraisal and exemption laws.

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7.4Marshalling; Payments Set Aside.  The Lender is under no obligation to marshall any assets in favor of the Borrower or any other party or against or in payment of any or all of the Liabilities.  To the extent that the Borrower makes a payment or payments to the Lender or the Lender enforces its security interests or exercises its rights of setoff, and such payment or payments or the proceeds of such enforcement or setoff or any part thereof are subsequently invalidated, declared to be fraudulent or preferential, set aside and/or required to be repaid to a trustee, receiver or any other party under any bankruptcy law, state or federal law, common law or equitable cause, then to the extent of such recovery, the obligation or part thereof originally intended to be satisfied will be revived and continue in full force and effect as if such payment had not been made or such enforcement or setoff had not occurred.

8.SUBORDINATION.

8.1Agreement to Subordinate.

(A)Terms of Subordination.  The Lender and the Borrower agree that the lien granted by the Borrower hereunder to secure the Liabilities is subordinate, to the extent and in the manner set forth in this Agreement, to the lien of the First Mortgage Bond Indenture and any and all of the bonds outstanding from time to time thereunder (the “Senior Obligations”).  Notwithstanding the order or time of creation, acquisition, attachment, or the order, time, or manner of perfection, or the order or time of filing or recordation of any document or instrument, or other method of perfecting a security interest or Lien on and against any of the Collateral or other assets of the Borrower, the Lender agrees that any Lien or security interest now or hereafter existing in and to the Collateral in favor of the Lender shall be and at all times remain subject and subordinate in all respects to any Lien or security interest which may now or hereafter at any time or from time to time be granted pursuant to the First Mortgage Bond Indenture on or in any or all of the Collateral as security for the Senior Obligations.

(B)Further Assurances.  The Lender and the Borrower will, at the Borrower’s expense and at any time and from time to time, promptly execute and deliver all further instruments and documents, and take all further action, that may be necessary, or that the Bond Trustee may reasonably request, in order to protect any right or interest granted or purported to be granted by this Agreement or to enable the Bond Trustee to exercise and enforce its rights and remedies under this Agreement.

8.2Administration of Collateral. The Bond Trustee shall have complete and sole discretion in, and shall not be liable to the Lender for, determining how, when and in what manner the Bond Trustee administers the Senior Obligations or forecloses or otherwise realizes upon the Collateral or exercises any rights or remedies of a secured party or lien creditor or any other rights with respect to the Collateral or otherwise takes any action with respect thereto.  Without in any way limiting the foregoing, the Lender specifically acknowledges and agrees that the Bond Trustee may take such action as it deems appropriate to enforce the Senior Obligations and its Lien on and security interest in the Collateral, whether or not such action is beneficial or detrimental to the Lender’s interest.  The Lender agrees that it shall not take any action to foreclose or otherwise realize upon the Collateral or exercise any rights or remedies of a secured party with respect to the Collateral, unless and until the Senior Obligations have been paid in full.  Also without in any way limiting the foregoing, the Lender hereby expressly waives and

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releases any and all rights to have the Collateral or any part thereof marshaled upon any foreclosure, sale or other realization thereon.  There shall be no obligation on the part of the Bond Trustee, at any time, to resort for payment of the Senior Obligations to any obligor thereon or any guarantor thereof, or to any other person or corporation, their properties or estates, or to resort to any other collateral or any other rights or remedies whatsoever, and the Bond Trustee shall have the right to foreclose or otherwise realize upon the Collateral upon which it has a security interest irrespective of whether or not other proceedings or steps are pending seeking resort to or realization upon or from any of the foregoing.

8.3Delivery of Proceeds of Collateral.  So long as the Senior Obligations are outstanding, the Lender will without demand or request being made upon it deliver any parts or proceeds of the Collateral which shall come into its possession, control or custody to the Bond Trustee for application as set forth in the First Mortgage Bond Indenture.

8.4Agreement Not to Contest.  The Lender hereby agrees that it shall not contest the validity, perfection, priority or enforceability of any security interest or Lien granted to the Bond Trustee pursuant to the First Mortgage Bond Indenture.

8.5Release of Collateral.  The Lender agrees that in the event the Bond Trustee shall come into the possession, custody and control of any property or assets of the Borrower as the result of any security interest granted to secure the Senior Obligations, the Bond Trustee may, to the extent the Bond Trustee does not apply the same to the payment or partial payment of the Senior Obligations, release the same to or upon the order of the Borrower, without notice, or accounting for the same, to the Lender or any other person, firm or corporation whomsoever, it being specifically understood and agreed that any property so released shall remain subject to all claims of the Lender and the Bond Trustee thereto in accordance herewith.  Without limiting the foregoing, the Lender acknowledges and agrees that the Bond Trustee may from time to time in its discretion release proceeds of the Collateral in which the Bond Trustee has a security interest to the Borrower or otherwise deal with the Collateral in which the Bond Trustee has a security interest, without any notice or accounting to the Lender whatsoever.

8.6Release of Security Interest.  The Lender agrees that, whether or not a default has occurred in payment of the Loans, its Lien on the Collateral or any portion thereof shall automatically be released ipso facto as to all indebtedness secured thereby owing to the Lender if, when and to the same extent that the Bond Trustee releases its Lien on such Collateral or portion thereof.  The Lender further hereby agrees to execute and deliver such further instruments and do such further acts as the Borrower or the Bond Trustee may deem necessary or proper to carry out more effectively the foregoing.

8.7Obligations under this Agreement Not Affected.  Except as specifically described in this Agreement, nothing contained in this Agreement or in any Note is intended to or impairs, as between the Borrower, its creditors other than the Bond Trustee and the Lender, the obligations of the Borrower, which are absolute and unconditional, to pay to the Lender the Liabilities as and when they become due and payable in accordance with the terms of this Agreement, subject, however, to the terms of this Section 8.  Except as specifically described in this Agreement, nothing contained in this Agreement or in any Note is intended to or affects the relative rights of the Lender and creditors of the Borrower other than the Bond Trustee.

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8.8Bankruptcy.  The Lender agrees that in the event bankruptcy proceedings are instituted by or against the Borrower, the Bond Trustee may consent to the use of cash collateral or provide postpetition financing under section 364 of the United States Bankruptcy Code, 11 U.S.C. § 364, to the Borrower on such terms and conditions and in such amounts as the Bond Trustee, in its sole discretion, may decide.  The Lender waives any rights it may have under applicable law to object to such use of such cash collateral or postpetition financing.

8.9Third Party Beneficiary.  The Bond Trustee shall be a third party beneficiary of this Section 8.

9.MISCELLANEOUS.

9.1Amendments and Waivers.  No modification or waiver of, nor any consent to the departure by the Borrower from, any provision of this Agreement will be effective unless it is in writing from the Lender and then such modification, waiver or consent will be effective only on the specific instance and for the purpose for which it is given.

9.2Severability.  Wherever possible, each provision of this Agreement must be interpreted in such manner as to be effective and valid under applicable law, but if any provision of this Agreement is prohibited by or invalid under applicable law, such provision is ineffective only to the extent of such prohibition or invalidity, without invalidating the remainder of such provisions or the remaining provisions of this Agreement.

9.3Notices.  Except as otherwise expressly provided in this Agreement, any notice required or desired to be served, given or delivered under this Agreement must be in writing and is deemed to have been validly served, given or delivered (i) three days after deposit in the United States mails, with proper postage prepaid, (ii) when sent after receipt of confirmation if sent by telecopy or other similar facsimile transmission, (iii) one Business Day after deposit with a reputable overnight courier with all charges prepaid or (iv) when delivered, if hand delivered by messenger, all of which must be properly addressed to the party to be notified and sent to the address or number indicated on the signature page hereof or to such other address or number as each party designates to the other in the manner prescribed in this Section 9.3.

9.4Counterparts.  This Agreement and any amendment or supplement to this Agreement or any waiver granted in connection with this Agreement may be executed in any number of counterparts and by the different parties on separate counterparts and each such counterpart is deemed to be an original, but all such counterparts together constitute but one and the same Agreement.

9.5Prior Agreements.  The terms and conditions set forth in this Agreement supersede all prior agreements, discussions, correspondence, memoranda and understandings (whether written or oral) of the Borrower and the Lender concerning or relating to the subject matter of this Agreement.

9.6Successors and Assigns.  This Agreement is binding upon the Borrower and the Lender and their respective successors and assigns and inures to the benefit of the Borrower and the Lender and their respective successors and permitted assigns.  The Borrower has no right to assign its rights or delegate its duties under this Agreement, without the prior written consent

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of the Lender.  The Lender has the right to assign to any Affiliate of the Lender all or a portion of its rights and obligations under this Agreement.  Upon any such assignment by the Lender, (i) the assignee becomes a party to this Agreement and, to the extent of such assignment, has all rights and obligations of the Lender under this Agreement and (ii) the Lender will, to the extent of such assignment, relinquish its rights and be released from its obligations under this Agreement.  The Borrower and the Lender agree to execute and deliver such documents, and to take such other actions, as the other party may reasonably request to accomplish the foregoing.

9.7CHOICE OF LAW. THIS AGREEMENT SHALL BE GOVERNED BY AND CONSTRUED FOR ALL PURPOSES IN ACCORDANCE WITH THE INTERNAL LAWS OF THE STATE OF DELAWARE.

*  *  *  *  *

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IN WITNESS WHEREOF, the parties have executed this Agreement as of the day and year first above written.

LOUISVILLE GAS AND ELECTRIC COMPANY
Address:	220 West Main Street
	Louisville, Kentucky 40202
	Attn:   Treasurer
Facsimile:	502-627-4742
By:
Name:
Title:
FIDELIA CORPORATION
Address:	300 Delaware Avenue
	Wilmington, Delaware 19801
	Attn:   Executive Vice President
Facsimile:	302-417-5913
By:
Name:
Title:

EXHIBIT A

FORM OF NOTE

$                      Date:                  

FOR VALUE RECEIVED, on                         (the “Maturity Date”) the undersigned, LOUISVILLE GAS AND ELECTRIC COMPANY, a Kentucky corporation (the “Borrower”), unconditionally promises to pay to FIDELIA CORPORATION (the “Lender”), at the Lender’s office at 300 Delaware Avenue, Wilmington, Delaware  19801, or at such other place as the holder of this Note may from time to time designate in writing, in lawful money of the United States of America and immediately available funds, the principal sum of $                         .  This Note is referred to in and was executed and delivered under the Loan and Security Agreement dated as of August 15, 2003 (the “Loan Agreement”) between the Borrower and the Lender, to which reference is made for a more complete statement of the terms and conditions under which the loan evidenced by this Note was made and is to be repaid.  Capitalized terms used in this Note and not otherwise defined have the meanings assigned to such terms in the Loan Agreement.

Unless otherwise paid sooner under the provisions of Section 2.6(c) or 7.1 of the Loan Agreement, the principal indebtedness represented by this Note is payable on the Maturity Date.  The Borrower further promises to pay interest on the outstanding principal amount of the indebtedness represented by this Note from the date of this Note until payment in full at the applicable rates determined in accordance with Section 2.3(A) of the Loan Agreement.  Except as otherwise provided in the Loan Agreement, interest is payable quarterly in arrears not later than the last Business Day of each calendar quarter and is computed on the basis of a 360-day year consisting of twelve 30-day months.

If payment under this Note becomes due and payable on a Business Day, the due date of such payment is extended to the next succeeding Business Day.  In no contingency or event whatsoever will interest charged under this Note, however such interest may be characterized or computed, exceed the highest rate permissible under any law which a court of competent jurisdiction, in a final determination, deems applicable to this Note.  In the event that such a court determines that the Lender has received interest under this Note in excess of the highest rate applicable to this Note, any such excess interest collected by the Lender is deemed to have been a repayment of principal and be so applied.

The obligations of the Borrower under this Note is secured by certain collateral as and to the extent set forth in the Loan Agreement.  This Note is subject to prepayment at the option of the Borrower as provided in the Loan Agreement.

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DEMAND, PRESENTMENT, PROTEST AND NOTICE OF NONPAYMENT AND PROTEST ARE WAIVED BY THE BORROWER.

This Note has been delivered and is deemed to have been made, at Wilmington, Delaware and will be interpreted in accordance with the internal law as (as opposed to conflicts of law provisions) and decisions of the State of Delaware.  Whenever possible each provision of this Note will be interpreted in such manner as to be effective and valid under applicable law, but if any provision of this Note is prohibited by or invalid under applicable law, such provision will be ineffective to the extent of such prohibition or invalidity, without invalidating the remainder of such provision or the remaining provisions of this Note.  Whenever in this Note reference is made to the Lender or the Borrower, such reference is deemed to include, as applicable, a reference to their respective successors and assigns.  The provisions of this Note are binding upon and inure to the benefit of said successors and assigns.  The Borrower’s successors and assigns include, without limitation, a receiver,  trustee or debtor-in-possession of or for the Borrower.

LOUISVILLE GAS AND ELECTRIC COMPANY
By:
	Title:

17

NOTE

$100,000,000.00 Date:  August 15, 2003

FOR VALUE RECEIVED, on August 15, 2013 (the “Maturity Date”) the undersigned, LOUISVILLE GAS AND ELECTRIC COMPANY, a Kentucky corporation (the “Borrower”), unconditionally promises to pay to FIDELIA CORPORATION (the “Lender”), at the Lender’s office at 300 Delaware Avenue, Wilmington, Delaware  19801, or at such other place as the holder of this Note may from time to time designate in writing, in lawful money of the United States of America and immediately available funds, the principal sum of $100,000,000.  This Note is referred to in and was executed and delivered under the Loan and Security Agreement dated as of August 15, 2003 (the “Loan Agreement”) between the Borrower and the Lender, to which reference is made for a more complete statement of the terms and conditions under which the loan evidenced by this Note was made and is to be repaid.  Capitalized terms used in this Note and not otherwise defined have the meanings assigned to such terms in the Loan Agreement.

Unless otherwise paid sooner under the provisions of Section 2.6(c) or 7.1 of the Loan Agreement, the principal indebtedness represented by this Note is payable on the Maturity Date.  The Borrower further promises to pay interest on the outstanding principal amount of the indebtedness represented by this Note from the date of this Note until payment in full at the applicable rates determined in accordance with Section 2.3(A) of the Loan Agreement.  Except as otherwise provided in the Loan Agreement, interest is payable quarterly in arrears not later than the last Business Day of each calendar quarter and is computed on the basis of a 360-day year consisting of twelve 30-day months.

If payment under this Note becomes due and payable on a Business Day, the due date of such payment is extended to the next succeeding Business Day.  In no contingency or event whatsoever will interest charged under this Note, however such interest may be characterized or computed, exceed the highest rate permissible under any law which a court of competent jurisdiction, in a final determination, deems applicable to this Note.  In the event that such a court determines that the Lender has received interest under this Note in excess of the highest rate applicable to this Note, any such excess interest collected by the Lender is deemed to have been a repayment of principal and be so applied.

The obligations of the Borrower under this Note is secured by certain collateral as and to the extent set forth in the Loan Agreement.  This Note is subject to prepayment at the option of the Borrower as provided in the Loan Agreement.

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DEMAND, PRESENTMENT, PROTEST AND NOTICE OF NONPAYMENT AND PROTEST ARE WAIVED BY THE BORROWER.

This Note has been delivered and is deemed to have been made, at Wilmington, Delaware and will be interpreted in accordance with the internal law as (as opposed to conflicts of law provisions) and decisions of the State of Delaware.  Whenever possible each provision of this Note will be interpreted in such manner as to be effective and valid under applicable law, but if any provision of this Note is prohibited by or invalid under applicable law, such provision will be ineffective to the extent of such prohibition or invalidity, without invalidating the remainder of such provision or the remaining provisions of this Note.  Whenever in this Note reference is made to the Lender or the Borrower, such reference is deemed to include, as applicable, a reference to their respective successors and assigns.  The provisions of this Note are binding upon and inure to the benefit of said successors and assigns.  The Borrower’s successors and assigns include, without limitation, a receiver,  trustee or debtor-in-possession of or for the Borrower.

LOUISVILLE GAS AND ELECTRIC COMPANY
By:
	Title

2

EX-10.60

EXHIBIT 10.60

BLACK BEAUTY COAL COMPANY

LGE Contract # LGE02012

KU Contract # KUF02857

Amendment No. 1

AMENDMENT NO. 1 TO COAL SUPPLY AGREEMENT

THIS AMENDMENT NO. 1 TO COAL SUPPLY AGREEMENT (“Amendment No. 1”) is entered into effective as of January 1, 2004, by and between LOUISVILLE GAS AND ELECTRIC COMPANY (“LG&E”) and KENTUCKY UTILITIES COMPANY (“KU”), each a Kentucky corporation, 220 West Main Street, Louisville, Kentucky 40202 (Buyer”), and BLACK BEAUTY COAL COMPANY, an Indiana partnership, 414 South Fares Avenue, Evansville, Indiana 47702, (“Seller”).

1.0 AMENDMENTS

The Agreement heretofore entered into by the parties, dated effective January 1, 2002 and identified by the Contract Numbers set forth above, is hereby amended as follows. The January 1, 2002 Agreement and Amendment No. 1 is hereafter referred to as the “Agreement”:

2.0 TERM

2.1Section 2.0 Term, is deleted and replaced with the following provision:

Term.The term of this Agreement shall commence on January 1, 2002 and shall continue through December 31, 2007, subject to the price review set forth in § 8.1.

3.0 QUANTITY

3.1Section 3.1 Base Quantity, is deleted and replaced with the following provision:

3.1           Base Quantity. Seller shall sell and deliver and Buyer shall purchase and accept delivery of the following annual quantities of coal:

YEAR	BASE QUANTITY (TONS)
2004	1,000,000	(1)
2005	1,000,000	(1)
2006	1,000,000	(2)
2007	1,000,000	(2)

(1) Buyer will specify at Buyer’s sole option, a minimum of 500,000 tons of Quality 1 up to a maximum of 700,000 tons of Quality 1. The remainder of the Base Quantity shall be Quality 2.

(2) Pricing and Base Quantity subject to review set forth in § 8.1.

The Base Quantity will be delivered in approximately equal monthly quantities and in accordance with a mutually agreed upon schedule.

4.0          SOURCE

4.1Section 4.1 Source is deleted and replaced with the following provision:

Section 4.1 Source. The coal sold hereunder shall be supplied primarily from geological seam Indiana #6 and #5, from Seller’s Somerville Mine Complex located in Gibson County, Indiana (the “Coal Property”).

5.0          QUALITY

5.1Section 6.1 Specifications is deleted and replaced with the following provision:

Section 6.1 Specifications.

(a) The coal delivered hereunder shall conform to the following specifications on an “as received” basis:

Guaranteed Monthly Specifications	Weighted Average (1)	Rejection Limits (per shipment)
B.T.U./lb.	min. 11 000	<	10 700
CHLORINE	max. 0.03	>	0.04
FLUORINE	max. 0.005	>	0.006
NITROGEN	max. 1.40	>	1.50
ASH/SULFUR RATIO	min. 2.70:1	<	2.40:1
SIZE (3” x 0”):
Top size (inches)**	max. 3x0	>	3x0
Fines (% by wgt)
Passing 1/4” screen	max. 40	>	50
BY WEIGHT:
VOLATILE	min. 32	<	30
FIXED CARBON	min. 40	<	38
GRINDABILITY (HGI)	min. 50	<	48
BASE ACID RATIO (B/A)	.55	>	.60
SLAGGING FACTOR***	max. 2.40	>	2.60
FOULING FACTOR****	max. .35	>	.40
ASH FUSION TEMPERATURE (°F) (ASTM D1857)
REDUCING ATMOSPHERE
Initial Deformation	min. 2000	min.	1925
Softening (H=W)	min. 2025	min.	1990
Softening (H=1/2W)	min. 2050	min.	2025
Fluid	min. 2125	min.	2100
OXIDIZING ATMOSPHERE
Initial Deformation	min.	min.
Softening (H=W)	min.	min.
Softening (H=1/2W)	min.	min.
Fluid	min.	min.

(1)An actual Monthly Weighted Average will be calculated for each specification for coal delivered to the Louisville Gas and Electric generating stations and a separate actual Monthly Weighted Average will be calculated for each specification for coal delivered to the Kentucky Utility generating stations.

**  All the coal will be of such size that it will pass through a screen having circular perforations three (3) inches in diameter, but shall not contain more than fifty per cent (50%) by weight of coal that will pass through a screen having circular perforations one-quarter (1/4) of an inch in diameter.

***Slagging Factor (R_s)=(B/A) x (Percent Sulfur by WeightD_ry)
Fouling Factor (Rf)=(B/A) x (Percent Na20 by Weight_Dry)

The Base Acid Ratio (B/A) is herein defined as:

BASE ACID RATIO (B/A) =	(Fe2O3 + CaO + MgO + Na2O + K2O
	(Si02 + A1203 + Ti02)

Note: As used herein	>	means greater than:
	<	means less than.

b) In addition to the specifications set forth in § 6.1(a), the coal delivered hereunder designated as Quality 1 shall conform on an “as received” basis to the following specifications:

QUALITY 1 (1)

Specifications	Guaranteed Monthly Weighted Average (2)		Rejection Limits (per shipment)
lbs./MMB.T.U.
Sulfur	max.	3.00		> 3.25
Ash	max.	10.50		> 11.10
Moisture	max.	13.0		> 14.10

(1) Buyer will specify on a monthly basis, the qualities (Quality 1 and/or Quality 2) that are to be delivered during a calendar month, no later than twenty (20) days prior to the start of that month. During any calendar year during the term of this Agreement, Buyer shall specify on an annual basis, an annual total of at least 500,000 tons and a maximum of 700,000 tons of the base quantity tons for that calendar year as Quality 1. The remainder of the base quantity tons shall be Quality 2.

(2) An actual Monthly Weighted Average will be calculated for each specification for coal delivered to the Louisville Gas and Electric generating stations and a separate actual Monthly Weighted Average will be calculated for each specification for coal delivered to the Kentucky Utility generating stations.

(c) In addition to the specifications set forth in § 6.1(a), the coal delivered hereunder designated as Quality 2 shall conform on an “as received” basis to the following specifications:

QUALITY 2 (1)

Specifications	Guaranteed Monthly Weighted Average (2)		Rejection Limits (per shipment)
lbs./MMB.T.U.
Sulfur	max.	3.20		> 3.50
Ash	max.	10.70		> 11.50
Moisture	max.	12.50		> 13.45

(1) Buyer will specify on a monthly basis, the qualities (Quality 1 and/or Quality 2) that are to be delivered during a calendar month, no later than twenty (20) days prior to the start of that month. During any calendar year during the term of this Agreement, Buyer shall specify on an annual basis, an annual total of at least 500,000 tons and a maximum of 700,000 tons of the base quantity tons for that calendar year as Quality 1. The remainder of the base quantity tons shall be Quality 2.

(2) An actual Monthly Weighted Average will be calculated for each specification for coal delivered to the Louisville Gas and Electric generating stations and a separate actual Monthly Weighted Average will be calculated for each specification for coal delivered to the Kentucky Utility generating stations.

5.2Section 6.4 Suspension and Termination is deleted and replaced with the following provision:

If the coal sold hereunder fails to meet one (1) or more of the Guaranteed Monthly Weighted Averages set forth in § 6.1 (as to either or both of LG&E or KU) for any two (2) consecutive months or a total of three (3) months in a six (6) month period, or if six (6) barge shipments in a thirty (30) day period are rejectable by Buyer, or if Buyer receives at generating station(s) two (2) rail shipments which are rejectable in any thirty (30) day period, then Buyer may upon notice confirmed in writing and sent to Seller by certified mail, suspend future shipments except shipments already loaded into barges and/or railcars. Seller shall, within ten (10) days, provide Buyer with reasonable assurances that subsequent monthly deliveries of coal shall meet or exceed the Guaranteed Monthly Weighted Averages set forth in § 6.1. If Seller fails to provide such assurances within said ten (10) day period, Buyer may terminate this Agreement by giving written notice of such termination at the end of the ten (10) day period. A waiver of this right for any one (1) period by Buyer shall not constitute a waiver for subsequent periods. If Seller provides such assurances to Buyer’s reasonable satisfaction, shipments hereunder shall resume and any tonnage deficiencies resulting from suspension may be made up at Buyer’s sole option. Buyer shall not unreasonably withhold its acceptance of Seller’s assurances, or delay the resumption of shipment. If Seller, after providing such assurances, fails to meet any of the Guaranteed Monthly Weighted Averages (as to either LG&E or KU) for any one (1) month within the next six (6) months or if three (3) barge shipments or one (1) rail shipment are rejectable within any one (1) month during such six (6) month period, then Buyer may terminate this Agreement and exercise all its other rights and remedies under applicable law and in equity for Seller’s breach.

6.0PRICE

6.1Section 8.1 Base Price is deleted and replaced with the following provision:

8.1 Base Price. The base price (“Base Price”) of the coal to be sold hereunder will be firm and will be based on $/MMBtu and will be determined by the year in which the coal is delivered as defined in § 5 in accordance with the following schedule:

BASE PRICE—QUALITY 1

YEAR	($ Per MMBTU)	($ Per Ton)
2004	$.96591 F.O.B. Railcar	$21.25 F.O.B. Railcar
	$1.1477 F.O.B. Barge	$25.25 F.O.B. Barge
2005	$.96591 F.O.B. Railcar	$21.25 F.O.B. Railcar
	$1.1477 F.O.B. Barge	$25.25 F.O.B. Barge
2006	*	*
2007	*	*

BASE PRICE—QUALITY 2

YEAR	($ Per MMBTU)	($ Per Ton)
2004	$1.0568 F.O.B. Barge	$23.25 F.O.B. Barge
2005	$1.0568 F.O.B. Barge	$23.25 F.O.B. Barge
2006
2007

* Buyer and Seller will begin negotiations on price, quantity and other terms and conditions on or before June 1, 2005 for prices and quantities to be effective during the years 2006 and 2007. The parties then shall attempt to negotiate on new prices, quantities and/other terms and conditions between June 1, 2005 and August 1, 2005. If the parties do not reach an agreement by August 1, 2005, then this Agreement will terminate as of December 31, 2005 without liability due to such termination for either party. Notwithstanding anything herein to the contrary, the Base Price and Base Quantity set forth herein for the years 2006 and 2007 are for use as reference points for the negotiations described in this paragraph and the parties do not intend to be bound by any terms and conditions relating to the years 2006 and 2007 (including Base Price and Base Quantity) unless and until the parties reach a mutually acceptable agreement by August 1, 2005 and execute a written amendment expressly setting forth the Base Price, Base Quantity and any other terms and conditions agreed to for 2006 and 2007. This clause shall not be interpreted as a Right of First Refusal or exclusive supply agreement.

6.2Section 8.2(b) is deleted and replaced with the following provision:

8.2 (b)Notwithstanding the foregoing, for each specification, there shall be no discount if the actual Monthly Weighted Average meets the applicable Discount Point set forth below. Actual Monthly Weighted Averages will be separately calculated for the Louisville Gas and Electric generating stations and for the Kentucky Utility generating stations. However, if the actual Monthly Weighted Average for the Louisville Gas and Electric generating stations and/or the Kentucky Utility generating stations fail to meet such applicable Discount Point, then the discount shall apply to and shall be calculated on the basis of the difference between the actual Monthly Weighted Average and the Guaranteed Monthly Weighted Average pursuant to the methodology shown in Exhibit A attached hereto. The discount will be applied only to the particular company whose actual Monthly Weighted Average failed to meet the Discount Points.

QUALITY 1

Guaranteed Monthly Weighted Average		Discount Point
BTU	Min. 11,000 BTU/LB	10,850 BTU/LB
ASH	Max. 10.50 LB/MMBTU	10.80 LB/MMBTU
MOISTURE	Max. 13.00 LB/MMBTU	13.50 LB/MMBTU
SULFUR	Max. 3.00 LB/MMBTU	3.05 LB/MMBTU

QUALITY 2

Guaranteed Monthly Weighted Average		Discount Point
BTU	Min. 11,000 BTU/LB	10,850 BTU/LB
ASH	Max. 10.70 LB/MMBTU	11.10 LB/MMBTU
MOISTURE	Max. 12.50 LB/MMBTU	12.95 LB/MMBTU
SULFUR	Max. 3.20 LB/MMBTU	3.30 LB/MMBTU

For example, if the actual Monthly Weighted Average of ash (For Quality 1) equals 11.20 lb/MMBTU, then the applicable discount would be (I 1.201b. - 10.501b.) X ..0083/lb/MMBTU = $.00581/MMBTU.

7.0 CREDIT RATING

7.1Section 21.0 CREDIT RATING is added as follows.

SECTION 21.0     CREDIT RATING

If the Credit Rating (as defined below) of either Buyer (if Buyer has a public rating) falls below Investment Grade Rating (as defined below), Buyer shall, within five (5) days after Seller’s written request, provide Seller with a mutually agreed upon form of credit enhancement (e.g., letter of credit, guaranty from an investment grade entity, etc.). If no such form of credit enhancement is received by Seller, then Seller has the right to require payment in cash at the time of delivery. Such mutually acceptable assurances of good credit shall not be more than the average monthly outstanding net balance.

“Credit Rating” means, with respect to any entity, the rating then assigned to such entity’s unsecured, senior long-term debt obligations (not supported by third party credit enhancements) or if such entity does not have a rating for its senior unsecured long-term debt, then the rating then assigned to such entity as an issues rating by S&P, Moody’s or any other rating agency agreed by the Parties as set forth in the Cover Sheet.

“Investment Grade Rating” shall mean a party’s unsecured, senior long-term debt obligations (not supported by third party credit enhancements) rating from Moody’s of “Baa3” or higher and a rating from S&P of “BBB-” or higher. Moody’s shall mean Moody’s Investor Services, Inc. or its successors. S&P shall mean the Standard & Poor’s Rating Group (a division of McGraw-Hill Inc.) or its successors.

IN WITNESS WHEREOF, the parties hereto have executed this Amendment No. 1 on the day and year below written, but effective as of the day and year first set forth above.

LOUISVILLE GAS AND ELECTRIC COMPANY		BLACK BEAUTY COAL COMPANY
BY:		BY:
	Paul Thompson
	SVP - Energy Services	TITLE:
DATE:		DATE:
KENTUCKY UTILITIES COMPANY
By:
	Paul Thompson
	SVP - Energy Services
Date:

EX-10.61

EXHIBIT 10.61

KU Contract #KUF-02849
Amendment #1

AMENDMENT NO. 1 to

COAL SUPPLY AGREEMENT

THIS AMENDMENT NO. 1 to COAL SUPPLY AGREEMENT (“Amendment No. 1”) is entered into effective July 1, 2003, by and between KENTUCKY UTILITIES COMPANY, a Kentucky corporation, 220 West Main Street, Louisville, Kentucky 40202 (“KU”), and ARCH COAL SALES COMPANY, INC., a Delaware corporation, agent for the independent operating subsidiaries of ARCH COAL, INC., a Delaware corporation (collectively “Seller”), whose address is CityPlace One, Suite 300, St. Louis, Missouri 63141.

In consideration of the agreements herein contained, the parties hereto agree as follows:

1.0MODIFICATIONS TO AGREEMENT

The Agreement heretofore entered into by the parties, dated effective January 1, 2002 and identified by the Contract Number set forth above (hereinafter together referred to as “Agreement”), is hereby amended as follows:

1.1Section 3.1 Base Quantity:

The quantity schedule set forth in Section 3.1 is deleted in its entirety and is replaced with the following:

YEAR	BASE QUANTITY (TONS)
2002	600,000
2003	1,100,000
2004	800,000
2005	800,000

1.2Section 4.1. Source:

Section 4.1 is deleted in its entirety and is replaced with the following provision:

“The coal sold hereunder shall be supplied by Seller primarily from the following coal mines owned or controlled by Arch Coal, Inc., its subsidiaries or affiliates: Ruffner, Wylo, Campbell’s Creek, Ragland, Mingo-Logan, Samples and Guyan Mines located in Logan, Mingo and Kanawha Counties, West Virginia. Seller shall determine, in its discretion, which mine or mines shall produce the coal to be supplied to Buyer for each shipment, provided that Buyer receives a continuous supply of the quantity and the quality of coal to be provided hereunder. Arch Coal, Inc. benefits from this Agreement as supplier of the coal to be sold hereunder and as the parent corporation of Arch Coal Sales Co., Inc., and Arch Coal, Inc. is therefore the guarantor of Seller’s obligations hereunder pursuant to a Guaranty Agreement of even date herewith.”

1.3Section 4.5. Substitute Coal:

Section 4.5 is deleted in its entirety and is replaced with the following provision:

“Notwithstanding the above representations and warranties, in the event that Seller is unable to produce or obtain coal from the Coal Property in the quantity and of the quality required by this Agreement, and such inability is not caused by a force majeure event as defined in § 10, then Buyer will have the option of requiring that Seller supply coal from Seller’s other facilities and mines. Seller shall also have the right to supply substitute coal from sources not owned or controlled by Seller after having received Buyer’s prior written consent (which shall not be unreasonably withheld) for up to 20% of the annual volume commitments. Such substitute coal shall be provided under all the terms and conditions of this Agreement including, but not limited to, the price provisions of §8, the quality specifications of § 6.1, and the provisions of § 5 concerning reimbursement to Buyer for increased transportation costs. Seller’s delivery of coal not produced from the Coal Property without having received the express written consent of Buyer shall constitute a material breach of this Agreement.”

1.4Section 5.1. Barge Delivery:

The first literary paragraph of Section 5.1 is deleted in its entirety and is replaced by the following paragraph. All other portions of Section 5.1 shall remain unchanged.

“The coal shall be delivered to Buyer F.O.B. barge at the following points (the “Delivery Point”), for coal delivered from the Ruffner Mine, the Wylo Mines, the Samples Mine, the Ragland Mine, the Mingo-Logan Mine and the Guyan Mine: Huntington Coal Terminal (HCT), KRT-Ceredo, Ohio River Terminal (ORT) and Arch Coal Terminal (ACT) located at mile points 309.1, 314.5, 306.0 and 318.0 respectively on the Ohio River. For coal delivered from the Campbell’s Creek Mine: Port Amherst Dock located at mile point 63.9 on the Kanawha River. Seller may deliver the coal at a location different from the Delivery Points, provided, however, that Seller shall reimburse Buyer for any resulting increases in the cost of transporting the coal to Buyer’s generating stations. Buyer shall retain any resulting savings in such transportation costs.

1.5Section 6.1. Specifications:

Section 6.1 is deleted in its entirety and is replaced with the following:

“6.1         Specifications.

(a) The first 1,600,000 tons of coal delivered hereunder shall conform to the following specifications on an “as received” basis:

Specifications	Guaranteed Monthly Weighted Average (1)	Rejection Limits (per shipment)
BTU/LB.	min. 12,000		<	11,800
LBS/MMBTU:
MOISTURE	max. 6.67		>	8.33
ASH	max. 10.83		>	11.66
SULFUR	max. 0.60 *		>	0.60
SULFUR	min.   NA		<	NA
CHLORINE	max. 0.142		>	0.21
NITROGEN	max. 1.190		>	1.66

* Individual barge shipment limit of 1.20 lbs. S0₂/MMBTU

SIZE (2” x 0”):
Top size (inches)**	max. 2x0	>	2x0
Fines (% by wgt)		>
Passing 1/4” screen	max. 40		50
BY WEIGHT:
VOLATILE	min.  32	<	32
FIXED CARBON	min.  52	<	50
GRINDABILITY (HGI)	min.  42	<	42
ASH FUSION TEMPERATURE (°F) (ASTM D1857)
REDUCING ATMOSPHERE
Initial Deformation	min. +2700	min.	+2700
Softening (H=W)	min. +2700	min.	+2700
Softening (H=1/2W)	min. +2700	min.	+2700
Fluid	min. +2700	min.	+2700
OXIDIZING ATMOSPHERE
Initial Deformation	min. +2700	min.	+2700

Softening (H=W)	min. +2700	min.	+2700
Softening (H=1/2W)	min. +2700	min.	+2700
Fluid	min. +2700	min.	+2700

(1) An actual Monthly Weighted Average will be calculated for each specification for coal delivered to the Kentucky Utilities Ghent generating station.

Note: As used herein	>	means greater than:
	<	means less than.

(b) After the first 1,600,000 tons of coal is delivered hereunder, the coal shall conform to the following specifications on an “as received” basis:

Specifications	Guaranteed Monthly Weighted Average (1)	Rejection Limits (per shipment)
BTU/LB.	min. 12,200		<	11
LBS/MMBTU:
MOISTURE	max. 6.67		>	8.33
ASH	max. 10.00		>	11.00
SULFUR	max. 0.60 *		>	0.60
SULFUR	min. NA		<	NA
CHLORINE	max. 0.142		>	0.21
NITROGEN	max. 1.190		>	1.66

* Individual barge shipment limit of 1.20 lbs. S0₂/MMBTU

SIZE (2” x 0”):
Top size (inches)**	max. 2x0	>	2x0
Fines (% by wgt)		>
Passing 1/4” screen	max. 40		50
BY WEIGHT:
VOLATILE	min.  32	<	32
FIXED CARBON	min.  52	<	50
GRINDABILITY (HGI)	min.  42	<	42
ASH FUSION TEMPERATURE (°F) (ASTM D1857)
REDUCING ATMOSPHERE
Initial Deformation	min. +2700	min.	+2700

Softening (H=W)	min. +2700	min.	+2700
Softening (H=1/2W)	min. +2700	min.	+2700
Fluid	min. +2700	min.	+2700
OXIDIZING ATMOSPHERE
Initial Deformation	min. +2700	min.	+2700
Softening (H=W)	min. +2700	min.	+2700
Softening (H=1/2W)	min. +2700	min.	+2700
Fluid	min. +2700	min.	+2700

(1) An actual Monthly Weighted Average will be calculated for each specification for coal delivered to the Kentucky Utilities Ghent generating station.

Note: As used herein	>	means greater than:
	<	means less than.

1.6Section 8.1. Base Price:

Section 8.1 is deleted in its entirety and is replaced with the following provision:

“8.1 For the first 1,600,000 tons shipped, the base price (“Base Price”) of the coal to be sold hereunder will be firm during each time period of this Agreement in accordance with the following schedule, subject to adjustment only for quality variations pursuant to §8.2 and New Costs pursuant to §8.4:

		BASE PRICE
PERIOD	LOADING POINT	($ PER MMBTU)	($ PER TON)
1/1/02 - 12/31/03	Huntington, WV Docks	1.8333 F.O.B. barge	$	44.00

For tons shipped after the first 1,600,000 tons, the base price (“Base Price”) of the coal to be sold hereunder will be firm during each time period of this Agreement in accordance with the following schedule, subject to adjustment only for quality variations pursuant to §8.2 and New Costs pursuant to §8.4:

				BASE PRICE
PERIOD			LOADING POINT	($ PER MMBTU)	($ PER TON)
10/1/03	-	12/31/03	Huntington, WV Docks	1.4344 F.O.B. barge	$	35.00
1/1/04	-	12/31/04	Huntington, WV Docks	1.5164 F.O. B. barge	$	37.00
1/1/05	-	12/31/05	Huntington WV Docks	1.5471 F.O. B. barge	$	37.75

1.8.Section 8.2.(b). Quality Price Discounts:

The text of Section 8.2.(b) is deleted in its entirety and is replaced with the following provision:

(b) (i) The quality price discounts for the first 1,600,000 tons of coal delivered hereunder shall conform to the following:

Notwithstanding the foregoing, for each specification, there shall be no discount if the actual Monthly Weighted Average meets the applicable Discount Point set forth below. However, if the actual Monthly Weighted Average for the Kentucky Utilities Ghent generating station fails to meet such applicable Discount Point, then the discount shall apply to and shall be calculated on the basis of the difference between the actual Monthly Weighted Average and the Guaranteed Monthly Weighted Average pursuant to the methodology shown in Exhibit A attached hereto.

	Guaranteed Monthly Weighted Average	Discount Point
BTU/LB	Min. 12,000	11,800
LB/MMBTU:
ASH	Max. 10.83	10.83
MOISTURE	Max. 6.67	8.33
	Guaranteed Barge LbsSO2/Mmbtu	Discount Point
LB/MMBTU:
SO2	Max. 1.20	1.20

For example, if the actual Monthly Weighted Average of ash equals 11.00 lb/MMBTU, then the applicable discount would be (11.00 lb./mmbtu - 10.83 lb./mate) X $.0083 lb./mmbtu = $.001411 /mmBtu.

(b)(ii) The quality price discounts after the first 1,600,000 tons of coal is delivered hereunder shall conform to the following:

Notwithstanding the foregoing, for each specification, there shall be no discount if the actual Monthly Weighted Average meets the applicable Discount Point set forth below. However, if the actual Monthly Weighted Average for the Kentucky Utilities Ghent generating station fails to meet such applicable Discount Point, then the discount shall apply to and shall be calculated on the basis of the difference between the actual Monthly Weighted Average and the Guaranteed Monthly Weighted Average pursuant to the methodology shown in Exhibit A attached hereto.

	Guaranteed Monthly Weighted Average	Discount Point
BTU/LB	Min. 12,200	12,000
LB/MMBTU:
ASH	Max. 10.00	10.60
MOISTURE	Max. 6.67	8.33
	Guaranteed Barge LbsSO2/Mmbtu	Discount Point
LB/MMBTU:
SO2	Max. 1.20	1.20

For example, if the actual Monthly Weighted Average of ash equals 11.00 lb/MMBTU, then the applicable discount would be (11.00 lb./mmbtu - 10.00 lb./mmBtu) X $.0083 lb./mmbtu = $.00830/MMBTU.

2.0STATUS OF AGREEMENT

The Agreement, as amended by this Amendment No. 1, is hereby ratified and confirmed and shall continue in full force and effect. Unless hereby amended, all terms and conditions of the Agreement shall apply to this Amendment No. 1. This Amendment No. 1 is the final and complete agreement of the parties hereto respecting the subject matter hereof and hereby supersedes all prior or contemporaneous oral or written statements, understandings and promises of the parties relating to the subject matter hereof.

IN WITNESS WHEREOF, the parties hereto have executed this Agreement on the dates below written, but effective as of the day and year first set forth above.

KENTUCKY UTILITIES COMPANY	ARCH COAL SALES COMPANY, INC.
By	By
Title	Title
Date	Date

EX-10.62

EXHIBIT 10.62

Contract #96-412-026
Hopkins County Coal, LLC
Amendment No. 1

AMENDMENT NO. 1 TO AMENDED AND RESTATED COAL SUPPLY AGREEMENT

THIS AMENDMENT NO. 1 TO AMENDED AND RESTATED COAL SUPPLY AGREEMENT (“Amendment No. 1”) is entered into effective as of January 1, 2000, by and between LOUISVILLE GAS AND ELECTRIC COMPANY (hereinafter referred to as “Buyer”), whose address is 220 West Main Street, Louisville, Kentucky 40202, and HOPKINS COUNTY COAL, LLC, a Delaware limited liability company and WEBSTER COUNTY COAL, LLC, a Delaware limited liability company (successor to WEBSTER COUNTY COAL CORPORATION, a Kentucky corporation), both having an address of 1717 South Boulder Avenue, Tulsa, Oklahoma 74119-4886, (the foregoing companies hereinafter referred to as “Seller”). In consideration of the agreements herein contained, the parties hereto agree as follows.

1.0 AMENDMENTS

The Amended and Restated Agreement heretofore entered into by the parties, dated effective April 1, 1998, and identified by the Contract Number set forth above, (hereinafter referred to as “Agreement”) is hereby amended as follows:

2.0 TERM

2.1           Section 2.0 Term, is hereby modified to read as follows:

“The Term of this Agreement shall continue through December 31, 2001.”

3.0 QUANTITY

3.1Section 3.0 Quantity, is deleted and replace with the following:

“During the Term, Seller shall deliver and Buyer shall purchase and accept delivery of the following quantities of coal.

YEAR	BASE QUANTITY (TONS)
December 1999	60,000	*
2000	1,250,000
2001	1,250,000

* The additional 60,000 tons in December 1999 are in addition to the base quantity of 1,500,000 tons for 1999 and are priced as set forth in Section 8.1.

Such coal shall be delivered ratably throughout the Term in accordance with reasonable delivery schedules to be mutually agreed by Buyer and Seller.”

3.2Section 3.1 Option to Increase or Decrease Quantity is added and reads as follows:

“Buyer shall have the right to increase or decrease the Base Quantity to be delivered hereunder by up to 31,250 tons per calendar quarter (three months), for example, if Buyer increases the quantity by 31,250 tons each quarter during a calendar year, the net increase will be 125,000 tons. Buyer shall exercise such option by giving Seller such notice stating Buyer’s exercise of the option and specifying the increase or decrease in tonnage, no later than thirty days prior to the first day of the quarter in which the increased or decreased tonnage will be delivered.”

4.0 SOURCE

4.1Section 4.1 Source is hereby deleted and replaced with the following:

“The coal sold hereunder shall be supplied from any one of the geological seams Western Kentucky #11, #12, and #9 (surface and underground), of any one of the Seller’s Hopkins County Mines, and/or from Seller’s Webster County Coal, LLC Dotiki Mine Complex, (all of the foregoing sources herein after referred to as the “Coal Property”).”

5.0 DELIVERY

5.1Section 5.1 Buyer’s Option is hereby deleted and replaced with the following:

“The Delivery Points shall be designated as follows: For the Hopkins County mines, the coal shall be delivered F.O.B. railcar at the Hopkins County rail loading facility near Madisonville, Kentucky on the Paducah and Louisville Railroad (the “Delivery Point”). For mines in the Dotiki Mine Complex, the coal shall be delivered F.O.B. railcar at the Dotiki rail loading facility near Madisonville, Kentucky on the CSXT Railroad which is accessible by the Paducah and Louisville Railroad (the “Delivery Point”). Seller may deliver the coal at a location different from the Delivery Points, provided, however that Seller shall reimburse Buyer for any resulting increases in the cost of transporting the coal to Buyer’s generating stations. Any resulting savings in such transportation costs shall be shared by Buyer and Seller. Buyer may request to change the Delivery Point to either F.O.B. truck or F.O.B. barge. Upon Buyer’s

notification to Seller of its desire to change the Delivery Point, Buyer and Seller shall mutually agree in writing upon the change(s) and the time frame wherein such change will take place.”

5.2Section 5.3 Delivery to Sebree Dock is deleted in its entirety.

6.0 QUALITY

6.1Section 6 Quality is amended as follows:

“Seller has the option to supply coal of two different qualities, noted as Quality #1 and Quality #2. Seller shall exercise such option by giving Buyer such notice stating Seller’s intent to supply coal of Quality #1 or Quality #2, no later than the fifteenth of the month, prior to the first day of the calendar month during which that particular coal Quality will be delivered. After Seller gives notice of the particular quality to be delivered for a given calendar month, Seller must supply coal of that quality for the entire calendar month. Seller shall not supply coals of Quality #1 and Quality #2 during the same calendar month.

The following specifications are amended:

QUALITY #1

All specifications are the same as specified in Section 6.1 of the Amended and Restated Coal Supply Agreement for coal to be delivered during the Secondary Term.

QUALITY #2

Specifications	Guaranteed Monthly Weighted Average	Rejection Limits (per shipment)
BTU/LB.	Min. 11,200	<10,900
ASH (lbs/Mmbtu)	Max. 12.00	>13.00

All other specifications are the same as specified in Section 6.1 of the Amended and Restated Coal Supply Agreement for coal to be delivered during the Secondary Term.

6.2Section 6.4 Suspension and Termination is deleted and replaced with the following:

“If the coal sold hereunder fails to meet one or more of the Guaranteed Monthly Weighted Averages set forth in §6.1 for any two months during any twelve month rolling period during the term of this Agreement, or if two (2) truck shipments or three (3) barge shipments in a seven-day period are rejectable by Buyer, or if Buyer receives at its generating station two (2) rail shipments which are rejectable in any ten-day period, Buyer may, upon notice confirmed in writing and sent to Seller by certified mail, terminate this Agreement and exercise all its other rights and remedies under applicable law and in equity for Seller’s breach.”

7.0 PRICE

7.1Section 8.1 Base Price is deleted and replaced with the following:

“The base price (“Base Price”) of the coal to be sold hereunder will be firm and in accordance with the following schedule:

QUALITY #1 - - HOPKINS COUNTY MINE

	BASE PRICE
Year	$ Per MMBtu		$ Per Ton A 11,400Btu
2000	$	0.8224	$	18.75
2001	$	0.8224	$	18.75

QUALITY #2 - - HOPKINS COUNTY MINE

	BASE PRICE
Year	$ Per MMBtu		$ Per Ton A 11,200 Btu
2000	$	0.8100	$	18.14
2001	$	0.8100	$	18.14

QUALITY #1- DOTIKI MINE

	BASE PRICE
Year	$ Per MMBtu		$ Per Ton A 11,400Btu
2000	$	0.7952	$	18.13
2001	$	0.7952	$	18.13

QUALITY #2 - - DOTIKI MINE

	BASE PRICE
Year	$ Per MMBtu		$ Per Ton (a, 11,200 Btu
2000	$	0.7821	$	17.52
2001	$	0.7821	$	17.52

7.2Section 8.2 Quality Price Discounts, paragraph (b) is deleted and replaced with the following:

“Notwithstanding the foregoing, for each specification each month, there shall be no discount if the actual Monthly Weighted Average meets the applicable Discount Point set forth below. However, if the actual Monthly Weighted Average fails to meet such applicable Discount Point, then the discount shall be calculated on the basis of the difference between the actual Weighted Average and the Guaranteed Monthly Weighted Average pursuant to the methodology shown in Exhibit A of the Agreement.

The Guaranteed Monthly Weighted Average and Discount Points shall be calculated as follows:

QUALITY #1

	Guaranteed Monthly Weighted Average	Discount Point
BTU/Lb.	Min. 11,400	11,250
Lb/MMBtu
SULFUR	Max. 3.125	3.325
ASH	Max. 11.75	12.50
MOISTURE	Max. 11.50	13.00

QUALITY #2

	Guaranteed Monthly Weighted Average	Discount Point
BTU/Lb.	Min. 11,200	11,050
Lb/MMBtu
SULFUR	Max. 3.125	3.325
ASH	Max. 12.00	12.75
MOISTURE	Max. 11.50	13.00

For example, if the Monthly Weighted Average of ash for Quality #1 equals 13.5 lb/MMBtu, then the applicable discount would be (13.5 lb - 11.75 lb.) X $0.0083/lb./MMBtu = $0.01453/MMBtu.

7.3Section 8.3 Price, Terms and Conditions Review is deleted in its entirety.

IN WITNESS WHEREOF, the parties hereto have executed this Amendment No. 1 on the day and year below written, but effective as of the day and year first set forth above.

HOPKINS COUNTY COAL, LLC.	LOUISVILLE GAS AND ELECTRIC COMPANY
BY:	BY:
TITLE:	TITLE:
DATE:	DATE:
WEBSTER COUNTY COAL, LLC
BY:
TITLE:
DATE:

EX-10.63

EXHIBIT 10.63

Contract #96-412-026
Hopkins County Coal, LLC
Amendment No. 2

AMENDMENT NO. 2 TO AMENDED AND RESTATED COAL SUPPLY AGREEMENT

THIS AMENDMENT NO. 2 TO AMENDED AND RESTATED COAL SUPPLY AGREEMENT (“Amendment No. 2”) is entered into effective as of September 15, 2000, by and between LOUISVILLE GAS AND ELECTRIC COMPANY (hereinafter referred to as “Buyer”), whose address is 220 West Main Street, Louisville, Kentucky 40202, and HOPKINS COUNTY COAL, LLC, a Delaware limited liability company and WEBSTER COUNTY COAL, LLC, a Delaware limited liability company (successor to WEBSTER COUNTY COAL CORPORATION, a Kentucky corporation), both having an address of 1717 South Boulder Avenue, Tulsa, Oklahoma 74119-4886, (the foregoing companies hereinafter referred to as “Seller”). In consideration of the agreements herein contained, the parties hereto agree as follows.

RECITALS

A.On even date herewith, Buyer entered into Coal Synfuel Purchase Order LGE00024, which is governed by the terms and conditions of Negotiated Contract LGE00019, (“Coal Synfuel Supply Agreement”) with ECO Coal Pelletization No. 12, LLC (“ECO”) for the purchase of coal synfuel which shall be processed from coal which is produced or supplied to ECO from Hopkins County Coal, LLC.

B.For each ton of coal synfuel Buyer purchases from ECO during the term of the Coal Synfuel Supply Agreement, Buyer and Seller hereby agree to reduce by like amount the quantity of coal to be purchased under the Amended and Restated Coal Supply Agreement as is more particularly set forth herein below.

1.0 AMENDMENTS

The Amended and Restated Agreement heretofore entered into by the parties, dated effective April 1, 1998, as amended by Amendment No. 1 dated January 1, 2000 and identified by the Contract Number set forth above, (hereinafter referred to as “Agreement”) is hereby amended as follows:

2.0 QUANTITY

2.1Section 3.2 Coal Synfuel Quantity, is added and reads as follows:

“During the Term, any quantity of coal synfuel purchased by Buyer from ECO under the Coal Synfuel Supply Agreement shall reduce the Quantity of coal to be supplied under this Agreement, by an equal amount of tonnage.”

3.0 INDEPENDENT RELATIONSHIP OF AGREEMENT TO COAL SYNFUEL SUPPLY AGREEMENT.

3.1Section 21 Independent Relationship of Agreement to Coal Synfuel Supply Agreement, is added and read as follows:

“Except for the tonnage reduction provision set forth under Section 3.2 herein above, all obligations between Buyer and Seller set forth in this Agreement shall continue through its Term. If Buyer reduces and/or suspends its purchases of coal synfuel under the Coal Synfuel Supply Agreement and/or either Buyer or ECO terminates the Coal Synfuel Supply Agreement for any reason, this Agreement shall remain in full force and effect and Buyer and Seller shall be obligated to continue their performance as required herein through the Term of this Agreement. In no event shall nonperformance or breach by Buyer or ECO under provisions of the Coal Synfuel Supply Agreement be a basis for Buyer or Seller to claim nonperformance or breach or grant a right of offset, counter claim or cancellation of this Agreement, and this Agreement shall continue in full force and effect with the remaining obligations for the purchase of quantities of coal to be the Quantity set forth in Section 3.0 during any contract year reduced by the amount of coal synfuel delivered by ECO to Buyer during such contract year.”

IN WITNESS WHEREOF, the parties hereto have executed this Amendment No. 2 on the day and year below written, but effective as of the day and year first set forth above.

HOPKINS COUNTY COAL, LLC.	LOUISVILLE GAS AND ELECTRIC COMPANY
BY:	BY:
TITLE:	TITLE:
DATE:	DATE:
WEBSTER COUNTY COAL, LLC
BY:
TITLE:
DATE:

EX-10.64

EXHIBIT 10.64

Peabody COALSALES Company
Contract #LGE 02011
Amendment No. 3

AMENDMENT NO. 3 TO COAL SUPPLY AGREEMENT

THIS AMENDMENT NO. 3 TO COAL SUPPLY AGREEMENT (“Amendment No. 3”) is entered into effective as of September 15, 2003, by and between LOUISVILLE GAS AND ELECTRIC COMPANY, a Kentucky corporation, 220 West Main Street, Louisville, Kentucky 40202 (Buyer”), and PEABODY COALSALES COMPANY, a Delaware corporation, 701 Market Street, Suite 830, St. Louis, Missouri 63101-1826 (“Seller”). In consideration of the agreements herein contained, the parties hereto agree as follows.

1.0 AMENDMENTS

The Agreement heretofore entered into by the parties, dated effective January 1, 2002 and identified by the Contract Number set forth above, as amended by Amendment No. 1 dated effective June 1, 2002, and Amendment No. 2 dated effective January 1, 2003 is hereby further amended as follows, the January 2, 2002 Agreement, as amended by Amendment No. 1, Amendment No. 2, and Amendment No. 3 is hereafter referred to as the “Agreement”:

2.0 QUANTITY

2.1Section 3.1 Quantity, is deleted in its entirety and replaced with the following:

3.1Quantity.

3.1.1 Seller shall sell and deliver and Buyer shall purchase and accept delivery of the following annual quantities of coal and/or coal synfuel:

YEAR	BASE QUANTITY (TONS)
2002	600,000
2003	350,000	- Quality A
	250,000	- Quality B
	400,000	- Coal Synfuel
2004	600,000	- Coal Synfuel/Coal
	250,000	- Quality B

3.1.2 In the event all or part of the Coal Synfuel quantities set forth in Section 3.1.1 above (i) cannot be unloaded or otherwise handled by Buyer without additional expense to Buyer, or (ii) causes adverse effects on the operation of Buyer’s generating stations (hereinafter referred to as an “Adverse Effect”), without limiting

any of the remedies of Buyer hereunder, Buyer shall have the right to elect to take all or part of such Coal Synfuel tonnage listed above as coal designated as Quality A.

3.1.3 In the event all or part of the Coal Synfuel quantities set forth in Section 3.1.1 above cannot be timely delivered by Seller or otherwise becomes unavailable as a result of the curtailing, reduction and/or ending of production at the Gilbraltar Coal Synfuel facility, Seller shall timely supply all or part of such Coal Synfuel tonnage listed above as coal designated as either Quality A or Quality B, at Seller’s option.

3.0 SOURCE

3.1Section 4.1 Source, is deleted in its entirety and replaced with the following:

4.1Source. The coal sold hereunder, including coal purchased by Seller from third parties, shall be supplied from the geological seams known as the Western Kentucky #9 and #11 seams. Coal designated as Quality A, as defined below, shall be supplied from the mining complex in Union County, Kentucky which is owned and operated by Seller’s affiliated company, Highland Mining Company (“Highland”). Coal designated as Quality B, as defined below, shall be supplied from: (i) the “Patriot Mining Complex” in Henderson County which consists of the Patriot Mine (a surface mining operation which is owned and operated by Seller’s affiliated company, Patriot Coal Company, LP (“Patriot”)) and the “Freedom Mine” (which is operated by Seller’s affiliated company, Ohio County Coal Company (“Ohio County”)); (ii) the Camp Complex in Henderson County, or (iii) the Gibraltar Mine in Muhlenberg County. Coal Synfuel sold hereunder shall be supplied from the Gibraltar Coal Synfuel Plant located in Muhlenberg County, Kentucky. The Camp Complex and the Gibraltar Mine are both owned and operated by Seller’s affiliated company, Peabody Coal Company (“Peabody Coal”). All of the foregoing sources of coal are hereinafter referred to as the “Coal Properties”. Highland, Patriot, Ohio County and Peabody shall be referred to collectively herein as “Producer.”

4.0 QUALITY

4.1Section 6.1.1 Quality A, is deleted in its entirety and replaced with the following:

Quality A. The coal delivered hereunder which is designated as Quality A and the coal synfuel delivered hereunder shall conform to the following specifications on an “as received” basis:

QUALITY A

Specifications	Guaranteed Monthly Weighted Average (1)	Rejection Limits (per shipment)
BTU/LB.	min. 11,400	< 10 800
LBS/MMBTU:
MOISTURE	max. 10.53	> 12.00
ASH	max. 8.33	> 9.00
SULFUR	max. 2.89	> 3.10
SULFUR	min. 2.30	< 2.00
CHLORINE	max. 0.009	> .015
FLUORINE	max.
NITROGEN	max. 1.32	> 1.70
ASH/SULFER RATIO	min 3.22:1	> 3:1
SIZE (3” x 0”):
Top size (inches)*	max. 3x0	> 4x0
Fines (% by wgt) Passing 1/4” screen	max. 60	> 65
BY WEIGHT:
VOLATILE	max. 30	>29
FIXED CARBON	max. 43	>40
GRINDABILITY (HGI)	min. 50	<48
BASE ACID RATIO (B/A)	0.40	0.50
SLAGGING FACTOR**	max. 1.32	> 1.80
FOULING FACTOR***	max. 0.32	> 0.40
ASH FUSION TEMPERATURE (°F) (ASTM D1857)
REDUCING ATMOSPHERE
Initial Deformation	min. 1990	min. 1990
Softening (H=W)	min. 2065	min. 2050
Softening (H=1/2W)	min. 2105	min. 2075
Fluid	min. 2225	min. 2200
OXIDIZING ATMOSPHERE
Initial Deformation	min. 2330	min. 2300
Softening (H=W)	min. 2355	min. 2325
Softening (H=1/2W)	min. 2400	min. 2370
Fluid	min. 2480	min. 2400

(1) An actual Monthly Weighted Average will be calculated for each specification for coal delivered to the Buyer’s generating stations.

* All the coal will be of such size that it will pass through a screen having circular perforations three (3) inches in diameter, but shall not contain more than fifty (50) per cent (50%) by weight of coal that will pass through a screen having circular perforations one-quarter (1/4) of an inch in diameter.

**Slagging Factor (R_s)=(B/A) x (Percent Sulfur by WeightDr_y)

***Fouling Factor (Rf)=(B/A) x (Percent Na₂O by WeightDy)

The Base Acid Ratio (B/A) is herein defined as:

BASE ACID RATIO (B/A) =	Fe2O3 + CaO + MgO + Na2O + K2O
	(Si02 + Al2O3 + T1O2)

Note: As used herein	>	means greater than:
	<	means less than.

5.0 PRICE

5.1Section 8.1 Base Price is deleted and replaced with the following:

The base price (“Base Price”) of the coal and coal synfuel to be sold hereunder will be firm and will be determined by the criteria set forth in Section 5 in accordance with the following schedule:

Year	Coal Synfuel Base Price (F.O. B. Barge)
2003		$1.0557 per MMBtu	$24.07 per ton
2004		$1.0886 per MMBtu	$24.82 per ton (1)

(1) Any shortfall of tonnage from calendar year 2003 will be the first tons shipped and unloaded in calendar year 2004. Such carryover tonnage will be priced at the 2003 price until all of the carryover tonnage has been delivered and unloaded.

Year	Coal Base Price Quality A (F.O.B. Barge)
2002		$1.1224 per MMBtu	$25.59 per ton
2003		$1.1224 per MMBtu	$25.59 per ton*
2003		$1.1351 per MMBtu	$25.88 per ton**
2004		$1.1680 per MMBtu	$26.63 per ton

* The Base Price for the first 150,000 tons of Quality A delivered in 2003

** The Base Price for the remainder of the tons of Quality A delivered in 2003

Year	Coal Base Price Quality B (F.O.B. Barge)
2003		$0.90 per MMBtu	$19.53 per ton
2004		$0.91 per MMBtu	$19.75 per ton

IN WITNESS WHEREOF, the parties hereto have executed this Amendment No. 3 on the day and year below written, but effective as of the day and year first set forth above.

LOUISVILLE GAS AND ELECTRIC COMPANY		PEABODY COALSALES COMPANY
BY:		BY:
	SVP - Energy Marketing
		TITLE:
DATE:		DATE:

EX-10.65

Exhibit 10.65

LG&E ENERGY CORP. LONG-TERM PERFORMANCE UNIT PLAN

Effective January 1, 2003

ARTICLE 1.  ESTABLISHMENT, PURPOSE, AND DURATION

1.1.         Establishment of the Plan.

LG&E Energy Corp, (hereinafter referred to as the “Company”) establishes as of the date set forth above the “LG&E Energy Corp. Long-Term Performance Unit Plan” (hereinafter referred to as the “Plan”), which permits the grant of Performance Units, as hereinafter defined, to employees of LG&E Energy Corp. and its Subsidiaries. The Plan was approved by the Board of Directors of the Company in a consent resolution dated April 25, 2003.

1.2.         Purpose of the Plan.

The purpose of the Plan is to promote the success of the Company and its Subsidiaries by providing incentives to Key Employees that will link their personal interests to the long-term financial success of the Company and its Subsidiaries and to growth in Parent shareholder value.  The Plan is designed to provide flexibility to the Company and its Subsidiaries in their ability to motivate, attract, and retain the services of Key Employees upon whose judgment, interest, and special effort the successful conduct of their operations is largely dependent.  Grants under the Plan may be made in conjunction with grants of phantom options under the E.ON Phantom Option Plan in the case of certain Key Employees.

1.3.         Duration of the Plan.

The Plan is effective as of January 1, 2003.  The Plan shall remain in effect, subject to the right of the Board of Directors to terminate the Plan at any time pursuant to Article 9 herein.

ARTICLE 2.  DEFINITIONS AND CONSTRUCTION

2.1.         Definitions.

Whenever used in the Plan, the following terms shall have the meanings set forth below and, when the meaning is intended, the initial letter of the word is capitalized:

(a)“Award” means a grant under this Plan of Performance Units.

(b)“Beneficial Ownership” shall have the meaning ascribed to such term in Rule 13d-3 of the General Rules and Regulations under the Exchange Act.

(c)“Board” or “Board of Directors” means the Board of Directors of the Company.

(d)“Cause” shall mean the occurrence of any one of the following:

(i)The willful and continued failure by a Participant to substantially perform his/her duties (other than any such failure resulting from the Participant’s disability), after a written demand for substantial performance is delivered to the Participant that specifically identifies the manner in which the Company or any of its Subsidiaries, as the case may be, believes that the Participant has not substantially performed his/her duties, and the Participant has failed to remedy the situation within ten (10) business days of receiving such notice; or

(ii)the Participant’s conviction for committing a felony in connection with the employment relationship; or

(iii)the willful engaging by the Participant in gross misconduct materially and demonstrably injurious to the Company or any of its Subsidiaries. However, no act, or failure to act, on the Participant’s part shall be considered “willful” unless done, or omitted to be done, by the Participant not in good faith and without reasonable belief that his/her action or omission was in the best interest of the Company or any of its Subsidiaries.

(e)“Change in Control” shall be deemed to have occurred if the conditions set forth in any one of the following paragraphs shall have been satisfied:

(i)Parent is notified by a third party that it has acquired 25 percent or more of the voting rights of Parent in accordance with § 21 of the German Securities Trading Act (WpHG), or

(ii)a third party on its own or together with voting rights attributable to him in accordance with § 22 German Securities Trading Act (WpHG) has acquired a share in voting rights which, at Parent’s Annual Shareholders’ Meeting, would represent or which, at Parent’s last Annual Shareholders’ Meeting, would have represented the majority of the voting rights present at such a Meeting, or

(iii)an affiliation agreement is concluded with Parent as controlled company in accordance with §§ 291 ff. of the German Stock Corporation Act (AktG), or

(iv)Parent is being integrated in accordance with §§ 319 ff. of the German Stock Corporation Act (AktG), or

(v)Parent changes its legal status in accordance with §§ 190 ff. of the German Conversion Law (UmwG), or

(vi)Parent is being merged with another legal entity, provided that the enterprise value of such legal entity is more than 20 percent of the enterprise value of Parent at the time of adopting the resolution by Parent.  The methods of valuation acknowledged by the professional association of qualified auditors (Stellungnahme des Hauptfachausschusses des Instituts der Wirtschaftsprüfer HF 2/1983 = Grundsätze zur Durchführung von Untemehmensbewertungen sowie die neueren Verlautbarungen des Berufsstandes) shall be used to determine the value of both entities, to the extent that both enterprise values will be determined according to said methods in connection with the merger.  Otherwise, the market capitalization of both legal entities at the time the resolution is adopted by Parent will be deemed as their respective enterprise values.  If a market capitalization cannot be determined, the enterprise values agreed upon by both legal entities will be deemed as their respective values.

(vii)Company ceases to be an affiliated company of Parent as defined in § 15 of the German Stock Corporation Act or where the following apply:

(a)A complete liquidation or dissolution of the Company unless, the Parent continues to own directly or indirectly all or substantially all of the Company’s assets;

(b)An agreement for the sale or other disposition of all or substantially all of the assets of the Company to any person or entity (other than a subsidiary of the Parent);

(c)A merger or other combination involving the Company as a result of which Parent ceases to beneficially own more that 50% of the outstanding Voting Stock, of the successor to the Company, unless the Parent or its subsidiary continues to own directly or indirectly all or substantially all of the Company’s assets; or

(d)Any person or entity acquires Beneficial Ownership of a greater percentage of the Voting Stock of the Company than the percentage or such Voting Stock then held, directly or indirectly by Parent.

(f)“Committee” means the Senior Vice President, Group Corporate Officer Resources -of the Parent and any other person, if any, designated by the Chairman and Chief Executive Officer of the Parent to administer the Plan pursuant to Article 3 herein.

(g)“Company” means LG&E Energy Corp., a Kentucky corporation, or any successor thereto as provided in Article 11 herein.

(h) “Exchange Act” means the Securities Exchange Act of 1934, as amended from time to time.

(i)“Key Employee” means (i) an employee of the Company or any of its Subsidiaries, including an employee who is an officer or a director of the Company or any of its Subsidiaries, who, in the opinion of the Committee, can contribute significantly to the growth and profitability of the Company and its Subsidiaries, (ii) may include employees who are members of the Board who are employees, or (iii) any other employee, identified by the Committee, in special situations involving extraordinary performance, promotion, retention, or recruitment.  The granting of an Award under this Plan shall be deemed a determination by the Committee that such employee is a Key Employee, but shall not create a right to remain a Key Employee.

(j)“Parent” means E.ON AG, an anktiengesellschaft formed under the Federal Republic of Germany, or any successor thereto as provided in Article 11 herein.

(k)“Participant” means a Key Employee who has been granted an Award under the Plan.

(l)“Performance Unit” means an Award, designated as a performance unit, granted to a Participant pursuant to Article 5 herein.

(m)“Person” shall have the meaning ascribed to such term in Section 3(a) (9) of the Exchange Act and used in Sections 13(d) and 14(d) thereof, including a “group” as defined in Section 13(d) thereof.

(n)“Plan” means this LG&E Energy Corp. Long-Term Performance Unit Plan, as herein described and as hereafter from time to time amended.

(o)“Subsidiary” shall mean any corporation of which more than 50% (by number of votes) of the Voting Stock at the time outstanding is owned, directly or indirectly,

by the Company.

(p)“Voting Stock” shall mean securities of any class or classes of stock of a corporation, the holders of which are ordinarily, in the absence of contingencies, entitled to elect a majority of the corporate directors.

2.2.         Gender and Number.

Except where otherwise indicated by the context, any masculine term used herein also shall include the feminine, the plural shall include the singular, and the singular shall include the plural.

2.3.         Severability.

In the event any provision of the Plan shall be held illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining parts of the Plan, and the Plan shall be construed and enforced as if the illegal or invalid provision had not been included.

ARTICLE 3.  ADMINISTRATION

3.1.         The Committee.

The Plan shall be administered by the Committee as permitted by law and Article 3.5.

3.2.         Authority of the Committee.

Subject to the provisions of the Plan, the Committee shall have full power to construe and interpret the Plan; to establish, amend or waive rules and regulations for its administration; to accelerate the end of a performance period or the termination of any award agreement; and (subject to the provisions of Article 9 herein) to amend the terms and conditions of any outstanding Award to the extent such terms and conditions are within the discretion of the Committee as provided in the Plan. The Committee shall not have authority to resolve disputed claims under the Plan.

3.3.         Selection of Participants.

The Committee shall have the authority to grant Awards under the Plan, from time to time, to such Key Employees (including officers and directors who are employees) as may be selected by it.  The Committee shall select Participants from among those whom they have identified as being Key Employees.

3.4.         Decisions and Appeals.

All determinations and decisions made by Committee pursuant to the provisions of the Plan may be reviewed by the Chairman and Chief Executive Officer of the Parent, upon

the written request of either the Committee or a Participant.  Any determination made by the Chairman and Chief Executive Officer of the Parent, pursuant to this section shall be final, conclusive and binding on all persons, including the Company and its Subsidiaries, its shareholders, employees, and Participants and their estates and beneficiaries, and such determinations and decisions shall not be subject to review.

3.5.         Delegation of Certain Responsibilities.

The Committee may delegate to an appropriate party any of its responsibilities under the Plan.

3.6.         Procedures of the Committee.

To the extent the Committee is comprised of more than one member, all determinations of the Committee or any delegates shall be made by not less than a majority of members present at any meeting (in person or otherwise) at which a quorum is present.  A majority of the entire Committee or the number of delegates at a given time shall constitute a quorum for the transaction of business.  Any action required or permitted to be taken at a meeting of the Committee or the delegates may be taken without a meeting if a unanimous written consent, which sets forth the action, is signed by each member of the Committee and filed with the minutes for proceedings of the Committee or delegates.

3.7.         Award Agreements.

Each Award under the Plan shall be evidenced by an award agreement which shall be signed by an authorized officer of the Company and by the Participant, and shall contain such terms and conditions as may be approved by the Committee.  Such terms and conditions need not be the same in all cases.

ARTICLE 4.  ELIGIBILITY AND PARTICIPATION

4.1.         Eligibility.

Persons eligible to participate in this Plan include all employees of the Company and its Subsidiaries who, in the opinion of the Committee, are Key Employees.

4.2.         Actual Participation.

Subject to the provisions of the Plan, the Committee may from time to time select those Key Employees to whom Awards shall be granted and determine the nature and amount of each Award.  No employee shall have any right to be granted an Award under this Plan even if previously granted an Award.

ARTICLE 5.  PERFORMANCE UNITS

5.1.         Grant of Performance Units.

Subject to the terms and provisions of the Plan, Performance Units may be granted to Participants at any time and from time to time as shall be determined by the Committee or any delegate who shall have complete discretion in determining the number of Performance Units granted to each Key Employee.

5.2.         Value of Performance Units .

The Committee shall set performance goals over certain periods to be determined in advance by the Committee (“Performance Periods”).  The initial value for each Performance Unit shall be one dollar.  With regard to each grant of Performance Units, the Committee in consultation with the Senior Vice President Controlling of the Parent shall set the performance goals that will be used to determine the extent to which the Participant receives a payment of the value of the Performance Units awarded for such Performance Period.  These goals will be based on the attainment, by the Parent, Company, or its Subsidiaries, of certain objective performance measures.  With respect to each such performance measure utilized during a Performance Period, the Committee shall assign percentages to various levels of performance which shall be applied to determine the extent to which the Participant shall receive a payout of the value of Performance Units.

5.3.         Payment of Performance Units.

After a Performance Period has ended, the holder of a Performance Unit shall be entitled to receive the value thereof as determined by the Committee.  The Committee shall make this determination by first determining the extent to which the performance goals set pursuant to Section 5.2 have been met.  It will then determine the applicable percentage (which may be greater or lesser than 100%) to be applied to, and will apply such percentage to, the value of Performance Units to determine the payout to be received by the Participant.  In addition, with respect to Performance Units granted to any Key Employee, no payout shall be made hereunder except upon written certification by the Committee that the applicable performance goal or goals have been satisfied to a particular extent.

5.4.         Discretion to Adjust Awards.

The Committee shall have the authority to modify, amend, or adjust the terms and conditions of any Performance Unit award, at any time or from time to time, including but not limited to the performance goals.

5.5.         Form and Timing of Payment.

The payment described in Section 5.3 herein shall be made in a cash lump sum as soon as administratively practical upon the determination by the Committee provided for in Section 5.3, unless the Participant has previously elected to defer such payment in a manner prescribed by the Committee.  If any payment is permitted by the Committee to be made on a deferred basis, the Committee may provide for earnings to be credited on such amount in a manner they determine.

5.6.         Termination of Employment Due to Death, Disability, or Retirement.

In the case of death, disability, or retirement (each of disability and retirement as defined under the established rules of the Company or any of its Subsidiaries, as the case may be), the holder of a Performance Unit shall receive a prorated payment based on the Participant’s number of full months of service during the Performance Period, further adjusted based on the achievement of the performance goals during the entire Performance Period, as computed by the Committee.  Payment shall be made at the time payments are made to Participants who did not terminate service during the Performance Period.

5.7.         Termination of Employment for Other Reasons.

In the event that a Participant terminates employment with the Company or any of its Subsidiaries for any reason other than death, disability, or retirement, prior to the end of the Performance Period all Performance Units shall be forfeited; provided however, in the case of any termination not for Cause, the Committee in its sole discretion may waive the automatic forfeiture provisions and make a prorated payment to the holder of a Performance Unit.  Payment made pursuant to this Section shall be made at the time payments are made to Participants who did not terminate service during the Performance Period.  In the event of a Participant’s termination of employment pursuant to this Section after completion of the respective Performance Period of a Performance Unit, but prior to payment pursuant to Section 5.5, the Participant shall be entitled to payment without proration.

5.8.         Nontransferability.

No Performance Units granted under the Plan may be sold, transferred, pledged, assigned, or otherwise alienated or hypothecated, other than by will or by the laws of descent and distribution until the termination of the applicable performance period.  All rights with respect to Performance Units granted to a Participant under the Plan shall be exercisable during his lifetime only by such Participant.

ARTICLE 6.  BENEFICIARY DESIGNATION

Each Participant under the Plan may, from time to time, name any beneficiary or beneficiaries (who may be named contingently or successively and who may include a trustee under a will or living trust) to whom any benefit under the Plan is to be paid in case of his death before he receives any or all of such benefit.  Each designation will revoke all prior designations by the same Participant, shall be in a form prescribed by the Committee, and will be effective only when filed by the Participant in writing with the Committee during his lifetime.  In the absence of any such designation or if all designated beneficiaries predecease the Participant, benefits remaining unpaid at the Participant’s death shall be paid to the Participant’s estate.

ARTICLE 7.  RIGHTS OF EMPLOYEES

7.1.         Employment.

Nothing in the Plan shall interfere with or limit in any way the right of the Company or any of its Subsidiaries to terminate any Participant’s employment at any time, nor confer upon any Participant any right to continue in the employ of the Company or any of its Subsidiaries.

7.2.         Participation.

No employee shall have a right to be selected as a Participant, or, having been so selected, to be selected again as a Participant.

7.3.         No Implied Rights; Rights on Termination of Service.

Neither the establishment of the Plan nor any amendment thereof shall be construed as giving any Participant, beneficiary, or any other person any legal or equitable right unless such right shall be specifically provided for in the Plan or conferred by specific action of the Committee in accordance with the terms and provisions of the Plan.  Except as expressly provided in this Plan, neither the Company nor any of its Subsidiaries shall be required or be liable to make any payment under the Plan.

7.4.         No Right to Company Assets.

Neither the Participant nor any other person shall acquire, by reason of the Plan, any right in or title to any assets, funds or property of the Parent, Company or any of its Subsidiaries whatsoever including, without limiting the generality of the foregoing, any specific funds, assets, or other property which the Parent, Company or any of its Subsidiaries, in its sole discretion, may set aside in anticipation of a liability hereunder.  Any benefits which become payable hereunder shall be paid from the general assets of the Parent, Company or the applicable subsidiary.  The Participant shall have only a contractual right to the amounts, if any, payable hereunder unsecured by any asset of the Company or any of its Subsidiaries.  Nothing contained in the Plan constitutes a guarantee by the Company or any of its Subsidiaries that the assets of the Company or the applicable subsidiary shall be sufficient to pay any benefit to any person.

ARTICLE 8.  CHANGE IN CONTROL

Notwithstanding any other provisions of the Plan, in the event of a Change in Control, all Performance Unit awards granted under this Plan shall be immediately paid out in cash.  The amount of the payout shall be based on the higher of:

(i)the extent, as determined by the Committee, to which performance goals, established for the Performance Period then in progress have been met up through and including the effective date of the Change in Control or

(ii)100% of the value on the date of grant of the Performance Units.

ARTICLE 9.  AMENDMENT, MODIFICATION, AND TERMINATION

9.1.         Amendment, Modification, and Termination.

At any time and from time to time, the Board, upon recommendation by the Committee, may terminate, amend, or modify the Plan.

9.2.         Awards Previously Granted.

No termination, amendment, or modification of the Plan shall in any manner adversely affect any Award theretofore granted under the Plan, without the written consent of the Participant.

ARTICLE 10.  TAX WITHHOLDING

The Company and any of its Subsidiaries shall have the power and the right to deduct or withhold, or require a Participant to remit to the Company or any of its Subsidiaries, an amount sufficient to satisfy taxes (including the Participant’s FICA obligation) required by law to be withheld with respect to any grant, exercise, or payment made under or as a result of this Plan.

ARTICLE 11.  PARENT AND SUCCESSORS

All obligations of the Company under the Plan, with respect to Awards granted hereunder, shall be binding on the Parent and any successor to the Company, whether the existence of such successor is the result of a direct or indirect purchase, merger, consolidation or otherwise, of all or substantially all of the business and/or assets of the Company.

ARTICLE 12.  REQUIREMENTS AND GOVERNING LAW

12.1.       Requirements of Law.

The granting of Awards under this Plan shall be subject to all applicable laws, rules, and regulations, and to such approvals by any governmental agencies or national securities exchanges as may be required.

12.2.       Governing Law.

The Plan, and all agreements hereunder, shall be construed in accordance with and governed by the laws of the Commonwealth of Kentucky.

EX-10.69

EXHIBIT 10.69

Ohio Valley Electric Corporation	Original Sheet No. 188
Indiana-Kentucky Electric Corporation
15f Revised Rate Schedule FERC No. 4

MODIFICATION NO. 12

TO

INTER-COMPANY POWER AGREEMENT

DATED JULY 10, 1953

AMONG

OHIO VALLEY ELECTRIC CORPORATION,

APPALACHIAN POWER COMPANY (formerly

APPALACHIAN ELECTRIC POWER COMPANY),

THE CINCINNATI GAS & ELECTRIC COMPANY,

COLUMBUS SOUTHERN POWER COMPANY (formerly

COLUMBUS AND SOUTHERN OHIO ELECTRIC COMPANY),

THE DAYTON POWER AND LIGHT COMPANY, INDIANA MICHIGAN

POWER COMPANY (formerly

INDIANA & MICHIGAN ELECTRIC COMPANY),

KENTUCKY UTILITIES COMPANY,

LOUISVILLE GAS AND ELECTRIC COMPANY

MONONGAHELA POWER COMPANY, OHIO

EDISON COMPANY,

OHIO POWER COMPANY (formerly THE OHIO

POWER COMPANY),

PENNSYLVANIA POWER COMPANY,

THE POTOMAC EDISON COMPANY,

SOUTHERN INDIANA GAS AND ELECTRIC COMPANY,

THE TOLEDO EDISON COMPANY, and WEST PENN POWER

COMPANY.

Dated as of November 1, 1999

Issued by: Dave Hart		Effective: June 1, 2001
	Vice President and Assistant to the President
Issued on: June 15, 2001

Original Sheet No. 189

MODIFICATION NO. 12

TO

INTER-COMPANY POWER AGREEMENT

THIS AGREEMENT dated as of the 1 st day of November, 1999, by and among OHIO VALLEY ELECTRIC CORPORATION (herein called “OVEC” or “Corporation”), APPALACHIAN POWER COMPANY, THE CINCINNATI GAS & ELECTRIC COMPANY, COLUMBUS SOUTHERN POWER, COMPANY (formerly COLUMBUS, AND SOUTHERN OHIO ELECTRIC COMPANY), THE DAYTON POWER AND LIGHT COMPANY, INDIANA MICHIGAN POWER COMPANY (formerly INDIANA & MICHIGAN ELECTRIC COMPANY), KENTUCKY UTILITIES COMPANY, LOUISVILLE GAS AND ELECTRIC COMPANY, MONONGAHELA POWER COMPANY, OHIO EDISON COMPANY, OHIO POWER COMPANY, PENNSYLVANIA POWER COMPANY, THE POTOMAC EDISON COMPANY, SOUTHERN INDIANA GAS AND ELECTRIC COMPANY, THE TOLEDO EDISON COMPANY, and WEST PENN POWER COMPANY, all of the foregoing, other than OVEC, being herein sometimes collectively referred to as the Sponsoring Companies and individually as a Sponsoring Company.

Original Sheet No. 190

W I T N E S SETH THAT

WHEREAS, Corporation and the United States of America have heretofore entered into Contract No. AT-(40-1)-1530 (redesignated Contract No. E-(40-1)-1530, later redesignated Contract No. EY-76-C-05-1530 and later redesignated Contract No. DE-AC05760RO1530), dated October 15, 1952, providing for the supply by Corporation of electric utility services to the United States Atomic Energy Commission (hereinafter called “AEC”) at AEC’s project near Portsmouth, Ohio (hereinafter called the “Project”), which Contract has heretofore been modified by Modification No. 1, dated July 23, 1953, Modification No. 2, dated as of March 15, 1964, Modification No. 3, dated as of May 12, 1966, Modification No. 4, dated as of January 7, 1967, Modification No. 5, dated as of August 15, 1967, Modification No. 6, dated as of November 15, 1967, Modification No. 7, dated as of November 5, 1975, Modification No. 8, dated as of June 23, 1977, Modification No. 9, dated as of July 1, 1978, Modification No. 10, dated as of August 1, 1979, Modification No. 11, dated as of September 1, 1979, Modification No. 12, dated as of August 1, 1981, Modification No. 13, dated as of September 1, 1989, Modification No. 14, dated as of January 15, 1992, Modification No. 15, dated as of February 1, 1993, and Modification No. 16, dated as of January 1, 1998 (said Contract, as so modified, is hereinafter called the “DOE Power Agreement”); and

WHEREAS, pursuant to the Energy Reorganization Act of 1974, the AEC was abolished on January 19, 1975 and certain of its functions, including the procurement of electric utility services for the Project, were transferred to and vested in the Administrator of Energy Research and Development; and

2

Original Sheet No. 191

WHEREAS, pursuant to the Department of Energy Organization Act, on October 1, 1977, all of the functions vested by law in the Administrator of Energy Research and Development or the Energy Research and Development Administration were transferred to, and vested in, the Secretary of Energy, the statutory head of the Department of Energy (hereinafter called “DOE”); and

WHEREAS, the parties hereto have entered into a contract, herein called the “Inter-Company Power Agreement,” dated July 10, 1953, governing, among other things, (a) the supply by the Sponsoring Companies of Supplemental Power in order to enable Corporation to fulfill its obligations under the DOE Power Agreement, and (b) the rights of the Sponsoring Companies to receive Surplus Power as may be available at the Project Generating Stations and the obligations of the Sponsoring Companies to pay therefor; and

WHEREAS, the Inter-Company Power Agreement has heretofore been amended by Modification No. 1, dated as of June 3, 1966, Modification No. 2 dated as of January 7, 1967, Modification No. 3, dated as of November 15, 1967, Modification No. 4, dated as of November 5, 1975, Modification No. 5, dated as of September 1, 1979, Modification No. 6, dated as of August 1, 1981, Modification No. 7, dated as of January 15, 1992, Modification No. 8, dated as of January 19, 1994, Modification No. 9, dated as of August 17, 1995, Modification No. 10, dated as of January 1, 1998, and Modification No. 11, dated as of April 1, 1999 (said contract so amended and as modified and amended by this Modification No. 12 being herein and therein sometimes called the “Agreement”); and

3

Original Sheet No. 192

WHEREAS, it is the goal of OVEC to assist its Sponsoring Companies during the winter of 1999-2000 by making available to them additional electricity; and

WHEREAS, reductions of the electricity to be delivered to DOE would make additional electricity available for the Sponsoring Companies; and

WHEREAS, the reduced purchases of electricity by DOE would reflect more closely the power needs of its Ohio uranium enrichment facility; and

WHEREAS, it is desired that DOE’s releases of portions of its entitlement to OVEC energy result in credits to DOE’s electricity bills; and

WHEREAS, it is desired that the Sponsoring Companies which receive additional electricity as a result of DOE’s energy releases reimburse OVEC for the credits to DOE’s power bills; and

WHEREAS, OVEC and the Sponsoring Companies desire to enter into this Modification No. 12 to the Inter-Company Power Agreement as more particularly hereinafter provided;

NOW, THEREFORE, the parties hereto agree with each other as follows:

1.             Delete subsections 1.0124, 1.0125 and 1.0126 of the Inter-Company Power Agreement and substitute therefor the following:

1.0124 “DOE Energy Release Period” means any calendar month from November 1, 1999 through May 31, 2000.

1.0125 “DOE Energy Release” means one or more reductions of the energy available to be scheduled by DOE pursuant to this Section 1.0125, for any calendar month during the DOE Energy Release Period.

1.0126 “Effective Date” means the date on which Corporation notifies DOE and the Sponsoring Companies that all conditions to

4

Original Sheet No. 193

effectiveness, including all required waiting periods and all required regulatory acceptances or approvals, of the arrangements for DOE Energy Releases and reimbursement of Corporation for costs associated with such releases, have been satisfied. Such date shall be not later than two business days after all conditions to effectiveness have been satisfied.

2.           Delete subsection 6.01 of the Inter-Company Power Agreement and substitute therefor the following:

Charges For Surplus Power, ECAR Emergency Energy and DOE Energy Releases

6.01 Total Monthly Charge. The amount to be paid Corporation each month by the Sponsoring Companies for Surplus Power, Surplus Energy and DOE Released Energy supplied under this Agreement shall consist of the sum of a demand charge, if applicable, an energy charge, and, if applicable, an emergency power surcharge and/or a DOE Energy Release Surcharge, all determined as set forth in this Article 6; provided, however, that Section 6.024 notwithstanding, each Sponsoring Company shall be relieved of responsibility for Corporation’s fuel cost allocable for each month to energy for which such Sponsoring Company pays to Corporation a DOE Energy Release Surcharge. The amount to be paid to Corporation for ECAR Emergency Energy supply under this Agreement shall be 98.74 mills per kilowatt hour (plus transmission charges calculated in accordance with applicable law).

3.             Delete subsection 6.038 and substitute therefor the following:

6.038 The aggregate charge otherwise payable by each Sponsoring Company for such Surplus Energy each month shall be adjusted to reflect a surcharge equal to its agreed share of the DOE Energy Release Credits for each month under the letter supplement to the DOE Power Agreement dated as of November 1, 1999.

4.             This Modification No. 12 shall become effective at 12:00 o’clock Midnight on the Effective Date.

5

Original Sheet No. 194

5. The Inter-Company Power Agreement, as modified by Modifications Nos. 1, 2, 3, 4, 5, 6, 7, 8, 9, 10 and 11 and as hereinbefore provided, is hereby in all respects confirmed.

6. This Modification No. 12 may be executed in any number of copies and by the different parties hereto on separate counterparts, each of which shall be deemed an original but all of which together shall constitute a single agreement.

IN WITNESS WHEREOF, the parties hereto have executed this Modification No. 12 as of the day and year first written above.

OHIO VALLEY ELECTRIC CORPORATION
By:	Is/ David L. Hart
APPALACHIAN POWER COMPANY
By:	/s/ Henry Fayne
THE CINCINNATI GAS & ELECTRIC COMPANY
By:	/s/ John C. Procario
COLUMBUS SOUTHERN POWER COMPANY
By:	/s/ Henry Fayne
THE DAYTON POWER AND LIGHT COMPANY
By:	/s/ Patrick W. O’Loughlin

6

Original Sheet No. 195

INDIANA MICHIGAN POWER COMPANY By:
/s/ Henry Fayne
KENTUCKY UTILITIES COMPANY
By:	/s/ Wayne T. Lucas
LOUISVILLE GAS AND ELECTRIC COMPANY
By:	s/ C. Hermann
MONONGAHELA POWER COMPANY
By:	/s/ Peter J. Skrgic
OHIO EDISON COMPANY
By:	s/ H. P. Burg

7

Original Sheet No. 196

OHIO POWER COMPANY
By:	/s/ Henry Fayne
PENNSYLVANIA POWER COMPANY
By:	s/ Arthur R. Garf eld	THE POTOMAC EDISON COMPANY
By:	s/ Peter J. Skrgic
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
By:	s/ J. G. Hurst
THE TOLEDO EDISON COMPANY
By:	s/ Guy L. Pipitone		WEST PENN POWER COMPANY
By:	s/ Peter J. Skrgic

8

EX-10.70

EXHIBIT 10.70

Ohio Valley Electric Corporation	Original Sheet No. 197
Indiana-Kentucky Electric Corporation
151 Revised Rate Schedule FERC No. 4

MODIFICATION NO. 13

TO

INTER-COMPANY POWER AGREEMENT

DATED JULY 10, 1953

AMONG

OHIO VALLEY ELECTRIC CORPORATION,

ALLEGHENY ENERGY SUPPLY COMPANY, L.L.C.

(successor to West Penn Power Company)

APPALCAHIAN POWER COMPANY (formerly

APPALACHIAN ELECTRIC POWER COMPANY),

THE CINCINNATI GAS & ELECTRIC COMPANY,

COLUMBUS SOUTHERN POWER COMPANY (formerly

COLUMBUS AND SOUTHERN OHIO ELECTRIC

COMPANY),

THE DAYTON POWER AND LIGHT COMPANY,

INDIANA MICHIGAN POWER COMPANY (formerly

INDIANA & MICHIGAN ELECTRIC COMPANY),

KENTUCKY UTILITIES COMPANY, LOUISVILLE GAS

AND ELECTRIC COMPANY MONONGAHELA POWER

COMPANY, OHIO EDISON COMPANY,

OHIO POWER COMPANY (formerly THE OHIO

POWER COMPANY),

PENNSYLVANIA POWER COMPANY,

THE POTOMAC EDISON COMPANY,

SOUTHERN INDIANA GAS AND ELECTRIC COMPANY, and

THE TOLEDO EDISON COMPANY.

Dated as of May 24, 2000

Issued by: Dave Hart		Effective: June 1, 2001
	Vice President and Assistant to the President
Issued on: June 15, 2001

Original Sheet No. 198

MODIFICATION NO. 13

TO

INTER-COMPANY POWER AGREEMENT

THIS AGREEMENT dated as of the 24^th day of May, 2000, by and among OHIO VALLEY ELECTRIC CORPORATION (herein called “OVEC” or “Corporation”), ALLEGHENY ENERGY SUPPLY COMPANY, L.L.C. (successor to WEST PENN POWER COMPANY), APPALACHIAN POWER COMPANY, THE CINCINNATI GAS & ELECTRIC COMPANY, COLUMBUS SOUTHERN POWER COMPANY (formerly COLUMBUS AND SOUTHERN OHIO ELECTRIC COMPANY), THE DAYTON POWER AND LIGHT COMPANY, INDIANA MICHIGAN POWER COMPANY (formerly INDIANA & MICHIGAN ELECTRIC COMPANY), KENTUCKY UTILITIES COMPANY, LOUISVILLE GAS AND ELECTRIC COMPANY, MONONGAHELA POWER COMPANY, OHIO EDISON COMPANY, OHIO POWER COMPANY, PENNSYLVANIA POWER COMPANY, THE POTOMAC EDISON COMPANY, SOUTHERN INDIANA GAS AND ELECTRIC COMPANY and THE TOLEDO EDISON COMPANY, all of the foregoing, other than OVEC, being herein sometimes collectively referred to as the Sponsoring Companies and individually as

a Sponsoring Company.

Original Sheet No. 199

WITNESSETH THAT

WHEREAS, Corporation and the United States of America have heretofore entered into Contract No. AT-(40-1)-1530 (redesignated Contract No. E-(40-1)-1530 later redesignated Contract No. EY-76-C-05-1530 and later redesignated Contract No. DE-AC05-76OR01530), dated October 15, 1952, providing for the supply by Corporation of electric utility services to the United States Atomic Energy Commission (hereinafter called “AEC”) at AEC’s project near Portsmouth, Ohio (hereinafter called the “Project”), which Contract has heretofore been modified by Modification No. 1, dated July 23, 1953, Modification No. 2, dated as of March 15, 1964, Modification No. 3, dated as of May 12, 1966, Modification No. 4, dated as of January 7, 1967, Modification No. 5, dated as of August 15, 1967, Modification No. 6, dated as of November 15, 1967, Modification No. 7, dated as of November 5, 1975, Modification No. 8, dated as of June 23, 1977, Modification No. 9, dated as of July 1, 1978, Modification No. 10, dated as of August 1, 1979, Modification No. 11, dated as of September 1, 1979, Modification No. 12, dated as of August 1, 1981, Modification No. 13, dated as of September 1, 1989, Modification No. 14, dated as of January 15, 1992, Modification No. 15, dated as of February 1, 1993, and Modification No. 16, dated as of January 1, 1998 (said Contract, as so modified, is hereinafter called the “DOE Power Agreement”); and

WHEREAS, pursuant to the Energy Reorganization Act of 1974, the AEC was abolished on January 19, 1975 and certain of its functions, including the procurement of electric utility services for the Project, were transferred to and vested in the Administrator of Energy Research and Development; and

2

Original Sheet No. 200

WHEREAS, pursuant to the Department of Energy Organization Act, on October 1, 1977, all of the functions vested by law in the Administrator of Energy Research and Development or the Energy Research and Development Administration were transferred to, and vested in, the Secretary of Energy, the statutory head of the Department of Energy (hereinafter called “DOE”); and

WHEREAS, the parties hereto have entered into a contract, herein called the “InterCompany Power Agreement,” dated July 10, 1953, governing, among other things, (a) the supply by the Sponsoring Companies of Supplemental Power in order to enable Corporation to fulfill its obligations under the DOE Power Agreement, and (b) the rights of the Sponsoring Companies to receive Surplus Power (as defined in the Agreement identified in the next clause in this preamble) as may be available at the Project Generating Stations and the obligations of the Sponsoring Companies to pay therefor; and

WHEREAS, the Inter-Company Power Agreement has heretofore been amended by Modification No. 1, dated as of June 3, 1966, Modification No. 2 dated as of January 7, 1967, Modification No. 3, dated as of November 15, 1967, Modification No. 4, dated as of November 5, 1975, Modification No. 5, dated as of September 1, 1979, Modification No. 6, dated as of August 1, 1981, Modification No. 7, dated as of January 15, 1992, Modification No. 8, dated as of January 19, 1994, Modification No. 9, dated as of August 17, 1995, Modification No. 10, dated as of January 1, 1998, Modification No. 11, dated as of April 1, 1999, and Modification No. 12, dated as of November 1, 1999 (said contract so amended and as

3

Original Sheet No. 201

modified and amended by this Modification No. 13 being herein and therein sometimes called the “Agreement”); and

WHEREAS, it is the goal of OVEC to assist its Sponsoring Companies during the summer of 2000 by making available to them additional power and energy; and

WHEREAS, additional power would be made available as a result of reductions by DOE of its contractual entitlement to power from OVEC; and

WHEREAS, it is desired that DOE release a portion of its contractual entitlement to OVEC power and energy in exchange for payments based on the value of such power and energy; and

WHEREAS, OVEC and the Sponsoring Companies desire to enter into this Modification No. 13 as more particularly hereinafter provided;

NOW, THEREFORE, the parties hereto agree with each other as follows:

1.Delete subsections 1.0124, 1.0125 and 1.0126 of the Inter-Company Power Agreement and substitute therefore the following:

1.0124 “DOE Additional Power Release Period” means the calendar months from June 1 through September 30, 2000.

1.0125 “DOE Additional Power Release” means a reduction of the otherwise applicable DOE contract demand pursuant to this Section 1.0125, for any calendar month during a DOE additional Power Release Period.

1.0126 “Effective Date” means the date on which Corporation notifies DOE and the Sponsoring Companies that all conditions to effectiveness, including all required waiting periods and all required regulatory acceptances or approvals, of the arrangements for a DOE Additional Power Release and

4

Original Sheet No. 202

reimbursement of Corporation for costs associated with such release, have been satisfied.

2.Delete subsection 5.05 of the Inter-Company Power Agreement and

substitute therefore the following:

5.05 Surplus Energy. Corporation shall make available to each Sponsoring Company Surplus Energy in proportion to said Sponsoring Company’s Surplus Power Reservation, provided that when (a) the DOE’s contractual entitlement to power from OVEC has been reduced and (b) one or more of the Sponsoring Companies have agreed to assume responsibility for the charges associated with such reduction in exchange for the right to receive Surplus Power made available thereby, the Sponsoring Companies which have assumed responsibility for the charges associated with such reduction shall have first priority to Surplus Energy up to the amounts of their respective entitlements to Surplus Power made available by their assumptions of responsibility for such charges. Any remaining Surplus Energy shall be made available (through successive allotments if necessary) to all Sponsoring Companies in proportion to their respective Power Participation Ratios. No Sponsoring Company, however, shall be obligated to avail itself of any Surplus Energy. Each Sponsoring Company availing itself of Surplus Energy shall be entitled to an amount of energy (herein called billing kilowatt-hours of Surplus Energy) equal to its portion, determined as provided above, of the total Surplus Energy after deducting therefrom such Sponsoring Company’s proportionate share, as defined below in this Section 5.05, of all losses which would be incurred in transmitting the total of such Surplus Energy from the 345-kv busses of the Project Generating Stations to the systems of all Sponsoring Companies availing themselves of Surplus Energy. The proportionate share of all such losses that shall be so deducted from such Sponsoring Company’s portion of Surplus Energy shall be equal to all such losses multiplied by the ratio of such portion of Surplus Energy to the total of such Surplus Energy. Each Sponsoring Company shall have the right, pursuant to this Section 5.05, to avail itself of Surplus Energy for the purpose of meeting the loads of its own system and/or of supplying energy to other systems in accordance with agreements, other than this Agreement, to which such Sponsoring Company is a party.

5

Original Sheet No. 203

3.Delete subsection 6.01 and substitute therefor the following:

CHARGES FOR SURPLUS POWER, ECAR EMERGENCY ENERGY AND DOE ADDITIONAL POWER RELEASES

6.01 Total Monthly Charge. The amount to be paid Corporation each month by the Sponsoring Companies for Surplus Power and Surplus Energy supplied under this Agreement shall consist of the sum of an energy charge, a demand charge and, if applicable, an emergency power surplus and/or a DOE Additional Power Release Surcharge, all determined as set forth in this Article 6. The amount to be paid to Corporation for ECAR Emergency Energy supply under this Agreement shall be 98.74 mills per kilowatt hour (plus transmission charges calculated in accordance with applicable law).

4.Delete subsection 6.024 and substitute therefor the following:

6.024 Determine for such month the difference between the total cost of fuel as described in subsection 6.021 above and the sum of (a) the total energy charge to be billed DOE as described in subsection 6.022 above, (b) the energy charge to be billed as DOE Emergency Energy as described in subsection 6.023 above and (c) the total cost of fuel used to generate ECAR Emergency Energy. For the purposes hereof the difference so determined shall be the fuel cost allocable for such month to the total kilowatt-hours of energy generated at the Project Generating Stations for the supply of Surplus Energy. For Surplus Energy made available to the Sponsoring Companies by the reduction in DOE Contract Demand from 1899 MW to 1299 MW during June through September 2000 (the “Released Demand”) and by DOE Additional Power Releases, each Sponsoring Company shall pay Corporation for each such month an amount obtained by multiplying the ratio of the billing kilowatt-hours of Surplus Energy availed of by such Sponsoring Company during such month to the aggregate of the billing kilowatt-hours of all Surplus Energy availed of by all Sponsoring Companies during such month times the difference determined hereinabove. For all other Surplus Energy, each Sponsoring Company shall pay Corporation an amount equal to (i) an amount obtained by multiplying the billing kilowatt-hours of Surplus Energy (other than Surplus Energy associated with the Released Demand or with a DOE Additional Power Release) availed of by such Sponsoring Company during

6

Original Sheet No. 204

such month by the average station heat rate of the Project Generating Stations times the average cost per Btu (determined in a uniform manner for all Sponsoring Companies in conformity with any applicable requirements of Account 703 (Fuel) by said Uniform System of Accounts) of all fuel consumed by said Sponsoring Company in its own generating stations, both averages to be computed in respect of the month next preceding that for which payment is being made, plus (ii) its Power Participation Ratio of the excess, if any, for such month of the fuel costs of the Corporation allocable to the total kilowatt-hours of energy generated at the Project Generating Stations for the supply of Surplus Energy (other than Surplus Energy associated with the Released Demand or with a DOE Additional Power Release) over the aggregate of the amounts computed with respect to all Sponsoring Companies under (i) above, minus (iii) its Power Participation Ratio of the excess, if any, for such month of the aggregate of the amounts computed with respect to all Sponsoring Companies under (i) above over the fuel costs of the Corporation allocable to the total kilowatt-hours of energy generated at the Project Generating Stations for the supply of Surplus Energy (other than Surplus Energy associated with the Released Demand or with a DOE Additional Power Release).

5.Delete subsection 6.038 and substitute therefor the following:

6.038 DOE will be responsible for capacity costs related to the Released Demand when and to the extent that energy associated with the Released Demand is not received by the Sponsoring Companies because of a curtailment or outage of Corporation’s generating plants or transmission facilities (an OVEC Outage). Any transmission loading relief (TLR) which is not caused by an OVEC Outage will not be considered an OVEC Outage.

6.Insert after subsection 6.038, a new subsection 6.039 as follows:

6.039 When, pursuant to the May 24, 2000 letter supplement (“Supplement”) to the DOE Power Agreement, DOE and Corporation agree to a DOE Additional Power Release and thereby to make additional Surplus Power and Surplus Energy available to the sponsoring Companies, the aggregate demand charge otherwise payable by each Sponsoring Company for Surplus Power shall be adjusted to reflect its agreed share of a

7

Original Sheet No. 205

DOE Additional Power Release Surcharge, such DOE Additional Power Release Surcharges to be equal to amounts per megawatt hour set forth below for the Insured Sponsoring Companies, as defined herein, and for the other Sponsoring Companies:

(a) For Insured Sponsoring Companies, the DOE Additional Power Release Surcharge shall be their agreed share of the amount of the DOE Additional Power Release under the Supplement times $50.76 per megawatt hour during the calendar month of June 2000, $118.60 per megawatt hour during the calendar months of July and August 2000 and $25.76 per megawatt hour during the calendar month of September 2000 times the number of onpeak hours (5 x 16) during each such month notwithstanding the fact that transmission loading relief or outages or curtailments of Corporation’s generation or transmission facilities may reduce deliveries of Surplus Energy which might otherwise be made available to the Sponsoring Companies by the DOE Additional Power Release, minus (a) the demand charges which DOE avoids by reason of the monthly reduction in DOE contract demand required for the DOE Additional Power Release to make additional Surplus Power available to the Insured Sponsoring Companies and (b) charges for energy in amounts equal to such reductions in demand times the number of on-peak hours during such month times Corporation’s energy rate per MWH.

(b) For Sponsoring Companies other than the Insured Sponsoring Companies, the DOE Additional Power Release Surcharge shall be their agreed share of the DOE Additional Power Release under the Supplement times $38.58 per magawatt hour during the calendar month of June 2000, $118.60 per megawatt hour during the calendar months of July and August 2000 and $25.76 per megawatt hour during the calendar month of September 2000 times the number of on-peak hours (5 x 16) during each such month notwithstanding the fact that transmission loading relief or outages or

8

Original Sheet No. 206

curtailments of corporation’s generation or transmission facilities may reduce deliveries of Surplus Energy which might otherwise be made available to the sponsoring Companies by the DOE Additional Power Release, minus (a) the demand charges which DOE avoids by reason of the monthly reduction in DOE contract demand required for the DOE Additional Power Release to make additional Surplus Power available to Sponsoring Companies other than the Insured Sponsoring Companies and (b) charges for energy in amounts equal to such reductions in demand times the number of on-peak hours during such month times Corporation’s energy rate per MWH.

The Sponsoring Companies listed below (“Insured Sponsoring Companies”) will be the loss payees of a $18,800,000 insurance policy in form and substance satisfactory to the Insured Sponsoring Companies covering their obligations to Corporation for its payments to DOE for DOE Additional Power Releases, when Surplus Energy associated with such releases is not received by the Insured Sponsoring Companies because of curtailments or outages of Corporation’s generation or transmission facilities other than curtailments resulting from transmission loading relief (TLR). TLR caused by curtailments or outages of Corporation’s generation or transmission facilities shall not constitute TLR for purposes of the preceding sentence.

9

Original Sheet No. 207

Insured Sponsoring Companies

Kentucky Utilities Company Louisville

Gas and Electric Company Ohio Edison

Company Pennsylvania Power

Company The Toledo Edison Company

7.Insert after subsection 10.07 new subsection 10.08 as follows:

10.08 DOE Additional Power Release Surcharge.

Corporation shall render to each Sponsoring Company a statement indicating the DOE Additional Power Release Surcharge due Corporation from such Sponsoring Company pursuant to Article 6 above. The total of such charges to the Sponsoring Companies shall in the aggregate equal Corporation’s payment obligation to DOE for a DOE Additional Power Release. Such Sponsoring Company shall make payment therefore by the date set forth in such statement. In case the computation of the amount due cannot be determined at the time, it shall be estimated subject to adjustment when the actual determination can be made, and all payments shall be subject to subsequent adjustment.

8.This Modification No. 13 shall become effective at 12:00 o’clock Midnight on the Effective Date.

9. The Inter-Company Power Agreement, as modified by Modification Nos. 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11 and 12 and as hereinbefore provided, is hereby in all respects confirmed.

10. This Modification No. 13 may be executed in any number of copies and by the different parties hereto on separate counterparts, each of which shall be deemed an original but all of which together shall constitute a single agreement.

10

Original Sheet No. 208

IN WITNESS WHEREOF, the parties hereto have executed this Modification No. 13 as of the day and year first written above.

OHIO VALLEY ELECTRIC CORPORATION
By:	/s/ David L. Hart
ALLEGHENY ENERGY SUPPLY COMPANY, L.L.C.
By:	/s/ Peter J. Skrgic
APPALACHIAN POWER COMPANY
By:	/s/ Henry Fayne
THE CINCINNATI GAS & ELECTRIC COMPANY
By:	/s/ John C. Procario
COLUMBUS SOUTHERN POWER COMPANY
By:	/s/ Henry Fayne
THE DAYTON POWER AND LIGHT COMPANY
By:	/s/ H. Ted Santo
INDIANA MICHIGAN POWER COMPANY
By:	/s/ Henry Fayne

11

Original Sheet No. 209

KENTUCKY UTILITIES COMPANY
By:	/s/ Wayne T. Lucas
LOUISVILLE GAS AND ELECTRIC COMPANY
By:	/s/ Chris Hermann
MONONGAHELA POWER COMPANY
By:	/s/ Peter J. Skrgic
OHIO EDISON COMPANY
By:	/s/ H. Peter Burg
OHIO POWER COMPANY
By:	/s/ Henry Fayne
PENNSYLVANIA POWER COMPANY
By:	/s/ Arthur R. Garfield
THE POTOMAC EDISON COMPANY
By:	/s/ Peter J. Skrgic

12

Original Sheet No. 210

SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
By:	/s/ J. G. Hurst
THE TOLEDO EDISON COMPANY
By:	/s/ Guy L. Pipitone

13

EX-10.71

EXHIBIT 10.71

Ohio Valley Electric Corporation	Original Sheet No. 211
Indiana-Kentucky Electric Corporation
1” Revised Rate Schedule FERC No. 4

MODIFICATION NO. 14

TO

INTER-COMPANY POWER AGREEMENT

DATED JULY 10, 1953

AMONG

OHIO VALLEY ELECTRIC CORPORATION,

ALLEGHENY ENERGY SUPPLY COMPANY, L.L.C.

(successor to West Penn Power Company

and The Potomac Edison Company)

APPALACHIAN POWER COMPANY (formerly

APPALACHIAN ELECTRIC POWER COMPANY), THE

CINCINNATI GAS & ELECTRIC COMPANY, COLUMBUS

SOUTHERN POWER COMPANY (formerly

COLUMBUS AND SOUTHERN OHIO ELECTRIC COMPANY),

THE DAYTON POWER AND LIGHT COMPANY, INDIANA

MICHIGAN POWER COMPANY (formerly

INDIANA & MICHIGAN ELECTRIC COMPANY),

KENTUCKY UTILITIES COMPANY, LOUISVILLE

GAS AND ELECTRIC COMPANY MONONGAHELA

POWER COMPANY, OHIO EDISON COMPANY, OHIO

POWER COMPANY (formerly THE OHIO

POWER COMPANY),

PENNSYLVANIA POWER COMPANY,

SOUTHERN INDIANA GAS AND ELECTRIC COMPANY, and

THE TOLEDO EDISON COMPANY.

Dated as of April 1, 2001

Issued by: Dave Hart		Effective: June 1, 2001
	Vice President and Assistant to the President
Issued on: June 15, 2001

Original Sheet No. 212

MODIFICATION NO. 14

TO

INTER-COMPANY POWER AGREEMENT

THIS AGREEMENT dated as of the 1^st day of April, 2001, by and among OHIO VALLEY ELECTRIC CORPORATION (herein called “OVEC” or “Corporation”), ALLEGHENY ENERGY SUPPLY COMPANY, L.L.C. (successor to WEST PENN POWER COMPANY and THE POTOMAC EDISON COMPANY), APPALACHIAN POWER COMPANY, THE CINCINNATI GAS & ELECTRIC COMPANY, COLUMBUS SOUTHERN POWER COMPANY (formerly COLUMBUS AND SOUTHERN OHIO ELECTRIC COMPANY), THE DAYTON POWER AND LIGHT COMPANY, INDIANA MICHIGAN POWER COMPANY (formerly INDIANA & MICHIGAN ELECTRIC COMPANY), KENTUCKY UTILITIES COMPANY, LOUISVILLE GAS AND ELECTRIC COMPANY, MONONGAHELA POWER COMPANY, OHIO EDISON COMPANY, OHIO POWER COMPANY, PENNSYLVANIA POWER COMPANY, SOUTHERN INDIANA GAS AND ELECTRIC COMPANY and THE TOLEDO EDISON COMPANY, all of the foregoing, other than OVEC, being herein sometimes collectively referred to as the Sponsoring Companies and individually as a Sponsoring Company.

Original Sheet No. 213

WITNESSETH THAT

WHEREAS, Corporation and the United States of America have heretofore entered into Contract No. AT-(40-1)-1530 (redesignated Contract No. E-(40-1)-1530, later redesignated Contract No. EY-76-C-05-1530 and later redesignated Contract No. DE-AC05-76OR01530), dated October 15, 1952, providing for the supply by Corporation of electric utility services to the United States Atomic Energy Commission (hereinafter called “AEC”) at AEC’s project near Portsmouth, Ohio (hereinafter called the “Project”), which Contract has heretofore been modified by Modification No. 1, dated July 23, 1953, Modification No. 2, dated as of March 15, 1964, Modification No. 3, dated as of May 12, 1966, Modification No. 4, dated as of January 7, 1967, Modification No. 5, dated as of August 15, 1967, Modification No. 6, dated as of November 15, 1967, Modification No. 7, dated as of November 5, 1975, Modification No. 8, dated as of June 23, 1977, Modification No. 9, dated as of July 1, 1978, Modification No. 10, dated as of August 1, 1979, Modification No. 11, dated as of September 1, 1979, Modification No. 12, dated as of August 1, 1981, Modification No. 13, dated as of September 1, 1989, Modification No. 14, dated as of January 15, 1992, Modification No. 15, dated as of February 1, 1993, and Modification No. 16, dated as of January 1, 1998 (said Contract, as so modified, is hereinafter called the “DOE Power Agreement”); and

WHEREAS, pursuant to the Energy Reorganization Act of 1974, the AEC was abolished on January 19, 1975 and certain of its functions, including the procurement of electric utility services for the Project, were transferred to and vested in the Administrator of Energy Research and Development; and

2

Original Sheet No. 214

WHEREAS, pursuant to the Department of Energy Organization Act, on October 1, 1977, all of the functions vested by law in the Administrator of Energy Research and Development or the Energy Research and Development Administration were transferred to, and vested in, the Secretary of Energy, the statutory head of the Department of Energy (hereinafter called “DOE”); and

WHEREAS, the parties hereto have entered into a contract, herein called the “Inter-Company Power Agreement,” dated July 10, 1953, governing, among other things, (a) the supply by the Sponsoring Companies of Supplemental Power in order to enable Corporation to fulfill its obligations under the DOE Power Agreement, and (b) the rights of the Sponsoring Companies to receive Surplus Power as may be available at the Project Generating Stations and the obligations of the Sponsoring Companies to pay therefor; and

WHEREAS, the Inter-Company Power Agreement has heretofore been amended by Modification No. 1, dated as of June 3, 1966, Modification No. 2 dated as of January 7, 1967, Modification No. 3, dated as of November 15, 1967, Modification No. 4, dated as of November 5, 1975, Modification No. 5, dated as of September 1, 1979, Modification No. 6, dated as of August 1, 1981, Modification No. 7, dated as of January 15, 1992, Modification No. 8, dated as of January 19, 1994, Modification No. 9, dated as of August 17, 1995, Modification No. 10, dated as of January 1, 1998, Modification No. 11, dated as of April 1, 1999, Modification No. 12, dated as of November 1, 1999, and Modification No. 13, dated as of May 24, 2000 (said contract so amended and as modified and amended by this Modification No. 14 being herein and therein sometimes called the “Agreement”); and

3

Original Sheet No. 215

WHEREAS, it is the goal of OVEC to assist its Sponsoring Companies by making available to them additional power and energy; and

WHEREAS, additional power would be made available as a result of reductions by DOE of its contractual entitlement to power from OVEC; and

WHEREAS, it was agreed between DOE and Corporation that DOE would reduce its contractual entitlement to OVEC power and energy in exchange for Corporation’s agreement to relieve DOE of certain costs associated with additional facilities and replacements (“AFR”); and

WHEREAS, it was necessary to allocate to the Sponsoring Companies shares of the AFR costs which, as a result of Corporation’s agreement with DOE, will no longer be payable by DOE; and

WHEREAS, the Sponsoring Companies also wish to amend this Agreement to equalize the costs of surplus energy associated with the additional power being made available by DOE; and

WHEREAS, OVEC and the Sponsoring Companies desire to enter into this Modification No. 14 as more particularly hereinafter provided;

NOW, THEREFORE, the parties hereto agree with each other as follows: 1.            Delete subsection 1.0124 and substitute therefor the following:

1.0124 “DOE Settlement Capacity Surcharge Period” means the calendar months from June 1, 2001 through April 30, 2003.

2.              Delete subsection 1.0125 and substitute therefor the following:

1.0125 “DOE Settlement Energy Surcharge Period” means the calendar months from September 1, 2001 through April 30, 2003.

4

Original Sheet No. 216 5

3.            Delete subsection 1.0126 and substitute therefor the following:

1.0126 “Effective Date” means the date on which Corporation notifies the Sponsoring Companies that all conditions to effectiveness, including all required waiting periods and all required regulatory acceptances or approvals, of this Modification No. 14 have been satisfied.

4.            Delete subsection 6.01 and substitute therefor the following:

CHARGES FOR SURPLUS POWER AND ECAR EMERGENCY ENERGY, AND DOE SETTLEMENT SURCHARGES

6.01 Total Monthly Charge. The amount to be paid Corporation each month by the Sponsoring Companies for Surplus Power and Surplus Energy supplied under this Agreement shall consist of the sum of an energy charge, a demand charge and, if applicable, an emergency power surcharge, a DOE Settlement Capacity Surcharge and a DOE Settlement Energy Surcharge, all determined as set forth in this Article 6. The amount to be paid to Corporation for ECAR Emergency Energy supply under this Agreement shall be 98.74 mills per kilowatt hour (plus transmission charges calculated in accordance with applicable law).

5.             Delete subsection 6.024 and substitute therefor the following:

6.024 Determine for such month the difference between the total cost of fuel as described in subsection 6.021 above and the sum of (a) the total energy charge to be billed DOE as described in subsection 6.022 above, (b) the energy charge to be billed as DOE Emergency Energy as described in subsection 6.023 above and (c) the total cost of fuel used to generate ECAR Emergency Energy. For the purposes hereof the difference so determined shall be the fuel cost allocable for such month to the total kilowatt-hours of energy generated at the Project Generating Stations for the supply of Surplus Energy. For Surplus Energy made available to the Sponsoring Companies by the Letter Supplement between DOE and Corporation dated March 20, 2001 (the “Released Demand”), each Sponsoring Company shall pay Corporation for each such month an amount obtained by multiplying the ratio of the billing kilowatt-hours of such Surplus Energy availed of by such Sponsoring Company during such month to the aggregate of the billing kilowatt-hours of all Surplus Energy availed of by all Sponsoring Companies during such month times the difference determined hereinabove. For all other Surplus Energy, each Sponsoring Company shall pay Corporation an amount equal to (i) an amount obtained by multiplying the billing

5

Original Sheet No. 217

kilowatt-hours of Surplus Energy (other than Surplus Energy associated with the Released Demand) availed of by such Sponsoring Company during such month by the average station heat rate of the Project Generating Stations times the average cost per Btu (determined in a uniform manner for all Sponsoring Companies in conformity with any applicable requirements of Account 703 (Fuel) of the Uniform System of Accounts) of all fuel consumed by said Sponsoring Company in its own generating stations, both averages to be computed in respect of the month next preceding that for which payment is being made, plus (ii) its Power Participation Ratio of the excess, if any, for such month of the fuel costs of the Corporation allocable to the total kilowatt-hours of energy generated at the Project Generating Stations for the supply of Surplus Energy (other than Surplus Energy associated with the Released Demand) over the aggregate of the amounts computed with respect to all Sponsoring Companies under (i) above, minus (iii) its Power Participation Ratio of the excess, if any, for such month of the aggregate of the amounts computed with respect to all Sponsoring Companies under (i) above over the fuel costs of the Corporation allocable to the total kilowatt-hours of energy generated at the Project Generating Stations for the supply of Surplus Energy (other than Surplus Energy associated with the Released Demand).

6.            Add a new subsection 6.025 after subsection 6.024 as follows:

6.025 During the DOE Settlement Energy Surcharge Period, Kentucky Utilities Company and Louisville Gas and Electric Company shall, in addition to all other charges payable to Corporation under this Agreement, pay to Corporation for all on-peak hours a DOE Settlement Energy Surcharge in the amount of 1.37 mills per kilowatt hour. For purposes of this subsection, “on-peak hour” means any hour from the hour ending 0800 Eastern Prevailing Time through the hour ending 2300 Eastern Prevailing Time on any Monday, Tuesday, Wednesday, Thursday or Friday, excluding any holidays specified by the North American Electric Reliability Council or its successors.

7.             Delete subsection 6.03 and substitute therefor the following:

6.03 Demand Charge from June 1, 2001 through April 30, 2003. The demand charge to be paid each month from June 1, 2001 through April 30, 2003 by the Sponsoring Companies shall, subject to the provisions of Sections 6.08 and 6.12 below, be determined by Corporation as follows:

6

Original Sheet No. 218

8.           Delete subsection 6.033 and substitute therefor the following:

6.033 Determine the demand charge to be charged to DOE for such month, such demand charge to be an amount equal to the product of the aggregate of the costs determined in accordance with subsection 6.031 above and the average DOE capacity ratio in effect for such month, weighted with respect to the periods of time during which DOE capacity ratios were in effect; provided, however, that the demand charge to be charged to DOE for such month shall be reduced by amounts, if any, specified in paragraph 3 of Section 3.04 of the DOE Power Agreement with respect to fines and penalties, which amounts DOE shall not be obligated to pay to Corporation as a result of the second proviso contained in Section 7.05 of the DOE Power Agreement and other amounts, if any, specified in paragraph 3 of Section 3.04 of the DOE Power Agreement which DOE shall not be obligated to pay to Corporation as a result of adjustments mutually agreed upon by Corporation and DOE pursuant to said second proviso which reads as follows:

“provided, further, that DOE shall be relieved of its obligation to pay to Corporation amounts specified in paragraph 3 of Section 3.04 with respect to fines and penalties with respect to occasions where it is asserted that Corporation failed to comply with a law or regulation relating to the emission of pollutants or the discharge of wastes, if, and only if, prior to any such particular occasion, (i) DOE has requested Corporation to limit the generation at either or both Project Generating Stations so as not to exceed a stated number of megawatts for a stated period to comply with applicable laws or regulations relating to the emission of pollutants or the discharge of wastes, (ii) DOE has advised Corporation that it will, and does, during such period, limit its demand at the Project so that the number of megawatts to be supplied by Corporation at the point of delivery as permanent and supplemental power shall not exceed the amount determined by multiplying the DOE capacity ratio by the number of megawatts of permanent and supplemental power to which DOE would be entitled after giving effect to the limitation provided in clause (i) above, and (iii) Corporation shall willfully fail so to limit generation at either or both of the Project Generating Stations so as not to exceed the number of megawatts stated in such request (however, should Corporation willfully operate either or both of the Project Generating Stations so that the number of megawatts generated shall exceed (x) the number of megawatts which could have been generated had DOE not requested Corporation to limit its generation as provided in clause (i) above, minus (y) the number of megawatts which could have been generated had DOE not requested Corporation to limit its generation as provided in clause (i) above multiplied by the DOE capacity ratio, plus (z) the number of megawatts

7

Original Sheet No. 219

determined as provided in clause (ii) above plus transmission losses thereon, then the amount to be paid by DOE to Corporation on account of the costs specified in paragraph 3 of Section 3.04 other than (a) any interest, principal, and/or amortization component of any purchase price, amortization, rental, or other payment under an installment sale, loan, lease or similar agreement relating to the purchase, lease, or acquisition by Corporation of additional facilities under Section 3.06 and replacements under Section 3.07, (b) the cost of any insurance carried solely for the benefit of DOE at its request pursuant to paragraph 3(b) of Section 3.04 and (c) any taxes allocated directly to DOE pursuant to paragraph 3(c) of Section 3.04, shall be adjusted to the extent mutually agreed upon);...”

9.            Delete subsections 6.038 and 6.039 in their entirety.

10.          Delete the last paragraph of subsection 6.08 and substitute therefor the following:

In the event DOE delivers such further notice to Corporation as provided in said paragraph (b) of Section 6.02 of the DOE Power Agreement and payment of a modified demand charge by DOE to Corporation as provided in said paragraph (d) of Section 6.02 of the DOE Power Agreement becomes effective during any portion of the notice period as defined in said Section 6.02 of the DOE Power Agreement, during such portion of the notice period determination of the demand charges to be paid by the Sponsoring Companies to Corporation each month shall continue to be in accord with the provisions of Section 6.03 of this Agreement, modified only as such provisions may be affected by said paragraphs (b) and (d) and consistent with the principle that the aggregate of (i) the demand charges payable by DOE adjusted pursuant to paragraph 4 of Section 3.04 of the DOE Power Agreement and (ii) the demand charges payable by the Sponsoring Companies, each month to Corporation shall be equal to the total costs incurred for such month by Corporation resulting from its ownership, operation, and maintenance of the Project Generating Stations and Project Transmission Facilities determined in accordance with paragraph 3 of Section 3.04 of the DOE Power Agreement and quoted in subsection 6.031 above.

11.           After subsection 6.08, add a new subsection 6.081 as follows:

6.081 DOE Settlement Capacity Surcharge. During the DOE Settlement Capacity Surcharge Period, the following Sponsoring Companies shall, in addition to all other charges payable to Corporation under this Agreement, by the Sponsoring Companies, pay monthly to Corporation, DOE Settlement Capacity Surcharges in the amounts set forth below:

8

Original Sheet No. 220

Allegheny Energy Supply Company, L.L.C.	$	314,093.66
Appalachian Power Company	532,786.51
The Cincinnati Gas & Electric Company	314,093.65
Columbus Southern Power Company	151,500.27
The Dayton Power and Light Company	174,003.45
Indiana Michigan Power Company	263,699.21
Monongahela Power Company	123,292.06
Ohio Edison Company	510,600.28
Ohio Power Company	527,398.42
Pennsylvania Power Company	67,192.59
Southern Indiana Gas and Electric Company	50,394.44
The Toledo Edison Company	140,407.15

12.          Delete the first paragraph of subsection 6.12 and substitute therefor the following:

6.12 Demand Charge Beginning May 1, 2003. During the period commencing with May 1, 2003 and for the remainder of the term of this Agreement, subject to the provisions of Article 11 below, demand charges payable by the Sponsoring Companies to Corporation shall be determined as provided below in this Section 6.12.

13.Delete subsection 10.08 in its entirety.

14.           This Modification No. 14 shall become effective at 12:00 o’clock Midnight on the Effective Date.

15. The Inter-Company Power Agreement, as modified by Modifications Nos. 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12 and 13 and as hereinbefore provided, is hereby in all respects confirmed.

16. This Modification No. 14 may be executed in any number of copies and by the different parties hereto on separate counterparts, each of which shall be deemed an originai but all of which together shall constitute a single agreement.

9

Original Sheet No. 221

IN WITNESS WHEREOF, the parties hereto have executed this Modification No. 14 as of the day and year first written above.

OHIO VALLEY ELECTRIC CORPORATION
By:	s/ E. L. Draper, Jr.
ALLEGHENY ENERGY SUPPLY COMPANY, L.L.C.
By:	s / D. C. Benson
APPALACHIAN POWER COMPANY
By:	s/ E. L. Draper, Jr.
THE CINCINNATI GAS & ELECTRIC COMPANY
By:	s/ J. C. Procario
COLUMBUS SOUTHERN POWER COMPANY
By:	s/ E. L. Draper, Jr.
THE DAYTON POWER AND LIGHT COMPANY
By:	s/ H. T. Santo

10

Original Sheet No. 222

INDIANA MICHIGAN POWER COMPANY
By:	s/ E. L. Draper, Jr.
KENTUCKY UTILITIES COMPANY
By:	s/ P. W. Thompson
LOUISVILLE GAS AND ELECTRIC COMPANY
By:		s/ P. W. Thompson
MONONGAHELA POWER COMPANY
By:		s/ D. C. Benson
OHIO EDISON COMPANY
OHIO POWER COMPANY By:			s/ E. L.
Draper, Jr.
PENNSYLVANIA
By:		s/ A. R. Garfield

11

Original Sheet No. 223

SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
By:	s/ R. G. Jochum
THE TOLEDO EDISON COMPANY
By:	s/ G. L. Pipitone

12

EX-12

EXHIBIT 12

LOUISVILLE GAS AND ELECTRIC COMPANY AND SUBSIDIARY

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

(Thousands of $)

	2003			2002			2001			2000			1999
Earnings:
Net Income	$	90,839		$	88,929		$	106,781		$	110,573		$	106,270
Add:
Federal income taxes - current	25,768			24,564			41,127			30,425			54,198
State income taxes - current	10,003			7,653			8,185			4,450			13,650
Deferred Federal income taxes - net	16,793			20,258			12,595			24,233			(4,564		)
Deferred State income taxes - net	1,716			4,357			3,840			6,787			(715		)
Investment tax credit - net	(4,207		)	(4,153		)	(4,290		)	(4,274		)	(4,289		)
Fixed charges	31,378			30,551			38,755			46,438			40,026
Earnings	172,290			172,159			206,993			218,632			204,576
Fixed Charges:
Interest Charges per statements of income	30,647			29,805			37,922			43,218			37,962
Add:
One-third of rentals charged to operating expense (1)	731			746			833			3,220			2,064
Fixed charges	$	31,378		$	30,551		$	38,755		$	46,438		$	40,026
Ratio of Earnings to Fixed Charges	5.49			5.64			5.34			4.71			5.11

NOTE:

(1)In the Company’s opinion, one-third of rentals represents a reasonable approximation of the interest factor.

KENTUCKY UTILITIES COMPANY AND SUBSIDIARY
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
(Thousands of $)

	2003			2002			2001			2000			1999
Earnings:
Net Income	$	91,402		$	93,384		$	96,278		$	95,524		$	106,558
Add:
Federal income taxes - current	29,118			37,839			57,389			45,276			51,997
State income taxes - current	11,322			10,509			13,197			9,400			13,513
Deferred Federal income taxes - net	11,378			3,272			(12,117		)	(3,376		)	(4,651		)
Deferred State income taxes - net	904			1,459			(1,118		)	927			887
Investment tax credit - net	(2,641		)	(2,955		)	(3,446		)	(3,674		)	(3,727		)
Undistributed income of Electric Energy, Inc.	(3,644		)	(5,382		)	258			70			33
Fixed charges	25,980			26,756			35,215			40,834			40,101
Earnings	163,819			164,882			185,656			184,981			204,711
Fixed Charges:
Interest Charges per statements of income	25,249			25,727			34,043			39,484			38,904
Add:
One-third of rentals charged to operating expense (1)	731			1,029			1,172			1,350			1,197
Fixed charges	$	25,980		$	26,756		$	35,215		$	40,834		$	40,101
Ratio of Earnings to Fixed Charges	6.31			6.16			5.27			4.53			5.10

NOTE:

(1)In the Company’s opinion, one-third of rentals represents a reasonable approximation of the interest factor.

EX-21

Exhibit 21

SUBSIDIARIES OF THE REGISTRANTS

Louisville Gas and Electric Company, a Kentucky corporation, has one subsidiary, LG&E Receivables LLC, a Delaware limited liability company.

Kentucky Utilities Company, a Kentucky and Virginia corporation, has two subsidiaries, Lexington Utilities Company, a Kentucky corporation, and KU Receivables LLC, a Delaware limited liability company.

EX-24

EXHIBIT 24

POWER OF ATTORNEY

WHEREAS, LOUISVILLE GAS AND ELECTRIC COMPANY, a Kentucky corporation, is to file with the Securities and Exchange Commission, under the provisions of the Securities Exchange Act of 1934, as amended, its Annual Report on Form 10-K for the year ended December 31, 2003 (the 2003 Form 10-K); and

WHEREAS, each of the undersigned holds the office or offices in LOUISVILLE GAS AND ELECTRIC COMPANY set opposite his name;

NOW, THEREFORE, each of the undersigned hereby constitutes and appoints JOHN R. MCCALL and S. BRADFORD RIVES, and each of them, individually, his attorney, with full power to act for him and in his name, place, and stead, to sign his name in the capacity or capacities set forth below to the 2003 Form 10-K and to any and all amendments to such 2003 Form 10-K and hereby ratifies and confirms all that said attorney may or shall lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned have hereunto set their hands and seals as of this 29th day of March, 2004.

/s/ Victor A. Staffieri	/s/ John R. McCall
VICTOR A. STAFFIERI	JOHN R. McCALL
Chairman, President and Chief	Executive Vice President, General Counsel
Executive Officer	and Corporate Secretary
(Principal Executive Officer)	Director
	/s/ S. Bradford Rives
	S. BRADFORD RIVES
	Chief Financial Officer
	(Principal Accounting Officer)
	Director

POWER OF ATTORNEY

WHEREAS, KENTUCKY UTILITIES COMPANY, a Kentucky corporation, is to file with the Securities and Exchange Commission, under the provisions of the Securities Exchange Act of 1934, as amended, its Annual Report on Form 10-K for the year ended December 31, 2003 (the 2003 Form 10-K); and

WHEREAS, each of the undersigned holds the office or offices in KENTUCKY UTILITIES COMPANY set opposite his name;

NOW, THEREFORE, each of the undersigned hereby constitutes and appoints JOHN R. McCALL, and S. BRADFORD RIVES, and each of them, individually, his attorney, with full power to act for him and in his name, place, and stead, to sign his name in the capacity or capacities set forth below to the 2003 Form 10-K and to any and all amendments to such 2003 Form 10-K and hereby ratifies and confirms all that said attorney may or shall lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned have hereunto set their hands and seals as of this 29th day of March, 2004.

/s/ Victor A. Staffieri	/s/ John R. McCall
VICTOR A. STAFFIERI	JOHN R. McCALL
Chairman, President and Chief	Executive Vice President, General Counsel
Executive Officer	and Corporate Secretary
(Principal Executive Officer)	Director
	/s/ S. Bradford Rives
	S. BRADFORD RIVES
	Chief Financial Officer
	(Principal Accounting Officer)
	Director

EX-31.1

Exhibit 31.1

CERTIFICATIONS

Louisville Gas and Electric Company

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

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

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

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

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

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

c) disclosed in this annual report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting;

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.

Date:  March 29, 2004

/s/  Victor A. Staffieri

Victor A. Staffieri

Chairman of the Board, President and Chief Executive Officer

1

EX-31.2

Exhibit 31.2

Louisville Gas and Electric Company

I, S. Bradford Rives, Chief Financial Officer, certify that:

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

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

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

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

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

c) disclosed in this annual report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting;

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.

Date:  March 29, 2004

/s/  S. Bradford Rives

S. Bradford Rives

Chief Financial Officer

1

EX-31.3

Exhibit 31.3

Kentucky Utilities Company

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

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

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

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

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

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

c) disclosed in this annual report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting;

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.

Date:  March 29, 2004

/s/  Victor A. Staffieri

Victor A. Staffieri

Chairman of the Board, President and Chief Executive Officer

1

EX-31.4

Exhibit 31.4

Kentucky Utilities Company

I, S. Bradford Rives, Chief Financial Officer, certify that:

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

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

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

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

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

c) disclosed in this annual report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting;

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.

Date:  March 29, 2004

/s/  S. Bradford Rives

S. Bradford Rives

Chief Financial Officer

1

EX-32

Exhibit 32

Certification Pursuant to 18 U.S.C. Section 1350
As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Annual Report of Louisville Gas and Electric Company and Kentucky Utilities Company (the “Companies”) on Form 10-K for the year ended December 31, 2003, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned does hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer’s knowledge,

1)   The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2)   The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Companies as of the dates and for the period expressed in the Report.

March 29, 2004

	/s/  Victor A. Staffieri
Chairman of the Board, President
and Chief Executive Officer
Louisville Gas and Electric Company
Kentucky Utilities Company
	/s/  S. Bradford Rives
Chief Financial Officer
Louisville Gas and Electric Company
Kentucky Utilities Company

The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document.

1

EX-99.1

Exhibit 99.1

Cautionary Factors for Louisville Gas and Electric Company and Kentucky Utilities Company

The Private Securities Litigation Reform Act of 1995 provides a “safe harbor” for forward-looking statements to encourage such disclosures without the threat of litigation providing those statements are identified as forward-looking and are accompanied by meaningful, cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement. Forward-looking statements have been and will be made in written documents and oral presentations of E.ON AG (“E.ON”), Powergen Limited (“Powergen”), LG&E Energy LLC (“LG&E Energy”), Louisville Gas and Electric Company (“LG&E”) and Kentucky Utilities Company (“KU”) (the latter entities, LG&E and KU, collectively, the “Companies”). Such statements are based on management’s beliefs as well as assumptions made by and information currently available to management. When used in the Companies’ documents or oral presentations, the words “anticipate,” “estimate,” “expect,” “objective” and similar expressions are intended to identify forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause the Companies’ actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:

•Increased competition in the utility, natural gas and electric power marketing industries, including effects of: decreasing margins as a result of competitive pressures; industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of investments made under traditional regulation; nature of competitors entering the industry; retail wheeling; a new pricing structure; and former customers entering the generation market;

•Changing market conditions and a variety of other factors associated with physical energy and financial trading activities including, but not limited to, price, basis, credit, liquidity, volatility, capacity, transmission, currency, interest rate and warranty risks;

•Risks associated with price risk management strategies intended to mitigate exposure to adverse movement in the prices of electricity and natural gas on both a global and regional basis;

•Legal, regulatory, public policy-related and other developments which may result in redetermination, adjustment or cancellation of revenue payment streams paid to, or increased capital expenditures or operating and maintenance costs incurred by, the Companies, in connection with rate, fuel, transmission, environmental consumer choice, safety and security and other proceedings or rules applicable to the Companies;

•Legal, regulatory, economic and other factors which may result in redetermination or cancellation of revenue payment streams under power sales agreements resulting in reduced operating income and potential asset impairment related to the Companies’ investments in independent power production ventures, as applicable;

•Economic conditions including inflation rates and monetary fluctuations;

•Trade, monetary, fiscal, taxation, and environmental policies of governments, agencies and similar organizations in geographic areas where the Companies have a financial interest;

•Customer business conditions including demand for their products or services and supply of labor and materials used in creating their products and services;

•Financial or regulatory accounting principles or policies imposed by the Financial Accounting Standards Board, the Securities and Exchange Commission, the Federal Energy Regulatory Commission, state public utility commissions, state entities which regulate natural gas transmission, gathering and processing and similar entities with regulatory oversight;

•Availability or cost of capital such as changes in: interest rates, market perceptions of the utility and energy-related industries, the Companies or any of their subsidiaries or security ratings;

•Factors affecting utility and non-utility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, unusual maintenance or repairs; unanticipated changes to fossil fuel, or gas supply costs or availability due to higher demand, shortages, transportation problems or other developments; environmental incidents; or electric transmission or gas pipeline system constraints;

•Employee workforce factors including changes in key executives, collective bargaining agreements with union employees, or work stoppages;

•Rate-setting policies or procedures of regulatory entities, including environmental externalities;

•Social attitudes regarding the utility, natural gas and power industries;

•Identification of suitable investment opportunities to enhance shareholder returns and achieve long-term financial objectives through business acquisitions;

•Some future project investments made by the Companies, respectively, as applicable, could take the form of minority interests, which would limit the Companies’ ability to control the development or operation of the project;

•Legal and regulatory delays and other unforeseeable obstacles associated with mergers, acquisitions and investments in joint ventures;

•Costs and other effects of legal and administrative proceedings, settlements, investigations, claims and matters, including but not limited to those described in Notes 3, 11 and 16 (for LG&E) and Notes 3, 11 and 15 (for KU) of the respective Notes to Financial Statements of the Companies’ Annual Reports on Form 10-K for the year ended December 31, 2003, and items under the caption Commitments and Contingencies;

•Technological developments, changing markets and other factors that result in competitive disadvantages and create the potential for impairment of existing assets;

•Factors associated with non-regulated investments, including but not limited to: continued viability of partners, foreign government actions, foreign economic and currency risks, political instability in foreign countries, partnership actions, competition, operating risks, dependence on certain customers, third-party operators, suppliers and domestic and foreign environmental and energy regulations;

•Other business or investment considerations that may be disclosed from time to time in the Companies’ Securities and Exchange Commission filings or in other publicly disseminated written documents;

•Factors affecting the realization of anticipated cost savings associated with the merger between LG&E Energy and KU Energy Corporation including national and regional economic conditions, national and regional competitive conditions, inflation rates, weather conditions, financial market

conditions, and synergies resulting from the business combination;

•Factors associated with market conditions in the pipeline construction and repair industry, both national and international, including, general levels of industry activity, fuels and liquids price levels, competition, foreign economic, currency, regulatory and operating risks and dependence on certain customers, suppliers and operators;

•Factors associated with, resulting from or affecting the merger transaction between LG&E Energy and Powergen, including the integration of the existing business and operations of LG&E and KU as part of the Powergen group of companies thereunder, as well as national and international economic, financial market, regulatory and industry conditions or environments applicable to Powergen and its subsidiaries, including LG&E and KU, in the future.

•Factors associated with, resulting from or affecting the acquisition and operation of Powergen and LG&E Energy by E.ON, including the integration of the existing business and operations of LG&E and KU as part of the E.ON group of companies thereunder, as well as national and international economic, financial market, regulatory and industry conditions or environments applicable to E.ON and its subsidiaries, including LG&E and KU, in the future.

The Companies undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

EX-99.2

Exhibit 99.02

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

The outstanding stock of Louisville Gas and Electric Company (“LG&E”) is divided into three classes: Common Stock, Preferred Stock (without par value), and Preferred Stock, par value $25 per share. At the close of business on February 27, 2004, the following shares of four series of such classes were outstanding:

Common Stock, without par value	21,294,223 shares
Preferred Stock, par value $25 per share, 5% Series	860,287 shares
Preferred Stock, without par value, $5.875 Series	237,500 shares
Auction Series A (stated value $100 per share)	500,000 shares

The outstanding stock of Kentucky Utilities Company (“KU”) is divided into three classes: Common Stock, without par value, Preferred Stock, without par value, and Preference Stock, without par value. As of the close of business on February 27, 2004, the following shares of three series of such classes were outstanding:

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

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

As of February 27, 2004, all directors, nominees for director and executive officers of LG&E and KU as a group beneficially owned no shares of LG&E Preferred Stock or KU Preferred Stock and less than 1% of E.ON AG shares.

On December 11, 2000, then Powergen plc, a public limited company with registered offices in England and Wales (“Powergen”) completed its acquisition of LG&E Energy, the parent corporation of LG&E and KU for cash of approximately $3.2 billion, or $24.85 per share of LG&E Energy common stock. In connection with such transaction, certain officers and directors of Powergen were appointed to fill vacancies in the Board of Directors of LG&E and KU occurring by resignation of prior directors.  In January 2003, Powergen was reregistered as Powergen Limited.

On July 1, 2002, E.ON AG, a German corporation (“E.ON”), completed the acquisition of Powergen for cash of approximately 8.1 billion euros or 7.65 British pounds per Powergen ordinary share (equal to 30.60 British pounds per Powergen American Depository Share.) In connection with such transaction, certain officers or directors of E.ON and Powergen were appointed to fill vacancies in the Board of Directors of LG&E and KU occurring by resignation of prior directors.

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

1

INFORMATION ABOUT DIRECTORS

The number of members of the Board of Directors of LG&E and KU is currently fixed at three, pursuant to the Companies’ bylaws and resolutions adopted by the Boards of Directors. Generally, directors are elected at each year’s Annual Meeting to serve for one-year terms and to continue in office until their successors are elected and qualified.

Effective July 1, 2002, in connection with the completion of the E.ON-Powergen acquisition, Sir Frederick Crawford, Dr. David K-P Li and Messrs. Nicholas P. Baldwin, Sydney Gillibrand and David J. Jackson resigned as directors of LG&E and KU. Messrs. Victor A. Staffieri and Edmund A. Wallis continued as directors and Mr. Michael Söhlke was appointed to fill a vacancy. Effective June 18, 2003, Edmund A. Wallis tendered his resignation, resulting in Boards of two persons.  On November 3, 2003, Dr. Hans Michael Gaul was appointed to fill this vacancy and Messrs. John R. McCall and S. Bradford Rives were also appointed directors.  At this time, the Boards also adopted or ratified actions, including an amendment to the LG&E bylaws to reduce the quorum requirement to one-third the number of directors to permit more efficient administration of that board.  Following this action, Messrs. McCall and Rives tendered their resignations.  At their 2003 Annual Meetings held on December 16, 2003, LG&E’s and KU’s shareholders each approved amendments previously recommended by the Boards which reduce the required number of directors from nine to three and eliminated staggered terms for directors.

Effective January 31, 2004, Dr. Gaul and Mr. Söhlke resigned from the Boards of LG&E and KU and Messrs. McCall and Rives were appointed to fill the vacancies created thereby.

The following contains certain information as of February 27, 2004 concerning the directors of LG&E and KU:

Directors with Terms Expiring at the 2005 Annual Meeting of Shareholders

Victor A. Staffieri (Age 48):Mr. Staffieri is Chairman, President and Chief Executive Officer of LG&E Energy, LG&E and KU, serving from April 2001 to the present. He served as President and Chief Operating Officer of LG&E Energy, LG&E and KU from February 1999 to April 2001; Chief Financial Officer of LG&E Energy and LG&E, May 1997 to February 2000; Chief Financial Officer of KU, May 1998 to February 2000. President, Distribution Services Division of LG&E Energy, December 1995 to May 1997; Senior Vice President, General Counsel and Public Policy of LG&E Energy and LG&E from November 1992 to December 1993. Mr. Staffieri has been a director of LG&E Energy, LG&E and KU since April 2001 and of Powergen from April 2001 until January 2004.

John R. McCall  (Age 60):Mr. McCall is Executive Vice President, General Counsel and Secretary of LG&E Energy and Executive Vice President, General Counsel and Corporate Secretary of LG&E and KU.  Mr. McCall has held these positions at LG&E Energy (or its predecessor) and LG&E since July 1994 and at KU since May 1998.  Mr. McCall has been a director of LG&E and KU since January 2004.

S. Bradford Rives (Age 45):Mr. Rives is Chief Financial Officer of LG&E Energy, LG&E and KU, serving from September 2003 until the present.  He served as Senior Vice President - Finance and Controller of LG&E Energy, LG&E and KU from December 2000 until September 2003; Senior Vice President - Finance and Business Development of LG&E Energy and LG&E from February 1999 to December 2000; and Vice President - Finance and Controller of LG&E Energy and LG&E from March 1996 to February 1999.  Mr. Rives has been a director of LG&E and KU since January 2004.

2

INFORMATION CONCERNING THE BOARD OF DIRECTORS

The Boards of Directors of LG&E and KU contain the same members.  Each member is also a director of LG&E Energy, as described above.

During 2003, there were a total of 18 meetings or consents of the LG&E and KU Boards. All directors attended 75% or more of the total number of meetings or consents of the Board of Directors and committees of the Board on which they served.

Compensation of Directors

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

Committees

There are currently no committees of the Boards of Directors of the Companies.  Due to the small Board size of three members, the Board as a whole performs the functions related to audit or nominating committees.

In July 2002, upon completion of the E.ON-Powergen acquisition, the structures of the LG&E and KU Boards were changed to recognize practical and administrative efficiencies. The LG&E and KU Boards and LG&E Energy Board, respectively, adopted resolutions providing that (i) the functions of the former Audit Committee would be performed by the LG&E and KU Boards as a whole and (ii) certain functions of the former Remuneration Committee under certain LG&E Energy executive compensation plans would be performed by the Senior Vice President - Corporate Executive Human Resources of E.ON AG, currently Dr. Stefan Vogg.

Audit and Auditor Matters

During 2003, the Boards maintained direct and indirect contact with the independent auditors and LG&E’s and KU’s internal Audit Services to review the following matters pertaining to LG&E and KU:  the adequacy of accounting and financial reporting procedures; the adequacy and effectiveness of internal accounting controls; the scope and results of the annual audit and any other matters relative to the audit of the Companies’ accounts and financial affairs that the Board, Audit Services or the independent auditors deemed necessary.  A report of the Board acting as Audit Committee is included in the “Report of 2003 Audit Committee” section of this document.  A copy of the charter applicable to the Board acting as Audit Committee is included as Appendix A of this document.

The Board is responsible for approving all audit and permissible non-audit services to be provided by the independent auditors in accordance with LG&E’s and KU’s Pre-Approval Policy.  Under the policy, the Board annually reviews and pre-approves the services that may be provided by the independent auditor without obtaining specific pre-approval from the Board.  These include audit services, audit-related services, tax services and some permissible non-audit services, up to designated fee or budget levels.  New services or services exceeding these levels will require separate pre-approval by the Board.  Under the policy, the Board may delegate pre-approval authority to one or more of its members, subject to reporting of any decisions by such member to the Board, or may rely upon certain annual or other pre-approvals by the E.ON AG Audit Committee under its policy, subject to certain reporting to the Board.

Nominations

Nominations for the election of directors may be made by the Boards, a committee thereof or by shareholders entitled to vote in the election of directors generally.  Shareholder nominations must provide timely written notice in writing to the Companies’ Secretary in accordance with the procedures set forth in the section “Shareholder Proposals” of this document.  The Boards’ chairman may void the nomination of any candidate for election which was not made in compliance with applicable procedures.

3

REPORT REGARDING REMUNERATION

Following the July 1, 2002 completion of E.ON’s acquisition of Powergen, the Remuneration Committee of the Boards of Directors of LG&E and KU was terminated.  As stated above, the LG&E Energy, LG&E and KU Boards adopted resolutions providing that certain functions of the former Remuneration Committee under certain executive compensation plans would be performed by the Senior Vice President - Corporate Executive Human Resources of E.ON, currently Dr. Stefan Vogg.  This report describes the compensation policies applicable to the Companies’ executive officers for the last completed fiscal year.

Prior to 2003, Dr. Vogg, in consultation with certain officers of E.ON AG, Powergen, LG&E Energy, LG&E and KU, including members of the Companies’ Boards of Directors (collectively, the “Compensation Group”), arrived at decisions regarding the compensation of LG&E’s and KU’s executive officers, including the setting of base pay levels for 2003, and the administration and determination of awards under the E.ON Group Stock Option Program (the “E.ON SAR Plan”) and the LG&E Energy Corp. Performance Unit Plan (the “Long-Term Plan”) and of payments under the Short-Term Incentive Plan (the “Short-Term Plan”) as applicable to LG&E and KU.

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

Set forth below is a report addressing LG&E’s and KU’s compensation policies during 2003 for their officers, including the executive officers named in the following tables. In many cases, the executive officers also serve in similar capacities for affiliates of LG&E and KU, including LG&E Energy. For each of the executive officers of LG&E and KU, the policies and amounts discussed below are for all services to LG&E, KU and their affiliates, during the relevant period.

Compensation Philosophy

During 2003, LG&E’s and KU’s executive compensation program had three major components: (1) base salary; (2) short-term or annual incentives; and (3) long-term incentives. The Companies developed their executive compensation program to focus on both short-term and long-term business objectives that are designed to enhance overall shareholder value. The short-term and long-term incentives were premised on the belief that the interests of executives should be closely aligned with those of the Companies’ shareholders. Based on this philosophy, these two portions of each executive’s total compensation package were linked to the accomplishment of specific results that were designed to benefit the Companies’ shareholders in both the short-term and long-term.

The executive compensation program also recognized that the Companies’ compensation practices must be competitive not only with utilities and utility holding companies, but also with companies in general industry to ensure that a stable and successful management team can be recruited and retained.

Pursuant to this competitive market positioning philosophy, in establishing compensation levels for all executive positions for 2003, the Compensation Group reviewed competitive compensation information for United States general industry companies with revenue of approximately $3 billion (the “Survey Group”) and established targeted total direct compensation (base salary plus short-term incentives and long-term incentives) for each executive for 2003 to generally approach the 50th percentile of the competitive range from the Survey Group.  Salaries, short-term incentives and long-term incentives for 2003 are described below.

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The 2003 compensation information set forth in other sections of this document, particularly with respect to the tabular information presented, reflects the considerations set forth in this report. The Base Salary, Short-Term Incentives, and Long-Term Incentives sections that follow address the compensation philosophy for 2003 for all executive officers except those serving as Chief Executive Officer. (See “Chief Executive Officer Compensation”).

Base Salary

The base salaries for LG&E and KU executive officers for 2003 were designed to be competitive with the Survey Group at approximately the 50th percentile of the base salary range for executives in similar positions with companies in the Survey Group. Actual base salaries were determined based on a combination of market position, individual performance and experience.

Short-Term Incentives

The Short-Term Plan provided for Company Performance Awards and Individual Performance Awards, each of which is expressed as a percentage of base salary and each of which is determined independent of the other. The Compensation Group established the performance goals for the Company Performance Awards and Individual Performance Awards at the beginning of the 2003 performance year. Payment of Company Performance Awards for executive officers was based on varying performance measures tied to each officer’s responsible areas. These measures and goals included, among others, LG&E Energy internal operating profit targets and LG&E/KU internal operating profit targets.  The Compensation Group retains discretion to adjust the measures and goals as deemed appropriate. Payment of Individual Performance Awards was based 100% on management effectiveness. As stated, the awards varied within the executive officer group based upon the nature of each individual’s functional responsibilities.

For 2003, the Company Performance Award targets for named executive officers ranged from 29% to 42% of base salary, and the Individual Performance Award targets ranged from 20% to 28% of base salary. Both awards were established to be competitive with the 50th percentile of such awards granted to comparable executives employed by companies in the Survey Group. The individual officers were eligible to receive from 0% to 175% of their targeted Company Performance Award amounts, dependent upon Company performance as measured by the relevant performance goals, and were eligible to receive from 0% to 175% of their targeted Individual Performance Award amounts dependent upon individual performance as measured by management effectiveness.

Using the relevant E.ON, Powergen, LG&E Energy, LG&E/KU and other subsidiaries’ performance against goals in 2003 and making adjustments for certain foreign currency rate effects, the Compensation Group determined relative annual performance against targets for Company Performance Awards. Based upon this determination, Company Performance Awards for 2003 to the named executive officers were paid ranging from 119% to 159% of target and 36% to 67% of base salary. Based on determinations of management effectiveness, payouts for Individual Performance Awards to the named executive officers ranged from 150% to 165% of target and 30% to 48% of base salary.

Long-Term Incentives

The Compensation Group determines the competitive long-term grants under the Long-Term Plan and the E.ON SAR Plan to be awarded for each executive based on the long-term awards for the 50th percentile of the Survey Group. The aggregate expected value of the awards is intended to approach the expected value of long-term incentives payable to executives in similar positions with companies in the 50th percentile of the Survey Group, depending upon achievement of targeted Company performance.

In 2003, the Compensation Group granted performance units under the Long-Term Plan to executive officers and senior management and stock appreciation rights (“SAR’s”) under the E.ON SAR Plan to executive officers.

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The amounts of the executive’s long-term award to be delivered in SAR’s and performance units were 25% and 75% respectively.  Under the Long-Term Plan, the future value of grants of performance units is dependent upon company performance against a value-added target.  The ultimate value of the performance unit can range from 0% to 150% of grant. Under the E.ON SAR Plan, the amount paid to executives when they exercise their SAR’s, after satisfaction of vesting and performance criteria, is the difference between E.ON’s stock price at the time of exercise and the stock price at the time of issuance, multiplied by the number of SAR’s exercised.  The price at issuance is the average of the XETRA closing quotations for E.ON stock during the December prior to issuance.  The future value of the 2003 grants of SAR's was substantially dependent upon the changing value of E.ON shares in the marketplace.

No SAR’s were exercisable during 2003 as the two year vesting requirements had not been completed.   No regular payouts of performance units under the Long-Term Plan occurred during 2003 as the three-year performance periods had not been completed.

Other

In connection with the E.ON-Powergen merger, Messrs. Staffieri and McCall entered into amendments to their employment and severance agreements and the other named officers entered into new retention and severance agreements.

Chief Executive Officer Compensation

Mr. Victor A. Staffieri was appointed Chief Executive Officer of LG&E and KU effective May 1, 2001. Mr. Staffieri’s compensation was governed by the terms of an Employment and Severance Agreement entered into on February 25, 2000 as amended (including upon his appointment as Chief Executive Officer) (the “2000 Agreement”). The 2000 Agreement was for an initial term of two years commencing on December 11, 2000, with automatic annual extensions thereafter unless the Companies or Mr. Staffieri give notice of non-renewal.

The 2000 Agreement established the minimum levels of Mr. Staffieri’s base compensation, although the Chairman of E.ON AG retains discretion to increase such compensation. In the first quarter of 2003, the Compensation Group established Mr. Staffieri’s compensation and long-term awards using comparisons to relevant officers of companies in the Survey Group, including utilities, and survey data from various compensation consulting firms. Mr. Staffieri also received Company contributions to the savings plan, similar to those of other officers and employees. Details of Mr. Staffieri’s 2003 compensation are set forth below.

Base Salary.Mr. Staffieri was paid a total base salary of $648,902 during 2003, pursuant to the 2000 Agreement, as amended. The Compensation Group, in determining Mr. Staffieri’s 2003 annual salary, including the minimum, considered his individual performance in the prior growth of LG&E Energy and the comparative compensation data described above.

Short-Term Incentives.Mr. Staffieri’s short-term incentive target award as Chief Executive Officer was 70% of his 2003 base salary. As with other executive officers receiving short-term incentive awards, Mr. Staffieri was eligible to receive more or less than the targeted amount, based on Company performance and individual performance. His 2003 short-term incentive payouts were based 60% on achievement of Company Performance Award targets and 40% on achievement of Individual Performance Award targets.

For 2003, the Company Performance Award payout for Mr. Staffieri was 158% of target and 67% of his 2003 base salary and the Individual Performance Award payout was 170% of target and 48% of his 2003 base salary.  Mr. Staffieri’s Company Performance Award

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was based on LG&E Energy internal operating profit.  His Company Performance Award was calculated based upon annual Company performance as described under the heading “Short-Term Incentives.”  In determining the Individual Performance Award, the Compensation Group considered Mr. Staffieri’s effectiveness in several areas, including the financial and operational performance of LG&E Energy, LG&E, KU and other subsidiaries, Company growth and other measures.

Long-Term Incentive Grant.In 2003, Mr. Staffieri received 851,681 performance units for the 2003-2005 performance period under the Long-Term Plan and 25,282 SAR’s under the E.ON SAR Plan. These amounts were determined pursuant to the terms of his 2000 Agreement, as amended, with an aggregate expected value representing approximately 175% of his base salary. The terms of the performance units and SAR’s for Mr. Staffieri are the same as for other executive officers, as described under the heading “Long-Term Incentives.”

Long-Term Incentive Payout.As with other executive officers, no SAR’s were exercisable by Mr. Staffieri during 2003 as the two year vesting requirements had not been completed.  As with other executive officers, no regular payouts of performance units under the Long-Term Plan occurred during 2003 as the three-year performance periods had not been completed.

Other.In 2003, Mr. Staffieri also received a bonus in connection with a 2002 amendment to his employment and severance agreement in the amount of $837,375, including interest.

Members of the Companies’ Boards of Directors

Victor A. Staffieri

John R. McCall

S. Bradford Rives

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EXECUTIVE COMPENSATION AND OTHER INFORMATION

The following table shows the cash compensation paid or to be paid by LG&E, KU or LG&E Energy, as well as certain other compensation paid or accrued for those years, to the Chief Executive Officer and the next four highest compensated executive officers of LG&E and KU who were serving as such at December 31, 2003, as required, in all capacities in which they served LG&E Energy or its subsidiaries during 2001, 2002 and 2003:

SUMMARY COMPENSATION TABLE

						Long-Term Compensation
						Awards	Payouts
				Other Annual Comp. ($)		Restricted Stock Awards ($)	Securities Underlying Options/SAR (#) (1)	LTIP Payouts ($) (2)	All Other Compen- Sation ($)
	Annual Compensation
Name and Principal Position	Year	Salary ($)	Bonus ($)
Victor A. Staffieri	2003	648,902	741,340	39,461		—	25,282	0	902,945	(3)
Chairman of the Board,	2002	630,001	650,101	24,282		—	6,250	1,483,377	2,433,735	(4)
President and Chief Executive Officer	2001	555,769	529,330	45,704		—	51,011	0	1,811,703	(5)
John R. McCall	2003	389,475	313,933	198,681	(6)	—	8,671	0	47,529	(3)
Executive Vice President,	2002	363,975	251,543	144,756	(6)	—	3,611	401,580	1,390,557	(4)
General Counsel and Corporate Secretary	2001	383,365	242,104	8,732		—	14,786	0	463,793	(5)
S. Bradford Rives	2003	305,495	243,607	6,880		—	5,345	0	423,923	(3)
Chief Financial Officer	2002	280,019	180,145	6,616		—	2,877	204,450	486,491	(4)
	2001	235,000	131,342	6,595		—	7,554	0	390,335	(5)
Paul W. Thompson	2003	269,071	187,526	7,232		—	4,792	0	10,151	(3)
Senior Vice President -	2002	262,497	147,944	8,106		—	2,604	290,000	440,486	(4)
Energy Services	2001	245,193	142,650	9,970		—	10,714	0	436,152	(5)
Chris Hermann	2003	252,928	166,267	4,905		—	3,378	0	22,463	(3)
Senior Vice President	2002	246,748	129,505	7,892		—	2,448	204,450	228,722	(4)
Energy Delivery	2001	234,999	131,342	12,122		—	7,554	0	13,996	(5)

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(1)Amounts for years 2003 and 2002 reflect E.ON SAR Plan grants.  Amounts for year 2001 reflect options for Powergen ADS’s.

(2)No payouts were made under the Long-Term Plan during years 2003 or 2002 as the three-year performance periods had not been completed.  Amounts for year 2002 reflect acceleration of open performance periods upon the change in control event resulting from the Powergen shareholders’ approval of the E.ON transaction.

(3)Includes employer contributions to 401(k) plan, nonqualified thrift plan, employer paid life insurance premiums, vacation sell back, and retention payments in 2003 as follows: Mr. Staffieri $6,000, $32,970, $26,600, $0 and $837,375, respectively; Mr. McCall $5,775, $13,680, $20,583, $7,491 and $0,  respectively; Mr. Rives $3,229, $11,478, $1,042, $4,618 and $403,556, respectively; Mr. Thompson, $2,688, $5,384, $2,078, $0 and $0, respectively; and Mr. Hermann, $5,732, $5,886, 5,981, $4,864 and $0, respectively.  The retention payments above are discussed in the “Report Regarding Remuneration” and  “Employment Contracts and Termination of Employment Arrangements and Change in Control Provisions”.

(4)Includes retention payments in 2002 as follows: Mr. Staffieri, $2,349,170; Mr. McCall, $1,346,416; Mr. Rives, $87,746; Mr. Thompson, $425,926; and Mr. Hermann, $211,342, respectively.

(5)Includes retention payments in 2001 as follows: Mr. Staffieri, $1,719,884; Mr. McCall, $423,524; Mr. Rives, $382,393; Mr. Thompson, $405,860; and Mr. Hermann, $0, respectively.

(6)Includes financial planning, automobile, spouse travel, dues, overseas compensation and tax payments in 2003 ($1,500, $4,000, $7,202, $0, $0 and $178,445) and 2002 ($2,000, $7,586, $50,589, $240, $36,398 and $48,143) respectively.

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OPTION/SAR GRANTS TABLE

Option/SAR Grants in 2003 Fiscal Year

The following table contains information at December 31, 2003, with respect to grants of E.ON AG stock appreciation rights (SAR’s) to the named executive officers:

	Individual Grants					Potential Realizable Value At Assumed Annual Rates of Stock Price Appreciation For Option Term
	Number of Securities Underlying Options/SARs Granted (#) (1)	Percent of Total Options/SARs Granted to Employees in Fiscal Year(2)		Exercise Or Base Price ($/ Share)	Expiration Date			10%($)
Name						0%($)	5% ($)
Victor A. Staffieri	25,282	36.1	%	43.99	12/31/2009	0	452,759	1,055,121
John R. McCall	8,671	12.4	%	43.99	12/31/2009	0	155,283	361,876
S. Bradford Rives	5,345	7.6	%	43.99	12/31/2009	0	95,720	223,069
Paul W. Thompson	4,792	6.9	%	43.99	12/31/2009	0	85,817	199,990
Chris Hermann	3,378	4.8	%	43.99	12/31/2009	0	60,494	140,978

(1)  E.ON SAR’s were awarded with an exercise price at issuance equal to the average XETRA closing quotations for E.ON stock during the December prior to issuance.  The SAR’s are exercisable over a seven-year period from their issuance date.

(2)  Represents percentage grants to LG&E Energy, LG&E and KU employees only.

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OPTION/SAR EXERCISES AND YEAR-END VALUE TABLE

Aggregated Option/SAR Exercises in 2003 Fiscal Year

And FY-End Option/SAR Values

The following table sets forth information with respect to the named executive officers concerning the value of unexercised E.ON SAR’s held by them as of December 31, 2003:

Name	Shares Acquired On Exercise (#)(1)	Value Realized ($)	Number of Securities Underlying Unexercised Options/SARs at FY-End (#)(2) Exercisable/Unexercisable	Value of Unexercised In-The-Money Options/SARs at FY-End ($) Exercisable/Unexercisable
Victor A. Staffieri	0	0	0 / 31,532	0 / $640,924
John R. McCall	0	0	0 / 12,282	0 / $242,975
S. Bradford Rives	0	0	0 / 8,222	0 / $160,049
Paul W. Thompson	0	0	0 / 7,396	0 / $143,880
Chris Hermann	0	0	0 / 5,826	0 / $111,088

(1)Amounts shown are E.ON SAR’s.  At December 31, 2003, no E.ON SAR’s were exercisable due to the two year vesting period from their 2002 or 2003 grant dates.

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LONG-TERM INCENTIVE PLAN AWARDS TABLE

Long-Term Incentive Plan Awards in 2003 Fiscal Year

The following table provides information concerning awards of performance units made in 2003 to the named executive officers under the Long-Term Plan.

	Number of Shares, Units or Other Rights(1)	Performance or Other Period Until Maturation Or Payout	Estimated Future Payouts under Non-Stock Price Based Plans (number of shares) (1)
Name			Threshold(#)	Target(#)	Maximum(#)
Victor A. Staffieri	851,681	12/31/2005	425,841	851,681	1,277,522
John R. McCall	292,106	12/31/2005	146,053	292,106	438,159
S. Bradford Rives	180,090	12/31/2005	90,045	180,090	270,135
Paul W. Thompson	161,445	12/31/2005	80,723	161,445	242,168
Chris Hermann	113,816	12/31/2005	56,908	113,816	170,724

(1)Amounts shown are awards of performance units under the Long-Term Plan during 2003.

Each performance unit awarded under the Long-Term Plan represented the right to receive an amount payable in cash on the date of payout. The amount of the payout is determined by the company performance over a three year cycle. For awards made in 2003, the Long-Term Plan awards were intended to reward executives on a three-year rolling basis dependent upon the achievement of a value-added target by LG&E Energy.

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Pension Plans

The following table shows the estimated pension benefits payable to a covered participant at normal retirement age under LG&E Energy’s qualified defined benefit pension plans, as well as non-qualified supplemental pension plans that provide benefits that would otherwise be denied participants by reason of certain Internal Revenue Code limitations for qualified plan benefits, based on the remuneration that is covered under the plan and years of service with LG&E Energy and its subsidiaries:

2003 PENSION PLAN TABLE

		Years of Service
Remuneration		15		20		25		30 or more
$	100,000	$	43,348	$	43,348	$	43,348	$	43,348
$	200,000	$	107,348	$	107,348	$	107,348	$	107,348
$	300,000	$	171,348	$	171,348	$	171,348	$	171,348
$	400,000	$	235,348	$	235,348	$	235,348	$	235,348
$	500,000	$	299,348	$	299,348	$	299,348	$	299,348
$	600,000	$	363,348	$	363,348	$	363,348	$	363,348
$	700,000	$	427,348	$	427,348	$	427,348	$	427,348
$	800,000	$	491,348	$	491,348	$	491,348	$	491,348
$	900,000	$	555,348	$	555,348	$	555,348	$	555,348
$	1,000,000	$	619,348	$	619,348	$	619,348	$	619,348
$	1,100,000	$	683,348	$	683,348	$	683,348	$	683,348
$	1,200,000	$	747,348	$	747,348	$	747,348	$	747,348
$	1,300,000	$	811,348	$	811,348	$	811,348	$	811,348
$	1,400,000	$	875,348	$	875,348	$	875,348	$	875,348
$	1,500,000	$	939,348	$	939,348	$	939,348	$	939,348
$	1,600,000	$	1,003,348	$	1,003,348	$	1,003,348	$	1,003,348
$	1,700,000	$	1,067,348	$	1,067,348	$	1,067,348	$	1,067,348
$	1,800,000	$	1,131,348	$	1,131,348	$	1,131,348	$	1,131,348
$	1,900,000	$	1,195,348	$	1,195,348	$	1,195,348	$	1,195,348

A participant’s remuneration covered by the Retirement Income Plan (the “Retirement Income Plan”) is his or her average base salary and short-term incentive payment (as reported in the Summary Compensation Table) for the five calendar plan years during the last ten years of the participant’s career for which such average is the highest. The years of service for each named executive employed by LG&E Energy at December 31, 2003 was as follows:  11 years for Mr. Staffieri; 9 years for Mr. McCall; 20 years for Mr. Rives; 12 years for Mr. Thompson; and 33 years for Mr. Hermann. Benefits shown are computed as a straight life single annuity beginning at age 65.

Current Federal law prohibits paying benefits under the Retirement Income Plan in excess of $160,000 per year. Officers of LG&E Energy, LG&E and KU with at least one year of service with an affiliated company are eligible to participate in LG&E Energy’s Supplemental Executive Retirement Plan (the “Supplemental Executive Retirement Plan”), which is an unfunded supplemental plan that is not subject to the $160,000 limit. Presently, participants in the Supplemental Executive Retirement Plan consist of all of the eligible officers of LG&E Energy, LG&E and KU. This plan provides generally for retirement benefits equal to 64% of average current earnings during the highest 36 consecutive months prior to retirement, reduced by Social Security benefits, by amounts received under the Retirement Income Plan and by benefits from other employers. As with all other officers, Mr. Staffieri participates in the Supplemental Executive Retirement Plan described above.

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Estimated annual benefits to be received under the Retirement Income Plan and the Supplemental Executive Retirement Plan upon normal retirement at age 65 and after deduction of Social Security benefits will be $702,523 for Mr. Staffieri; $344,984 for Mr. McCall; $251,425 for Mr. Rives; $241,419 for Mr. Thompson; and $208,324 for Mr. Hermann.

EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT

ARRANGEMENTS AND CHANGE IN CONTROL PROVISIONS

In connection with the E.ON-Powergen merger, Messrs. Staffieri and McCall entered into amendments to their employment and severance agreements.  The original agreements, effective upon the LG&E Energy-Powergen merger for two year terms, contained change in control provisions and the benefits described below.  Pursuant to the amended agreements, Mr. Stafferi received certain retention payments in 2003, as described in the Report Regarding Renumeration and the Summary Compensation Table.

Under the terms of his revised employment and severance agreement, Mr. Staffieri is entitled to additional retention payments of $800,570, plus interest, on each of July 1, 2004 and January 1, 2005, (the two year and thirty month anniversaries of the E.ON-Powergen merger), which will initially be credited into a deferred compensation account and which will then be payable in a lump sum in cash, if Mr. Staffieri elects, upon (i) a termination of employment (other than by Mr. Staffieri without good reason), (ii) a change in control within 30 months of the E.ON-Powergen merger, or (iii) the respective first year, second year and thirty month anniversaries of the E.ON-Powergen merger, if Mr. Staffieri is still employed.  If during the term of his agreement, which is automatically extended for subsequent one year terms unless terminated upon 90 days notice, and within twenty four months following a change in control, Mr. Staffieri’s employment is terminated for reasons other than cause, disability or death, or for good reason, Mr. Staffieri shall be entitled to a severance amount equal to 2.99 times the sum of (1) his annual base salary and (2) his bonus or “target” award paid or payable.  If during the term of his agreement but prior to a change in control, Mr. Staffieri’s employment is terminated for reasons other than cause, disability or death, or for good reason, Mr. Staffieri will be entitled an amount equal to his annual base salary and target annual bonus.

Under the terms of his revised employment and severance agreement, if Mr. McCall is (a) employed by LG&E Energy or LG&E or any of their affiliates on July 1, 2004 or (b) terminated prior to July 1, 2004 for any reason other than by the employer for cause or by Mr. McCall without good reason; then in each case Mr. McCall is entitled to receive a lump sum cash payment equal to his annual salary plus target annual bonus.  If during the term of his agreement, which is automatically extended for subsequent one year terms unless terminated upon 90 days notice, and within twenty four months following a change in control or within forty-eight months of the E.ON- Powergen merger, Mr. McCall’s employment is terminated for reasons other than cause, disability or death, or for good reason, Mr. McCall shall be entitled to a severance amount equal to 2.99 times the sum of (1) his annual base salary and (2) his bonus or “target” award paid or payable, or, if within 48 months of the date of the E.ON-Powergen merger, 2.99 times the sum of (1) and (2).

In 2003, Mr. Rives became entitled to receive a scheduled retention payment of $355,078, plus interest, pursuant to the terms his retention agreement entered into at the time of the Powergen-LG&E Energy merger.  During 2002, in connection with the E.ON-Powergen merger, Messrs. Thompson, Rives and Hermann entered into new retention agreements under which these officers will be entitled to a payment equal to the sum of (1) his annual base salary and (2) his annual bonus or “target” award, in the event of their continued employment through the second anniversary of the E.ON-Powergen merger.  Messrs. Thompson, Rives and Hermann have also entered into change of control agreements with terms of 24 months, which provide that, in the event of termination of employment for reasons other than cause, disability or death, or for good reason within the 24 months following a change in control, these officers shall be entitled to a severance amount equal to 2.99 times the sum of (1) his annual base salary and (2) his bonus or “target” award paid or payable.

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

EQUITY COMPENSATION PLAN INFORMATION

The executive officers of LG&E and KU do not participate in any compensation plans under which equity securities of LG&E, KU or any affiliate are authorized for issuance.

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Report on 2003 Audit Committee Matters

The Board of Directors, consisting of three members, performed the functions of an Audit Committee (“Audit Committee”). The Audit Committee is governed by a charter adopted by the Board of Directors, which sets forth the responsibilities of the Audit Committee members.  The Audit Committee held one meeting during 2003.

The financial statements of Louisville Gas and Electric Company and Subsidiary and of Kentucky Utilities Company and Subsidiary are prepared by management, which is responsible for their objectivity and integrity.  With respect to the financial statements for the calendar year ended December 31, 2003, the Audit Committee reviewed and discussed the audited financial statements and the quality of the financial reporting with management and the independent accountants.  It also discussed with the independent accountants the matters required to be discussed by Statement on Auditing Standards No. 61, Communication with Audit Committees, as amended, and received and discussed with the independent accountants the matters in the written disclosures required by Independence Standards Board Standard No. 1, Independence Discussions with Audit Committees.

Based upon the reviews and discussions referred to above, the Audit Committee recommended to the Board of Directors the inclusion of the audited financial statements in Louisville Gas and Electric Company’s and Kentucky Utilities Company’s Annual Report on Form 10-K for the year ended December 31, 2003, for filing with the Securities and Exchange Commission.

The following information on independent audit fees and services is being provided in compliance with the Securities and Exchange Commission rules on auditor independence.

1.  PricewaterhouseCoopers LLP fees for the periods ended December 31, 2002 and December 31, 2003 are as follows:  (Certain amounts for 2002 have been reclassified to conform to 2003 presentation.)

	LG&E				KU
	2003		2002		2003		2002
•  Audit Fees
• Audit Fees	$	128,862	$	47,500	$	128,862	$	47,500
•  Regulatory Work	$	4,665	—		$	4,665	—
•  Total Audit Fees	$	131,527	$	47,500	$	133,527	$	47,500
•  Audit Related Fees
•  Pension Plan Audits	$	17,200	$	17,000	$	9,000	$	8,600
•  Comfort Letter Procedures	$	51,154	$	69,270	—		$	22,220
•  Total Audit Related Fees	$	68,354	$	86,270	$	9,000	$	30,820
•  Tax Fees	—		—		—		—
•  All Other Fees	—		—		—		—

2.The Audit Committee considered whether the independent accountant’s provision of non-audit services is compatible with maintaining the accountant’s independence.

3.The Audit Committee has been advised by PricewaterhouseCoopers LLP that hours expended on the audit engagement were entirely performed by PricewaterhouseCoopers’ personnel.

This report has been provided by the Board of Directors performing the functions of the Audit Committee.

Victor A. Staffieri, Chairman

John R. McCall

S. Bradford Rives

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SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING

LG&E and KU have in place procedures to assist its directors and officers in complying with Section 16(a) of the Exchange Act of 1934, which includes assisting the director or officer in preparing forms for filing.  However, due to administrative errors arising from the transition from overseas directors to US-based directors, two reports were filed late or omitted regarding personnel changes in November 2003 and January 2004.  All such errors related solely to entry or exit filings for individuals who had no holdings of or transactions in LG&E or KU securities.  Except as set forth above, based upon information provided to LG&E and KU by individual directors and officers, LG&E and KU believe that during the year ended December 31, 2003, all filing requirements have otherwise been complied with.

SHAREHOLDER PROPOSALS

Under LG&E’s By-laws, shareholders intending to nominate a director for election at the annual meeting must provide advance written notice. In general, such notice must be received by the Secretary of LG&E (a) not less than 90 days prior to the meeting date or (b) if the meeting date is not publicly announced more than 100 days prior to the meeting, by the tenth day following such announcement. Under KU’s s By-laws, shareholders intending to nominate a director for election at the annual meeting must provide advance written notice. In general, such notice must be received by the Secretary of KU (a) not less than 60 days prior to the meeting date or (b) if the meeting date is not publicly announced more than 70 days prior to the meeting, by the tenth day following such announcement.

To be proper, written notice must generally include (a) the name and address of the stockholder and of each nominee, (b) a representation that the stockholder is a holder of record entitled to vote at such meeting and intends to appear in person or by proxy, (c) a description of all arrangements between the stockholder and each nominee, (d) such other information regarding each nominee as would be required to be included in a proxy statement under the Securities and Exchange Commission rules had the nominee been nominated by the Board and (e) the consent of the each nominee to serve if elected.  LG&E proponents must also include the class and number of shares beneficially owned by the proponent.  Proposals not properly submitted will be considered untimely.

SHAREHOLDER COMMUNICATIONS

Shareholders can communicate with our Board by submitting a letter or writing addressed to a director care of:  John R. McCall, Secretary, Louisville Gas and Electric Company/Kentucky Utilities Company, P.O. Box 32102, 220 West Main Street, Louisville, KY  40232. The Secretary may initially review communications with directors and transmit a summary to the directors, but has discretion to exclude from transmittal any communications that are commercial advertisements or other forms of solicitation or individual service or billing complaints (although all communications are available to the directors upon request). The Secretary will forward to the directors any communications raising substantial issues.

We encourage all directors to attend our annual meeting. Two of our three directors were in attendance at the annual meeting in 2003.

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APPENDIX A

LOUISVILLE GAS AND ELECTRIC COMPANY

AND

KENTUCKY UTILITIES COMPANY

AUDIT COMMITTEE CHARTER

Mission Statement

The Audit Committee (the “Committee”) is a Committee, respectively, of the Boards of Directors (each, separately, the “Board”) of Louisville Gas and Electric Company and of Kentucky Utilities Company (each, separately, the “Company”).  Its primary function is to assist the Board in fulfilling its oversight responsibilities by reviewing the financial information provided to shareholders and others, the systems of internal controls which management and the Board of Directors have established and the audit process. Although operating as a combined Committee, actions of the Committee related to an individual Company only are applicable to such Company only, as appropriate.

Composition

The Committee will be composed of at least three members of the Board of Directors who shall serve at the pleasure of the Board.  In the event that the Board of Directors does not appoint a Committee, the functions of the Committee shall be performed by the Board of Directors or its members.

Audit Committee members will be appointed by the Board of Directors. One of the members will be designated as the Committee’s Chairman.  The Chairman will preside over the Committee meetings and report Committee actions to the Board of Directors.

Meetings

The Committee will meet on a regular basis and will call special meetings as circumstances require.  It will meet privately with the Director of Audit Services and the independent public accountant in separate executive sessions to discuss any matters that the Committee, the Director of Audit Services, or the independent accountant believes should be discussed privately. The Committee may ask members of management or others to attend meetings and provide pertinent information, as necessary.

Responsibilities

1.Provide an open avenue of communication between the internal auditors, the independent accountant, and the Board of Directors.

2.Review and update, where appropriate, the Committee’s charter annually.

3.Recommend to the Board of Directors on an annual basis the independent accountant to be nominated, approve the compensation of the independent accountant, and review and approve the discharge of the independent accountant.  The independent accountant is ultimately responsible to the Board of Directors and the Audit Committee.

4.Pre-approve the audit and non-audit services performed by the independent accountant as prescribed under the Sarbanes-Oxley Act of 2002, and related regulations of the Securities and Exchange Commission.

5.Review and concur in the appointment, replacement, reassignment or dismissal of the Director of Audit Services.

6.Require the independent accountant to submit to the Committee on a periodic basis a formal written statement regarding independence of such independent accountant and all facts and circumstances relevant thereto; discuss with the independent accountant its independence; confirm and assure the independence of the Audit Services

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Department and the independent accountant, including a review of management consulting services and related fees provided by the independent accountant; and recommend to the Board of Directors actions necessary to ensure independence of the Audit Services Department and the independent accountant.

7.Inquire of management, the Director of Audit Services, and the independent accountant about significant risks or exposures and assess the steps management has taken to minimize such risk to the Company.

8.Approve the annual audit plan and review the three-year plan of the internal auditing function. Review the independent accountant’s proposed audit plan, including coordination with Audit Services’ annual audit plan.

9.Review with the Director of Audit Services and the independent accountant the coordination of audit effort to assure completeness of coverage, reduction of redundant efforts, and the effective use of audit resources.

10.Consider with management and the independent accountant the rationale for employing audit firms other than the principal independent accountant.

11.Consider and review with the independent accountant and the Director of Audit Services:

a.The adequacy of the Company’s internal controls, including computerized information system controls and security, and

b.Any related significant issues identified by the independent accountant and Audit Services, together with management’s responses thereto.

12.Review with management and the independent accountant at the completion of the annual audit:

a.The Company’s annual financial statements and related footnotes;

b.The independent accountant’s audit of the financial statements and the report thereon;

c.The independent accountant’s judgment about the quality and appropriateness of the Company’s accounting principals as applied to its financial reporting;

d.Any significant changes required in the independent accountant’s audit plan and scope;

e.Any serious difficulties or disputes with management encountered during the course of the audit; and

f.Other matters related to the conduct of the audit which are to be communicated to the Committee under generally accepted auditing standards.

13.Review with management such appropriate notices or reports as may be required to be filed on behalf of the Committee with the regulatory authorities, exchanges or included in the Company’s proxy materials or otherwise, pursuant to law or exchange regulations.

14.Consider and review with management and the Director of Audit Services:

a.Any difficulties encountered in the course of their audits, including any restrictions on the scope of their work or access to required information;

b.Any significant changes required in their audit plan;

c.Any significant audit findings and management’s responses thereto;

d.The Audit Services Department staffing and staff qualifications; and

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e.The Audit Services Department charter.

15.Review with the Director of Audit Services the results of the annual Code of Business Conduct questionnaire.

16.Review legal and regulatory matters that may have a material impact on the financial statements, related Company compliance policies and programs, and reports received from regulators.

17.Report Committee actions to the Board of Directors with such recommendations as the Committee may deem appropriate.

18.Conduct or authorize investigations into any matters within the Committee’s scope of responsibilities, and retain independent counsel, accountants or others to assist it in the conduct of any investigation.

19.Assume such other duties and considerations as may be delegated to the Committee by the Board of Directors, or required of the Committee upon the request of the Board of Directors from time to time pursuant to a duly adopted resolution of the Board of Directors.

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