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.

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

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.

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.

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

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.

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 a 53-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

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.

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 5 counties 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 approximately 1.4 lbs./Mmbtu of 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

was -1 degree F.

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

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

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.

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.

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

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.

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.

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.

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.

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.

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 approximately 15.1 million Mcf. See Gas Supply under Item 1.

In 1990, LG&E entered into an operating lease for its corporate office building located in downtown Louisville, Kentucky. The lease 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

(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

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.

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.

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.

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.

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.

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

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

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.

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.

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	)

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).

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.

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.

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.

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.

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.

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.

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

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.

(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.

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.

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.

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

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

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

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.

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.

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.

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,

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 level of 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.

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

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

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

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.

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

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.

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.

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.

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:

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

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.

(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.

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

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

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

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.

(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.

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.

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

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.

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

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.

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.

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.

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

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 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 level of 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

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 SO₂reductions, 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

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.

FUTURE OUTLOOK

Competition and Customer Choice

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.

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

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.

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.

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.

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.

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.

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.

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

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:

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

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.

• 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.

(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

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.

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

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.

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.

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.

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.

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.

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

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.

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

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.

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.

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

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 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	)

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.

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	)

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

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:

	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.

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 $):

	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

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.

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.

The following table reflects the long-term debt maturities:

(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:

(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.

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

(e) Represents construction commitments.

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.

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.

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.

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

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

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.

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

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 consolidated financial 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.

111

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.

112

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.

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.

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.

113

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.

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.

114

Commitments and Contingencies, for a further discussion.

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

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

115

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.

• 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.

(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

116

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	)

117

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.

118

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.

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 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

119

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.

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

120

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.

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.

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.

121

As a separate matter, MISO, its transmission owners and other interested industry segments reached a settlement in mid-2002 regarding the level of 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.

122

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.

123

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	)

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.

124

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.

Note 5 - Concentrations of Credit and Other Risk

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

125

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	)

126

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:

127

(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

128

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	%

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.

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

129

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	%

130

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.

	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.

131

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:

132

	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.

(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.

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

133

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 SO₂requirements primarily through installation of FGD equipment on Ghent Unit 1. KU’s strategy for Phase II SO₂reductions, 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.

134

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.

Note 12 – Jointly Owned Electric Utility Plant

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

135

($ 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.

136

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.

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

137

(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)

	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).

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 consolidated financial 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):

LG&E:
Consolidated Statements of Income for the three years ended December 31, 2003.
Consolidated Statements of Retained Earnings for the three years ended December 31, 2003.
Consolidated Statements of Comprehensive Income for the three years ended December 31, 2003.
Consolidated Balance Sheets-December 31, 2003, and 2002.
Consolidated Statements of Cash Flows for the three years ended December 31, 2003.
Consolidated Statements of Capitalization-December 31, 2003, and 2002.
Notes to Consolidated Financial Statements.
Report of Management.
Report of Independent Auditors.

KU:
Consolidated Statements of Income for the three years ended December 31, 2003.

143

Consolidated Statements of Retained Earnings for the three years ended December 31, 2003.
Consolidated Statements of Comprehensive Income for the three years ended December 31, 2003.
Consolidated Balance Sheets-December 31, 2003, and 2002.
Consolidated Statements of Cash Flows for the three years ended December 31, 2003.
Consolidated Statements of Capitalization-December 31, 2003, and 2002.
Notes to Consolidated Financial Statements.
Report of Management.
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
Exhibit No.	LG&E	KU	Description

2.01	X	X	Copy of Agreement and Plan of Merger, dated as of February 27, 2000, by and among Powergen plc, LG&E Energy Corp., US Subholdco2 and Merger Sub, including certain exhibits thereto. [Filed as Exhibit 1 to LG&E’s and KU’s Current Report on Form 8-K filed February 29, 2000 and incorporated by reference herein]

2.02	X	X	Amendment No. 1 to Agreement and Plan of Merger, dated as of December 8, 2000, among LG&E Energy Corp., Powergen plc, Powergen US Investments Corp. and Powergen Acquisition Corp. [Filed as Exhibit 2.01 to LG&E’s and KU’s Current Report on Form 8-K filed December 11, 2000 and incorporated by reference herein]

2.03	X	X	Copy of Agreement and Plan of Merger, dated as of May 20, 1997, by and between LG&E Energy and KU Energy, including certain exhibits thereto. [Filed as Exhibit 2 to LG&E’s and KU’s Current Report on Form 8-K filed May 30, 1997 and incorporated by reference herein]

3.01	X		Copy of Restated Articles of Incorporation of LG&E, dated November 6, 1996. [Filed as Exhibit 3.06 to LG&E Quarterly Report on Form 10-Q for the quarter ended September 30, 1996, and incorporated by reference herein]

3.02	X		Copy of Amendment to Articles of Incorporation of LG&E, dated February 6, 2004.

144

Exhibit No.	Applicable to Form 10-K of
Exhibit No.	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
Exhibit No.	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
Exhibit No.	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
Exhibit No.	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
Exhibit No.	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
Exhibit No.	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
Exhibit No.	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
Exhibit No.	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
Exhibit No.	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
Exhibit No.	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
Exhibit No.	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
Exhibit No.	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
Exhibit No.	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
Exhibit No.	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.

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

	KENTUCKY UTILITIES COMPANY
	Registrant

March 29, 2004	/s/ S. Bradford Rives
(Date)	S. Bradford Rives
	Chief Financial Officer

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