10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C.  20549

FORM 10-K

(Mark One)

ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
For the fiscal year ended December 31, 2004
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.  ý

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, 2004, 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 28, 2005, 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 registrant.

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
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, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6.	Selected Financial Data
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
		Louisville Gas and Electric Company
		Kentucky Utilities Company
Item 7A.	Quantitative and Qualitative Disclosures 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
Item 9B.	Other Information
PART III
Item 10.	Directors and Executive Officers of the Registrant (a)
Item 11.	Executive Compensation. (a)
Item 12.	Security Ownership of Certain Beneficial Owners and Management and related Stockholder Matters (a)
Item 13.	Certain Relationships and Related Transactions (a)
Item 14.	Principal Accountant Fees and Services
PART IV
Item 15.	Exhibits and Financial Statement Schedules
Signatures

(a) Incorporate by reference

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INDEX OF ABBREVIATIONS

AFUDC	Allowance for Funds Used During Construction
ARO	Asset Retirement Obligation
Capital Corp.	LG&E Capital Corp.
Clean Air Act	The Clean Air Act, as amended in 1990
CCN	Certificate of Public Convenience and Necessity
CO2	Carbon Dioxide
CT	Combustion Turbines
CWIP	Construction Work in Progress
DSM	Demand Side Management
ECAR	East Central Area Reliability Region
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
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
IRP	Integrated Resource Plan
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.
LNG	Liquefied Natural Gas
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
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)

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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 Executive Retirement Plan
SFAS	Statement of Financial Accounting Standards
SIP	State Implementation Plan
SMD	Standard Market Design
SO2	Sulfur Dioxide
Texas Gas	Texas Gas Transmission LLC
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
WNA	Weather Normalization Adjustment

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PART I

Item 1.  Business.

LG&E and KU are each subsidiaries of LG&E Energy.  LG&E Energy is a subsidiary of E.ON AG, a German corporation.  E.ON acquired LG&E Energy through its July 1, 2002 acquisition of Powergen plc, now Powergen Limited, a United Kingdom company.  LG&E and KU are now indirect subsidiaries of E.ON.  As a result of these acquisitions and otherwise, E.ON and LG&E Energy are registered as holding companies under PUHCA.

In order to comply with PUHCA, LG&E Services was formed as a subsidiary of LG&E Energy.  LG&E Services provides certain services to affiliated entities, including LG&E and KU, at cost as required under PUHCA.  Approximately 1,000 employees, mainly from LG&E Energy, LG&E and KU, were moved to LG&E Services upon its formation.

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.  E.ON’s general financing approval order under PUHCA (including certain LG&E and KU components) expires in May 2005 and an application has been submitted to the SEC for renewed or modified financing authorizations for an additional three year period.  LG&E and KU anticipate receiving a timely approval from the SEC, but such approval cannot be assured.

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 as LG&E and KU.  The preferred stock and debt securities of LG&E and KU were not affected by these transactions.

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

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LOUISVILLE GAS AND ELECTRIC COMPANY

General

LG&E, incorporated in 1913 in Kentucky, is a regulated public utility that supplies natural gas to approximately 318,000 customers and electricity to approximately 390,000 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 does not provide any distribution services.  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.

For the year ended December 31, 2004, 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	$	240,779		$	222,574	$	463,353		48	%
Commercial	202,025			88,774		290,799			30	%
Industrial	119,758			15,277		135,035			14	%
Public authorities	62,266			15,533		77,799			8	%
Total retail	624,828			342,158		966,986			100	%
Wholesale sales	185,563			7,195		192,758
Gas transported – net	—			6,140		6,140
Provision for rate collections	(11,418		)	—		(11,418		)
Miscellaneous	16,724			1,578		18,302
Total	$	815,697		$	357,071	$	1,172,768

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, 2004.

Electric Operations

The sources of LG&E’s electric operating revenues and the volumes of sales for the three years ended December 31, 2004, were as follows:

(in thousands)	2004			2003			2002
ELECTRIC OPERATING REVENUES
Residential	$	240,779		$	223,404		$	232,527
Commercial	202,025			187,500			185,306
Industrial	119,758			111,535			111,988
Public authorities	62,266			58,493			57,762
Total retail	624,828			580,932			587,583
Wholesale sales	185,563			169,782			120,552
Provision for rate collections (refunds)	(11,418		)	(412		)	11,656
Miscellaneous	16,724			17,886			16,251
Total	$	815,697		$	768,188		$	736,042

(Thousands of Mwh)
ELECTRIC SALES
Residential	3,923	3,835	4,036
Commercial	3,534	3,482	3,493
Industrial	3,019	2,936	3,028
Public authorities	1,248	1,251	1,253
Total retail	11,724	11,504	11,810
Wholesale sales	7,819	7,678	6,387
Total	19,543	19,182	18,197

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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 2004 was approximately 0.56 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 2,485 Mw on July 13, 2004, when the temperature reached 88 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, 2004, LG&E owned steam and combustion turbine generating facilities with a net summer capability of 3,105 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, 2004, LG&E’s system net summer capability, including purchases from others and excluding the hydroelectric facility, was 3,260 Mw.  See Item 2, Properties.

LG&E and 11 other electric utilities are participating owners of OVEC located in Piketon, Ohio.

In March 2005, LG&E purchased from American Electric Power Company Inc. (“AEP”) an additional 0.73% interest in OVEC for a purchase price of approximately $0.1 million, which resulted in an increase in LG&E ownership in OVEC from 4.9% to 5.63%.  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 is a member of the MISO and therefore has turned over operational control of transmission facilities  100 kV and above, but continues 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 lines over 1.1 million square miles located in the northern Midwest between Manitoba, Canada and Kentucky.  As a transmission-owning member of the MISO, LG&E also incurs costs under the MISO Open Access Transmission Tariff, including the Schedule 10 adder which recovers the operational and capital costs incurred by the MISO.  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.

Gas Operations

The sources of LG&E’s gas operating revenues and the volumes of sales for the three years ended December 31, 2004, were as follows:

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(in thousands)	2004		2003		2002
GAS OPERATING REVENUES
Residential	$	222,574	$	198,881	$	160,733
Commercial	88,774		78,280		61,036
Industrial	15,277		13,812		10,232
Public authorities	15,533		13,745		11,197
Total retail	342,158		304,718		243,198
Wholesale sales	7,195		12,278		16,384
Gas transported – net	6,140		6,046		6,232
Miscellaneous	1,578		2,291		1,879
Total	$	357,071	$	325,333	$	267,693

(Millions of cu. ft.)
GAS SALES
Residential	21,402	23,192	22,124
Commercial	9,144	9,652	9,074
Industrial	1,736	1,880	1,783
Public authorities	1,646	1,746	1,747
Total retail	33,928	36,470	34,728
Wholesale sales	1,221	2,119	5,345
Gas transported	13,692	13,683	13,939
Total	48,841	52,272	54,012

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 WNA mechanism.  The WNA mechanism adjusts the distribution cost recovery component of the natural gas billings of residential and commercial customers to normal temperatures during the heating season months of November through April, somewhat mitigating the effect of weather extremes.  LG&E requested, and the Kentucky Commission 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, 2004, LG&E had an inventory balance of gas stored underground of approximately 12.2 million Mcf of working gas valued at approximately $77.5 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.

During 2004, the maximum day gas sendout was approximately 491,000 Mcf, occurring on January 30, 2004, when the average temperature for the day was 7 degrees F.  Supply on that day consisted of approximately 235,000 Mcf from purchases, approximately 180,000 Mcf delivered from underground storage, and approximately 76,000 Mcf transported for industrial customers.  For a further discussion, see Gas Supply under Item 1.

Rates and Regulation

As a subsidiary of a registered holding company under PUHCA, LG&E is 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

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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.  E.ON’s general financing approval order under PUHCA (including certain LG&E components) expires in May 2005 and an application has been submitted to the SEC for renewed or modified financing authorizations for an additional three year period.  LG&E anticipates receiving a timely approval from the SEC, but such approval cannot be assured.

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 a 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.

Prior to 2004, LG&E’s retail electric rates were subject to an ESM.  LG&E and the Kentucky Commission agreed to a termination of the ESM relating to all periods after 2003.  The ESM, initially in place for three years beginning in 2000, set an upper and lower point for rate of return on equity, whereby if LG&E’s rate of return for the calendar year fell within the range of 10.5% to 12.5%, no action was necessary.  If earnings were above the upper limit, the excess earnings were shared 40% with ratepayers and 60% with shareholders; if earnings were below the lower limit, the earnings deficiency was recovered 40% from ratepayers and 60% from shareholders.  By order of the Kentucky Commission, rate changes prompted by the ESM filing went into effect in April of each year subject to a balancing adjustment in successive periods.  For discussion of current ESM matters, see Rates and Regulation for LG&E under Item 7 and Note 3 of LG&E’s Notes to Financial Statements under Item 8.

LG&E’s 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 Rates and Regulation for LG&E under Item 7 and Note 3 of LG&E’s Notes to Financial Statements under Item 8.

LG&E’s 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,

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capacity margins and demand-side management techniques.  LG&E filed its most recent 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.  In June 2004, the Kentucky Commission issued an order approving increases in LG&E’s annual electric base rates of approximately $43.4 million (7.7%) and annual gas base rates of approximately $11.9 million (3.4%). The rate increases took effect on July 1, 2004.

During July 2004, the Attorney General of Kentucky (“AG”) served subpoenas on LG&E, as well as on the Kentucky Commission and its staff, requesting information regarding allegedly improper communications between LG&E and the Kentucky Commission, particularly during the period covered by the rate case.  The Kentucky Commission has procedurally reopened the rate cases for the limited purpose of taking evidence, if any, as to the communication issues.

LG&E believes no improprieties have occurred in its communications with the Kentucky Commission and is cooperating with the proceedings before the AG and the Kentucky Commission.  LG&E is currently unable to determine the ultimate impact, if any, of, or any possible future actions of the AG or the Kentucky Commission arising out of, the AG’s report and investigation, including whether there will be further actions to appeal, review or otherwise challenge the granted increases in base rates.

For a further discussion of 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, 2004, 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 25% of total utility plant at December 31, 2004, and consisted of $821 million for electric properties and $156 million for gas properties.  Gross retirements during the same period were $126 million, consisting of $92 million for electric properties and $34 million for gas properties.

Capital expenditures during the five years ending December 31, 2009 are estimated to be approximately $843 million.  The major expenditures during this period relate to the development and construction of Trimble County Unit 2, of which LG&E’s portion totals $158 million, contingent upon approval of the Company’s application for a CCN by the Kentucky Commission, and the redevelopment of the Ohio Falls hydro facility ($46 million).

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Coal Supply

Coal-fired generating units provided over 98.2% of LG&E’s net kilowatt-hour generation for 2004.  The remaining net generation for 2004 was provided by natural gas and oil-fueled combustion turbine peaking units (0.5%) and a hydroelectric plant (1.3%).  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 production issues and other supplier or transporter operating difficulties.

LG&E has entered into coal supply agreements with various suppliers for coal deliveries for 2005 and beyond.  The Company normally augments its coal supply agreements with spot market purchases.  LG&E has a coal inventory policy which it believes provides adequate protection under most contingencies.  It had a coal inventory of approximately 0.7 million tons, or a36-day supply, on hand at December 31, 2004.

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:

	2004			2003			2002
Per ton	$	26.25		$	25.56		$	25.30
Per MMBtu	$	1.15		$	1.12		$	1.11
Spot purchases as % of all sources	7		%	1		%	2		%

The delivered cost of coal is expected to increase in 2005 due to market conditions.

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 the regulated interstate natural gas pipelines that provide service to LG&E. Although both Texas Gas and Tennessee Gas have several active proceedings in which LG&E is participating at the FERC, neither interstate natural gas pipeline has filed an application 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 NNS and FT service.  During the winter

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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.  LG&E has provided Texas Gas with notice to terminate a portion of the summer-only FT agreement in the amount of 18,000 MMBtu/day effective November 1, 2005.  After that date, LG&E will have FT service during the summer in the amount of 36,000 MMBtu/day.  For January 2005 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 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 $7.18 in 2004, $6.30 in 2003, and $4.19 in 2002.  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 2004, expenditures for pollution control facilities represented $247 million or 25% of total construction expenditures.  LG&E estimates that construction expenditures for environmental protection equipment from 2005 through 2009 will be approximately $56 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.  LG&E will take additional steps to better position itself should retail competition come to Kentucky.

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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.  Some states that have already deregulated have begun discussions that could lead to re-regulation.

In February 2005, Kentucky’s Governor signed an executive order directing the Kentucky Commission, in conjunction with the Commerce Cabinet and the Environmental and Public Protection Cabinet, to ‘develop a Strategic Blueprint for the continued use and development of electric energy.’ This Strategic Blueprint will be designed to promote future investment in electric infrastructure for the Commonwealth of Kentucky, to protect Kentucky’s low-cost electric advantage, to maintain affordable rates for all Kentuckians, and to preserve Kentucky’s commitment to environmental protection.”  In March 2005, the Kentucky Commission established Administrative Case No. 2005-00090 to collect information from all jurisdictional utilities in Kentucky, including LG&E, pertaining to Kentucky electric generation, transmission and distribution systems.  The KPSC must provide its Strategic Blueprint to the Governor in early August 2005.  LG&E must respond to the Kentucky Commission’s first set of data requests by the end of March 2005.

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KENTUCKY UTILITIES COMPANY

General

KU, incorporated in Kentucky in 1912 and incorporated in Virginia in 1991, is a regulated public utility engaged in producing, transmitting and selling electric energy.  KU provides electric service to approximately 488,000 customers in over 600 communities and adjacent suburban and rural areas in 77 counties in central, southeastern and western Kentucky, to approximately 30,000 customers in 5counties in southwestern Virginia and to less than 10 customers in Tennessee.  In Virginia, KU operates under the name Old Dominion Power Company.  KU operates under appropriate franchises in substantially all of the 160 Kentucky incorporated municipalities served.  No franchises are required in unincorporated Kentucky or Virginia communities.  The lack of franchises is not expected to have a material adverse effect on KU’s operations.  KU also sells wholesale electric energy to 12 municipalities.

Electric Operations

The sources of KU’s electric operating revenues and the volumes of sales for the three years ended December 31, 2004, were as follows:

(in thousands)	2004		2003			2002
ELECTRIC OPERATING REVENUES
Residential	$	303,635	$	278,461		$	274,660
Commercial	206,931		189,113			178,694
Industrial	190,560		175,601			163,372
Mine power	31,703		29,584			28,664
Public authorities	72,158		66,452			62,490
Total retail	804,987		739,211			707,880
Wholesale sales	160,002		138,003			117,252
Provision for rate collections (refunds)	4,751		(8,534		)	15,481
Miscellaneous	25,622		23,098			21,051
Total	$	995,362	$	891,778		$	861,664

(Thousands of Mwh)
ELECTRIC SALES
Residential	6,160	6,001	6,198
Commercial	4,323	4,210	4,161
Industrial	5,400	5,110	4,975
Mine power	732	722	766
Public authorities	1,597	1,551	1,533
Total retail	18,212	17,594	17,633
Wholesale sales	5,707	5,591	4,794
Total	23,919	23,185	22,427

KU’s weighted-average system-wide emission rate for sulfur dioxide in 2004 was approximately1.4lbs./MMBtuof heat input, with every generating unit below its emission limit established by the Kentucky Division for Air Quality.

KU set an annual peak load of 3,768 Mw on January 7, 2004, when the temperature was 13 degrees F.  On January 18, 2005, KU achieved the highest hourly customer demand in KU’s history, with a peak load of 4,065 Mw.

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

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under Item 7.

KU currently maintains a 13% -15% reserve margin range.  At December 31, 2004, KU owned steam and combustion turbine generating facilities with a net summer capability of 4,433 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, 2004, KU’s system net summer capability, including purchases from others and excluding the hydroelectric facility, was 4,934 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 9% of KU’s net generation system output during 2004.  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 generated by KU.  This contract governing the purchases from EEI will terminate on December 31, 2005.  Such power equated to approximately 10% of KU’s net generation system output in 2004.  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 is a member of the MISO and therefore has turned over operational control of transmission facilities 100 kV and above, but continues 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.  As a transmission-owning member of the MISO, KU also incurs costs under the MISO Open Access Transmission Tariff, including the Schedule 10 adder which recovers the operational and capital costs incurred by the MISO.  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.

Rates and Regulation

As a subsidiary of a registered holding company under PUHCA, KU is 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.  E.ON’s general financing approval order under PUHCA (including certain KU components) expires in May 2005 and an application has been submitted to the SEC for renewed or modified financing authorizations for an additional three year period.  KU anticipates receiving a timely approval from the SEC, but such approval cannot be assured.

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

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electric utility property in one county in Tennessee (having a gross book value of approximately $0.3 million) from which KU served 5 customers at December 31, 2004, KU is subject to the jurisdiction of the Tennessee Regulatory Authority.  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 a 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.

Prior to 2004, KU’s Kentucky retail electric rates were subject to an ESM.  KU and the Kentucky Commission agreed to a termination of the ESM relating to all periods after 2003.  The ESM, initially in place for three years beginning in 2000, set an upper and lower point for rate of return on equity, whereby if KU’s rate of return for the calendar year fell within the range of 10.5% to 12.5%, no action was necessary.  If earnings were above the upper limit, the excess earnings were shared 40% with ratepayers and 60% with shareholders; if earnings were below the lower limit, the earnings deficiency was recovered 40% from ratepayers and 60% from shareholders.  By order of the Kentucky Commission, rate changes prompted by the ESM filing went into effect in April of each year subject to a balancing adjustment in successive periods.  There is no ESM for Virginia retail electric rates.  For discussion of current ESM matters, see Rates and Regulation for KU under Item 7 and Note 3 of KU’s Notes to Financial Statements under Item 8.

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 Rates and Regulation for KU under Item 7 and 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 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 gave Virginia customers the ability to choose their electric supplier.  Rates are capped at current levels through December 2010.  The Virginia Commission will continue to require each Virginia utility to make annual filings of either a base rate change or an Annual Informational Filing consisting of a set of standard financial schedules.  The Virginia Staff will issue a Staff Report regarding the individual utility’s financial performance during the historic 12-month period.  The Staff Report can lead to an adjustment in rates, but through December 2010 rates are subject to the capped rate period and essentially “frozen”.  However, KU may petition the

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Virginia Commission for a one-time adjustment in rates during the capped rate period.  Effective July 1, 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 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.  In June 2004, the Kentucky Commission issued an order approving an increase in KU’s annual electric base rates of approximately $46.1 million (6.8%). The rate increase took effect on July 1, 2004.

During July 2004, the AG served subpoenas on KU, as well as on the Kentucky Commission and its staff, requesting information regarding allegedly improper communications between KU and the Kentucky Commission, particularly during the period covered by the rate case.  The Kentucky Commission has procedurally reopened the rate cases for the limited purpose of taking evidence, if any, as to the communication issues.

KU believes no improprieties have occurred in its communications with the Kentucky Commission and is cooperating with the proceedings before the AG and the Kentucky Commission.  KU is currently unable to determine the ultimate impact, if any, of, or any possible future actions of the AG or the Kentucky Commission arising out of, the AG’s report and investigation, including whether there will be further actions to appeal, review or otherwise challenge the granted increases in base rates.

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

Construction Program and Financing

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

During the five years ended December 31, 2004, 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 26% of total utility plant at December 31, 2004.  Gross retirements during the same period were $114 million.

Capital expenditures during the five years ending December 31, 2009 are estimated to be approximately $1.9 billion.  The major expenditures during this period relate to the development and construction of Trimble County Unit 2, of which KU’s portion totals approximately $672 million, and the installation of FGDs on Ghent and Brown units, totaling approximately $678 million.  Expenditures for Trimble County Unit 2 and the FGDs are contingent upon approval of the Company’s application for CCNs by the Kentucky Commission.

Coal Supply

Coal-fired generating units provided over 98.7% of KU’s net kilowatt-hour generation for 2004.  The remaining net generation for 2004 was provided by natural gas and oil-fueled combustion turbine peaking units (0.7%) and

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hydroelectric plants (0.6%).  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 production issues and other supplier or transporter operating difficulties.

KU has entered into coal supply agreements with various suppliers for coal deliveries for 2005 and beyond.  The Company normally augments its coal supply agreements with spot market purchases.  KU has a coal inventory policy which it believes provides adequate protection under most contingencies.  It had a coal inventory of approximately 1.0 million tons, or a 49-day supply, on hand at December 31, 2004.

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 and truck.

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

	2004			2003			2002
Per ton	$	37.69		$	34.57		$	31.44
Per MMBtu	$	1.56		$	1.47		$	1.35
Spot purchases as % of all sources	14		%	11		%	18		%

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 for 2005 is expected to increase due to market conditions.

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 2004, expenditures for pollution control facilities represented $246 million or 25% of total construction expenditures.  KU estimates that construction expenditures for environmental control equipment from 2005 through 2009, primarily related to the installation of FGDs on three Ghent units, will be approximately $719 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

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continuous modifications of its organizational structure.  KU will take additional steps to better position itself should retail competition come to Kentucky.

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.  Some states that have already deregulated have begun discussions that could lead to re-regulation.

In February 2005, Kentucky’s Governor signed an executive order directing the Kentucky Commission, in conjunction with the Commerce Cabinet and the Environmental and Public Protection Cabinet, to ‘develop a Strategic Blueprint for the continued use and development of electric energy.’ This Strategic Blueprint will be designed to promote future investment in electric infrastructure for the Commonwealth of Kentucky, to protect Kentucky’s low-cost electric advantage, to maintain affordable rates for all Kentuckians, and to preserve Kentucky’s commitment to environmental protection.  In March 2005, the Kentucky Commission established Administrative Case No. 2005-00090 to collect information from all jurisdictional utilities in Kentucky, including KU, pertaining to Kentucky electric generation, transmission and distribution systems.  The KPSC must provide its Strategic Blueprint to the Governor in early August 2005.  KU must respond to the Kentucky Commission’s first set of data requests by the end of March 2005.

Virginia has enacted a phase-in of customer choice through the Virginia Electric Restructuring Act.  The Virginia Commission is promulgating regulations to govern the various activities required by the Act.  Effective July 1, 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 customers in KU’s other service territories.

EMPLOYEES AND LABOR RELATIONS

LG&E had approximately 887 full-time regular employees and KU had approximately 934 full-time regular employees at February 28, 2005. Of the LG&E total, 643 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, approximately 158 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.

LG&E Services provides certain services to affiliated entities, including LG&E and KU, at cost as required under PUHCA.  On February 28, 2005 approximately 965 employees worked for LG&E Services.

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

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Executive Officers of LG&E and KU at February 28, 2005:

Name	Age	Position	Effective Date of Election to Present Position
Victor A. Staffieri	49	Chairman of the Board, President and Chief Executive Officer	May 1, 2001
John R. McCall	61	Executive Vice President, General Counsel and Corporate Secretary	July 1, 1994
S. Bradford Rives	46	Chief Financial Officer	September 15, 2003
Paul W. Thompson	48	Senior Vice President - Energy Services	June 7, 2000
Chris Hermann	57	Senior Vice President - Energy Delivery	February 14, 2003
Wendy C. Welsh	51	Senior Vice President - Information Technology	December 11, 2000
Martyn Gallus	40	Senior Vice President - Energy Marketing	December 11, 2000

Other Officers of LG&E and KU at February 28, 2005:

David A. Vogel	39	Vice President - Retail and Gas Storage Operations	March 1, 2003
Daniel K. Arbough	43	Treasurer	December 11, 2000
Michael S. Beer	46	Vice President Federal Regulation and Policy	September 27, 2004
George R. Siemens	55	Vice President - External Affairs	January 11, 2001
Paula H. Pottinger	48	Vice President - Human Resources	June 1, 2002
D. Ralph Bowling	47	Vice President - Power Operations WKE	August 1, 2002
R. W. Chip Keeling	48	Vice President - Communications	March 18, 2002
John N. Voyles, Jr.	50	Vice President - Regulated Generation	June 16, 2003
Valerie L. Scott	48	Controller	January 1, 2005

The present term of office of each of the above executive and other officers extends to the meeting of the Board of Directors following the 2005 Annual Meeting of Shareholders.

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There are no family relationships between or among executive and other officers of LG&E and KU.  The above tables indicate officers serving as executive officers of both LG&E and KU at February 28, 2005.  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 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 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, 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 - Information Technology from February 1998 to December 2000.

Before he was elected to his current positions, Mr. Gallus was Vice President, Energy Marketing from August 1998 to December 2000 for LG&E Energy.

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.

In addition to being elected to his current positions, Mr. Arbough has held the positions 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. Beer was Senior Corporate Attorney from February 1998 to February 2000; Senior Counsel Specialist, Regulatory from February 2000 to February 2001, and Vice President – Rates and Regulatory from February 2001 to September 2004.

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 positions, Ms. Pottinger was Manager, Human Resources Development

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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, Cane Run, Ohio Falls and Combustion Turbines, November 1998 to February 2003; and Director, Generation Services, February 2003 to June 2003.

Before she was elected to her current positions, Ms. Scott was Director, Trading Controls and Energy Marketing Accounting from February 1999 to September 2002, and Director, Financial Planning and Accounting – Utility Operations from September 2002 to December 2004.

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ITEM 2.  Properties.

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

	Summer Capability Rating (Kw)
Steam Stations:
Mill Creek - Kosmosdale, KY
Unit 1	303,000
Unit 2	301,000
Unit 3	391,000
Unit 4	477,000
Total Mill Creek	1,472,000
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	383,000
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)	328,000
Total combustion turbine generators	687,000
Total capability rating	3,105,000

(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 Paddy’s Run Units 11 and 12.  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, 38% interest in Units 6 and 7 at E.W. Brown and 10% of the Inlet Air Cooling system, attributable to Brown Unit 5.  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 and LG&E’s 37% interest in Units 7, 8, 9 and 10 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 (Ohio Falls), with an expected summer capability rating of 48 Mw, operated under a license issued by the FERC.

At December 31, 2004, 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 11,878,000 Kva and approximately 670 structure miles of lines.  The electric distribution system

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included 93 substations (20 of which are shared by the transmission system) with a total capacity of approximately 4,860,500 Kva, 3,923 structure miles of overhead lines and 1,859 miles of underground conduit.

LG&E’s gas transmission system includes 255 miles of transmission mains, and the gas distribution system includes 4,026 miles of distribution mains.

LG&E operates underground gas storage facilities with a current working gas capacity of approximately15.1million Mcf.See Gas Supply under Item 1.

In 1990, LG&E entered into an operating lease for its corporate office building located in downtown Louisville, Kentucky.  The lease was renegotiated in 2002 and is scheduled to expire July 31, 2015.

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

The trust indenture securing LG&E’s first mortgage bonds constitutes a direct first mortgage lien upon much of the property owned by LG&E.  In addition, Fidelia Corporation, a financing subsidiary 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	475,000
Unit 2	484,000
Unit 3	493,000
Unit 4	493,000
Total Ghent	1,945,000
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)	632,000
Total combustion turbine generators	1,499,000
Total capability rating	4,433,000

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(a)Amount shown represents KU’s 47% interest in Unit 5, 62% interest in Units 6 and 7, 100% of units 8-11 at E.W. Brown and 90% of the Inlet Air Cooling system, attributable to E.W. Brown CT Unit 5 and Units 8 to 11.  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 and KU’s 63% interest in Units 7, 8, 9 and 10 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 nameplate-rated hydroelectric generating station located in Burgin, Kentucky (Dix Dam), with an expected summer capability rating of 24 Mw, operated under a license issued by the FERC.

At December 31, 2004, KU’s electric transmission system included 108 substations with a total capacity of approximately 16,978,000 Kva and approximately 4,239 structure miles of lines.  The electric distribution system included 491 substations with a total capacity of approximately 6,220,400 Kva and 15,182 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 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, the Kentucky attorney general investigation, ESM proceedings, FERC or MISO proceedings, and other rate or regulatory matters affecting LG&E and KU, see Rates and Regulation for LG&E and KU under Item 1 and 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 SO₂ and 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 Executive Summary  (Environmental Pressures) and Rates and Regulations for LG&E and KU (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.

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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 eight 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.

Owensboro Contract Litigation

In May 2004, the City of Owensboro, Kentucky and Owensboro Municipal Utilities (collectively “OMU”), filed suit in Davies County, Kentucky District Court against KU concerning a long-term power supply contract (the “OMU Agreement”) with KU.  The dispute involves interpretational differences regarding certain issues under the OMU Agreement, including various payments or charges between KU and OMU and rights concerning excess power, termination and emissions allowances, respectively.  The complaint seeks approximately $6 million in damages for historical periods, as well as injunctive and other relief, including a declaration that KU is in material breach.  KU has removed this litigation to the U.S. District Court for the Western District of Kentucky, filed an answer in that court denying the OMU claims and presenting certain counterclaims and commenced a FERC proceeding to request FERC jurisdiction on certain issues.  In October 2004, FERC declined to exercise exclusive jurisdiction regarding the issues in dispute, which ruling KU has appealed.  In December 2004, KU filed in federal court for summary judgment on certain issues.

OVEC Power Agreement and Share Purchase

On April 30, 2004, OVEC and its shareholders, including LG&E and KU, entered into an Amended and Restated Inter-Company Power Agreement, to be effective beginning March 2006, upon the expiration of the current power contract among the parties.  Under the new contract, which has a 20-year term from its effective date, LG&E and KU have purchase rights for 5.63% and 2.5%, respectively, of OVEC power at marginal cost-based rates.  LG&E and KU are entitled to 7% and 2.5% of OVEC power, respectively, under the current contract.  In addition, LG&E has purchased from AEP an additional 0.73% interest in OVEC for a purchase price of approximately $0.1 million, resulting in an increase in LG&E ownership in OVEC from 4.9% to 5.63%.  The parties received SEC approval under PUHCA of the Amended and Restated Inter-Company Power Agreement during February 2005 and completed the share purchase transaction during March 2005.

Other

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

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

None.

PART II.

ITEM 5.  Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

LG&E:

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

The following table sets forth LG&E’s cash distributions on common stock paid to LG&E Energy during 2004.

(in thousands)
First quarter	$	—
Second quarter	21,000
Third quarter	21,000
Fourth quarter	15,000

LG&E had no cash distributions on common stock paid to LG&E Energy in 2003. In 2002, LG&E paid $69 million in cash distribution on common stock to LG&E Energy.

KU:

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

The following table sets forth KU’s cash distributions on common stock paid to LG&E Energy during 2004.

(in thousands)
First quarter	$	—
Second quarter	21,000
Third quarter	21,000
Fourth quarter	21,000

KU paid no cash distributions on common stock to LG&E Energy in 2003 or 2002.

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ITEM 6.  Selected Financial Data.

The 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 and the reclassification of income taxes.  Arthur Andersen LLP has ceased operations.  The amounts shown below for such period, reclassified pursuant to the adoption of EITF 02-03 and reclassified due to the change in presentation of income taxes, are unaudited.

	Years Ended December 31
(in thousands)	2004		2003		2002		2001		2000
LG&E:
Operating revenues	$	1,172,768	$	1,093,521	$	1,003,735	$	964,547	$	931,704
Net operating income	$	185,031	$	178,752	$	172,949	$	205,225	$	213,295
Net income	$	95,618	$	90,839	$	88,929	$	106,781	$	110,573
Total assets	$	2,966,552	$	2,882,082	$	2,768,930	$	2,448,354	$	2,226,084
Long-term obligations (including amounts due within one year)	$	871,804	$	798,054	$	616,904	$	616,904	$	606,800
Dividends declared per common share	$	2.68	$	—	$	3.24	$	1.08	$	2.35

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)	2004		2003		2002		2001		2000
KU:
Operating revenues	$	995,362	$	891,778	$	861,664	$	820,721	$	793,409
Net operating income	$	227,847	$	162,210	$	162,675	$	178,852	$	180,099
Net income	$	133,471	$	91,402	$	93,384	$	96,414	$	95,524
Total assets	$	2,610,439	$	2,505,094	$	2,251,638	$	1,826,902	$	1,739,518
Long-term obligations (including amounts due within one year)	$	726,211	$	687,576	$	500,492	$	488,506	$	484,830
Dividends declared per common share	$	1.67	$	—	$	—	$	0.81	$	2.00

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

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

GENERAL

The following discussion and analysis by management focuses on those factors that had a material effect on LG&E and KU’s financial results of operations and financial condition during 2004, 2003, and 2002 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

Our Business

LG&E and KU are each subsidiaries of LG&E Energy LLC, which is an indirect subsidiary of E.ON, a German company.  LG&E and KU maintain separate corporate identities and serve customers in Kentucky, Virginia and Tennessee under their respective names.

LG&E, incorporated in 1913 in Kentucky, is a regulated public utility that supplies natural gas to approximately 318,000 customers and electricity to approximately 390,000 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.  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.

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 488,000 customers in over 600 communities and adjacent suburban and rural areas in 77 counties in central, southeastern and western Kentucky, to approximately 30,000 customers in 5counties in southwestern Virginia and to less than 10 customers in Tennessee.  In Virginia, KU operates under the name Old Dominion Power Company.  KU also sells wholesale electric energy to 12 municipalities.

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Our Customers

The following table provides statistics regarding LG&E and KU retail customers:

	LG&E				KU		2004 % Retail Revenues
Customers (000s)	Electric		Gas		Electric		LG&E				KU
	2004	2003	2004	2003	2004	2003	Electric		Gas		Electric
Retail Customer Data
Residential	343	337	293	287	426	421	39	%	65	%	38	%
Industrial & Commercial	41	41	24	24	82	82	51	%	30	%	53	%
Other	6	6	1	1	10	9	10	%	5	%	9	%
Total Retail	390	384	318	312	518	512	100	%	100	%	100	%

Our Mission

The mission of LG&E and KU is to build on our tradition and achieve world-class status providing reliable, low-cost energy services and superior customer satisfaction; and to promote safety, financial success and quality of life for our employees, communities and other stakeholders.

Our Strategy

LG&E and KU’s strategy focuses on the following:

•Execute all our business processes to secure a world-class competitive advantage

•Develop and transfer best practices in generation, customer service, distribution and supply

•Operate our commercial hub to enhance margins and manage risks across the company

•Pursue flexible asset portfolio management

•Attract, retain and develop the best people

Low Rates

LG&E and KU believe they are well positioned in the regulated Kentucky market. LG&E and KU continue to sustain high customer satisfaction, ranking top amongst large electric utilities in the Midwest for the 5^th time in six years in the J.D. Power and Associates 2004 survey of residential electric customers.  This excellent performance is balanced with cost control.  The customer benefits of the LG&E and KU culture of cost management are evident in rate comparisons among U.S. utilities.  The following chart compares the total residential average rates per thousand Kwh of U.S. investor-owned utilities as of July 1, 2004:

Source: Edison Electric Institute, Summer 2004 Typical Bills and Average Rates Report; Residential rates in effect July 1, 2004, based on 1,000 Kwh monthly usage.

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The company must continue to address new cost pressures. The Kentucky Commission accepted the settlement agreements reached by the majority of the parties in the rate cases filed by LG&E and KU in December 2003.  New rates, implemented in July 2004, produce $55.3 million of revenue for LG&E and $46.1 million of revenue for KU for a full year.  Under the ruling, the LG&E utility base electric rates have increased $43.4 million (7.7%) and base gas rates have increased $11.9 million (3.4%), on an annual basis.  Base electric rates at KU have increased $46.1 million (6.8%) annually.  The 2004 increases were the first increases in electric base rates for LG&E and KU in 13 and 20 years, respectively; the last gas rate increase for the LG&E gas utility took effect in September 2000. Competitors also face these same cost pressures that caused LG&E and KU to initiate rate cases (e.g. pensions, benefits, and reliability expenditures) and many other utility companies already have rate cases in process.  Despite these increases, LG&E and KU rates remain significantly lower than the national average.

Commodity Prices: Fuel and Electricity

Wholesale natural gas prices stayed around the $6/MMBtu level during summer 2004.  The U.S. supply-demand imbalance problem has continued, with U.S. reserves in decline and gas demand for electric generation continuing to increase.

Coal prices, which moderated after increases in 2001-2002, rose in late 2003 and maintained strength during 2004.  Coal production in the U.S. has not kept pace with demand, and mining companies are exercising market discipline in their production decisions.  Lower sulfur Central Appalachian coal led the price increases.  Prices for Powder River Basin (“PRB”) low sulfur coal from the western U.S. have risen much less than eastern coals, largely due to transportation constraints between the mines and eastern markets.  However, LG&E and KU generation plants are limited in the amount of PRB coal that can be burned.

The graph displays the LG&E, KU and combined utility average utility gas and coal purchase prices.

Actual gas costs are recovered from customers through the GSC.  The GSC also contains an incentive component, the PBR component, which is determined for each 12-month period ending October 31.

Actual fuel costs associated with retail electric sales are recovered from customers through the FAC.  The Utilities’ base rates contain an embedded fuel cost component.  The FAC reconciles the difference between this fuel cost component and the actual fuel cost, including transportation costs.  Refunds to customers occur if the actual costs are below the embedded cost component.  Additional charges to customers occur if the actual costs exceed the embedded cost component.

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With respect to wholesale electricity prices, generation overcapacity in the Midwest is forecasted to persist, with reserve margins still topping 25% for ECAR in 2005. However, the overcapacity resulted largely from the construction of high-cost simple cycle gas-fired units.  Therefore, high gas prices have supported higher wholesale electricity prices, advantaging coal-fired generation.  While the regional reserve margin is expected to decline over time as new capacity construction slows and demand grows, gas-fired generation is expected to set prices, particularly during times of higher loads. This expectation, combined with the expectation that gas prices will remain high, indicates that on-peak electricity prices are expected to remain high.

Generation Reliability

Generation reliability also remains a key aspect to meeting our strategy. LG&E and KU believe that they have maintained good performance and reliability in the key area of utility generation operation.  While maintaining low cost levels, LG&E and KU have also been able to generate increasing volumes and expect to continue high levels of availability and low outage levels. This performance is also important to maintaining margins from off-system sales.

Generation Capacity

With the recent installation of four combustion turbines at Trimble County, near-term regulated load growth in Kentucky is expected to be satisfied. The installation of Trimble County Units 7-10 increased total system capability by 9%. However, the IRP submitted by LG&E and KU to the Kentucky Commission in 2002, outlining the least cost alternative to meet Kentucky’s needs, indicated the requirement for additional base-load capacity in the longer-term.   Consequently, LG&E and KU have begun development efforts for another base-load coal-fired unit at the Trimble County site. LG&E and KU believe this is the least cost alternative to meet the future needs of customers.  Trimble County Unit 2, with a 732 MW capacity rating, is expected to be jointly owned by LG&E and KU (75% owners of the unit) and IMEA and IMPA (25% owners).   An application for a construction CCN was filed with the Kentucky Commission in December 2004, and the proposed air permit was filed with the Kentucky Department of Air Quality in December 2004.  LG&E’s and KU’s share of the total capital cost of $885 million for Trimble County Unit 2 is estimated to be $168 million and $717 million, respectively, through 2010.

Environmental Pressures

In addition to the Trimble County Unit 2 project, the second major utility investment area is environmental expenditures.  The need for additional FGD units is continuously assessed based on the expected changes in SO₂ allowance prices, coal cost, and environmental legislation.  The analysis supports building additional FGD units to mitigate the declining SO₂ allowance bank at KU over the next several years.  The LG&E utility fleet is fully scrubbed.  SO₂ allowance prices have risen significantly and, coupled with the high price of low sulfur coal, indicate the need for FGDs on three of KU’s Ghent units and at E.W. Brown.  In December 2004, KU filed with the Kentucky Commission an application for a CCN to construct four FGDs; a decision is expected by late June 2005.

LG&E and KU completed the NOx SCR projects before the May 2004 deadline.  Expenditures on NOx investments, totaling approximately $186 million at LG&E and $219 million at KU, are being recovered currently through the companies’ ECR mechanism (see “Rates and Regulation”).

Additional environmental regulations are probable in the areas of New Source Review (a preconstruction permitting program established as part of the Clean Air Act), mercury and CO2. The mercury standard will most likely be achieved through the operation of conventional air pollution control equipment (FGDs). The

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Companies believe that CO2 regulation is a longer-term issue as there is no current nationwide consensus to adopt Kyoto-like restrictions.

Kentucky law permits LG&E and KU to recover the costs of complying with the Federal Clean Air Act, including a return of operating expenses, and a return of and on capital invested, through the ECR mechanism. The mechanism permits LG&E and KU to earn a reasonable return on these capital investments outside of base rates.  Related operation and maintenance expenses are also recoverable.  Approximately 80% of the applicable environmental costs, including investment and operating costs, are recoverable through ECR. The remaining 20%, attributable to off-system and FERC-jurisdictional sales, are not recoverable through the ECR, but can be included in the determination of base rate cases.

Weather

The utility business is affected by various weather patterns.  Seasonal weather patterns can cause extreme variability in load due to higher or lower temperatures than normal.  The Companies maintain generation reserve margins and natural gas storage fields to accommodate higher than normal loads.  Lower than normal loads can impact the profitability of the Companies due to lower revenues.  A WNA mechanism, effective November through April, adjusts for the over- and under-recovery of costs associated with natural gas in periods of abnormal winter usage.

Severe snow and ice storms, thunderstorms, tornadoes and flooding can result in extensive damage to the infrastructure of the Companies’ transmission and distribution systems.  The Companies maintain a comprehensive storm management plan for efficient and timely restoration of service to customers after major storm events.

Business Disruption Risks

LG&E and KU face certain operational risks common to the electric and gas utility industries, as applicable.  These include, without limitation, the risk of disruptions or outages relating to major operating or delivery facilities, such as generating units, transmission or distribution assets and information technology or data processing components, whether due to terrorist or other attack, civil unrest or labor action, break-down or mechanical failure, severe weather or other acts of God.

While LG&E and KU believe they have appropriate prevention or mitigation measures in place, where possible, with respect to these potential business disruptions, no assurances can be given that such events will not occur in the future or will not negatively affect the Companies’ financial condition or results of operations.

MERGERS AND ACQUISITIONS

LG&E and KU are each subsidiaries of LG&E Energy.  On December 11, 2000, LG&E Energy Corp., now LG&E Energy LLC, was acquired by Powergen plc, now known as Powergen Limited, for cash of approximately $3.2 billion and the assumption of all of LG&E Energy’s debt.  As a result of the acquisition, LG&E Energy became a wholly owned subsidiary of Powergen and, as a result, LG&E and KU became indirect subsidiaries of Powergen.

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.

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 of LG&E Energy have continued their separate identities as LG&E and KU.  The preferred stock and debt securities of LG&E and KU were not affected by these transactions.

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

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RESULTS OF OPERATIONS

LG&E

Net Income

LG&E’s net income in 2004 increased $4.8 million (5.3%) compared to 2003.  The increase resulted primarily from higher electric revenues due to increased base rates implemented for service rendered on and after July 1, 2004, following the electric rate case order and higher wholesale revenues, somewhat offset by higher maintenance expenses related to storm restoration costs.  Operating expenses for 2004 reflect $12.7 million in expenses related to severe May and July storms.

LG&E’s net income in 2004 related to the electric business increased $6.6 million (8.2%) compared to 2003.  Electric operating revenues increased $47.5 million (6.2%), offset by higher fuel for electric generation and power purchased of $22.6 million (8.2%).  Other electric operations and maintenance expenses increased $11.1 million (4.9%).  Electric depreciation expense increased $3.5 million (3.6%).  Interest expense increased $1.6 million (6.3%).

LG&E’s net income in 2004 related to the gas business decreased $1.9 million (18.2%) compared to 2003.  Gas operating revenues increased $31.7 million (9.8%) offset by higher gas supply expenses of $32.4 million (13.9%).  Other gas operations and maintenance expenses increased $2.0 million (4.2%).

LG&E’s net income in 2003 increased $1.9 million (2.1%) as compared to 2002.  The increase resulted primarily from increased electric sales.

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%).

Revenues

The following table presents a comparison of operating revenues for the years 2004 and 2003 with the immediately preceding year.

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	Increase (Decrease) From Prior Period
(in thousands)	Electric Revenues						Gas Revenues
Cause	2004			2003			2004			2003
Retail sales:
Fuel and gas supply adjustments	$	1,093		$	6,620		$	33,546		$	50,972
LG&E/KU Merger surcredit	(2,329		)	(2,288		)	—			—
Environmental cost recovery surcharge	12,747			(269		)	—			—
Earnings sharing mechanism	4,489			9,768			—			—
Demand side management	403			1,362			(555		)	267
VDT surcredit	(1,140		)	(3,394		)	87			(1,283		)
Weather normalization	—			—			3,188			(506		)
Rate changes	16,824			—			6,947			—
Variation in sales volumes and other	11,809			(18,451		)	(5,773		)	12,070
Provision for Rate Collections (Refunds)	(11,006		)	(12,067		)	—			—
Total retail sales	32,890			(18,719		)	37,440			61,520
Wholesale	15,781			49,230			(5,083		)	(4,106		)
Gas transportation-net	—			—			95			(186		)
Other	(1,162		)	1,635			(714		)	412
Total	$	47,509		$	32,146		$	31,738		$	57,640

Electric revenues increased in 2004 primarily due to new rates implemented in July 2004. Retail revenues increased 2.0% due to higher sales volume, primarily due to warmer summer weather than 2003.  Cooling degree days increased 21% compared to 2003 and were 2% higher than the 20-year average.  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.

Gas revenues in 2004 increased due to higher gas supply cost billed to customers through the gas supply clause and increased gas rates. New gas rates took effect in July 2004 increasing revenues by 2.3% in 2004. These increases were partially offset by lower retail sales due to warmer winter weather and lower wholesale sales.  Heating degree days decreased 8% as compared to 2003 and were 8% lower than the 20-year average. Gas revenues in 2003 increased compared to 2002, 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 off-system gas sales.  Heating degree days increased 5% as compared to 2002 and were the same as the 20-year average.

The decrease in the provision for rate collections (refunds) in 2004 from 2003 ($11.0 million) results primarily from a decrease in the ESM accrual ($12.7 million) and a decrease in 2004 ECR accruals ($5.4 million), partially offset by an increase in fuel accruals ($7.1 million). 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 fuel accruals ($2.6 million), partially offset by an increase in ECR accruals ($2.9 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 a FAC and gas rates contain a GSC, whereby increases or decreases in the cost of fuel and gas supply are reflected in the FAC and GSC factors, subject to approval by the Kentucky Commission, and passed through to LG&E’s retail customers.

Fuel for electric generation increased $10.1 million (5.1%) in 2004 due to increased generation ($3.7 million) and higher cost of fuel burned ($6.4 million).   Fuel for electric generation increased $2.1 million (1.1%) in

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2003 due to increased generation ($5.8 million) offset by lower cost of fuel burned ($3.7 million), primarily due to greater percentage of steam generation vs. combustion turbine generation in 2003.  The average delivered cost per MMBtu of coal purchased was $1.15 in 2004, $1.12 in 2003 and $1.11 in 2002.

Power purchased increased $12.4 million (15.6%) in 2004 due to a 4% increase in purchases to meet off-system sales requirements ($3.4 million), and an 11% higher unit cost of purchases ($9.0 million).   Power purchased expenses increased $17.7 million (28.7%) in 2003 due to an increase in purchases to meet off-system sales requirements ($9.0 million), and a 12% higher unit cost of purchases ($8.7 million).

Gas supply expenses increased $32.4 million (13.9%) in 2004 due to an increase in cost of net gas supply ($52.2 million) offset by a decrease in the volume of gas delivered to the distribution system ($19.8 million). 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).

Other operations and maintenance expenses increased $14.7 million (5.1%) in 2004.

Other operation expenses decreased $2.5 million (1.2%) in 2004 primarily due to:

•The KU/LG&E merger costs and the One Utility initiative costs were fully amortized in 2003, resulting in $2.8 million lower expense in 2004.

•Decreased steam generation expense ($1.2 million).

•Decreased benefits expense ($1.7 million), primarily due to lower pension expense ($2.1 million) as a result of the $34.5 million pension funding in January 2004, partially offset by higher medical insurance expense.

•Incremental operations expense due to storm restoration costs related to severe storms in May and July 2004 ($3.1 million).

Maintenance expenses for 2004 increased $15.6 million (27.3%) primarily due to:

•Increased maintenance expense due to storm restoration costs related to severe May and July storms ($9.3 million).

•Increased distribution maintenance, excluding the storm restoration costs ($0.7 million).

•Increased steam generation expense due to timing of scheduled maintenance ($1.4 million).

•Increased combustion turbine maintenance ($1.1 million).

•Increased hydro generation maintenance, primarily due to Ohio Falls rehabilitation ($0.5 million).

Property and other taxes increased $1.6 million (10.2%) in 2004 primarily due to:

•Increased property taxes ($1.2 million).

•Increased payroll taxes ($0.4 million).

Other operations and maintenance increased $5.3 million (1.9%) in 2003.

Other operation expenses increased $8.7 million (4.2%) in 2003 primarily due 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).

•Increased uncollectible customer accounts ($1.6 million).

•Decreased amortization of regulatory assets ($3.5 million).

•Decreased injury and damage liabilities ($2.1 million).

Maintenance expenses for 2003 decreased $3.0 million (5.0%) primarily due to:

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•Decreased maintenance of electric distribution ($1.1 million) and gas distribution ($0.8 million).

•Decreased communications maintenance expenses ($0.9 million).

Property and other taxes decreased $0.4 million (2.3%) in 2003 primarily due to:

•Reduced property taxes due to a $1.2 million coal credit ($1.1 million).

•Increased payroll taxes ($0.7 million).

Depreciation and amortization increased $3.3 million (2.9%) in 2004 and $7.4 million (7.0%) in 2003 due to additional utility plant in service.

Other income (expense) - net increased $3.9 million (53.7%) in 2004.  In 2003, write-offs of $3.0 million decreased other income (see below).  Other income (expense) - net decreased $5.7 million (367.2%) 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).

Total interest expense for 2004 increased $2.1 million (7.0%) due to increased borrowing from Fidelia ($6.9 million), higher cost of the interest rate swaps ($3.0 million) resulting from the first full year of an additional $128 million of swaps and higher interest rates on variable-rate debt ($0.8 million), partially offset by savings from retired first mortgage debt ($7.2 million) and reduced borrowing from the money pool ($1.4 million).

Interest charges for 2003 increased $0.8 million (2.8%) due to new fixed-rate debt with Fidelia ($5.0 million) offset by a decrease in average outstanding balances borrowed from the money pool ($0.4 million) and savings from lower average interest rates on variable-rate long-term bonds ($3.7 million).

The weighted average interest rate on variable-rate long-term bonds for 2004, 2003 and 2002 was 1.28%, 1.10% and 1.54%, respectively.  At December 31, 2004, 2003 and 2002, LG&E’s percentage of long-term bonds having a variable-rate, including the impact of interest rate swaps,  was 35.1% at $306.0 million, 38.3% at $306.0 million and 46.8% at $289.0 million, respectively.  LG&E’s weighted average cost of long-term debt, including amortization of debt expense and interest rate swaps, was 3.92%, 3.58%, and 3.87% at December 31, 2004, 2003 and 2002, respectively.  See Note 9 of LG&E’s Notes to Financial Statements under Item 8.

Variations in income tax expenses are largely attributable to changes in pre-tax income. LG&E’s 2004 effective income tax rate increased to 35.8% from the 35.5% rate in 2003.   See Note 7 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

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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.  Wholesale sales of excess asset capacity and wholesale purchases to be used to serve native load are treated as normal sales and purchases under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities and SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, and are not marked-to-market.  See Note 4 and Note 15 of LG&E’s Notes to Financial Statements under Item 8.

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, 2004, a 10% change in these estimated quantities would cause revenue and accounts receivable to change by approximately $6.3 million, including $2.7 million for electric usage and $3.6 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, 2004 and 2003, the LG&E allowance for doubtful accounts was $0.8 million and $3.5 million, respectively.  The allowance is based on the ratio of the amounts charged-off during the last twelve months to the retail revenues billed over the same period multiplied by the retail revenues billed over the last four months.  Accounts with no payment activity are charged-off after four months.

Benefit Plan Accounting – 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, healthcare cost trend rates, discount rate, contributions made to the plan, and other actuarial assumptions used to value benefit obligations.  In 2002, LG&E was required to recognize an additional minimum liability of $26.0 million as prescribed by SFAS No. 87 Employers’ Accounting for Pensions since the fair value of the plan assets was less than the accumulated benefit obligation at that time.  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.  The liability was recorded as a reduction to other comprehensive income, and did not affect net income.  In 2003, LG&E recognized a reduction of the minimum pension liability of $3.1 million.  During 2004 LG&E recognized an additional minimum pension liability of $10.2 million.  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.

Should poor market conditions return, these conditions could result in an increase in LG&E’s unfunded 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.

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

	2004		2003		2002
Discount rate	6.25	%	6.75	%	7.25	%
Expected long-term return on plan assets	8.50	%	9.00	%	9.50	%
Rate of compensation increase	3.50	%	3.75	%	4.25	%

LG&E made contributions to the pension plan of $34.5 million in January 2004 and $89.1 million during 2003.

A 1% increase or decrease in the assumed discount rate could have an approximate $39.9 million positive or negative impact to the accumulated benefit obligation of LG&E.

See also Note 6 and Note 15 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.

See also Note 3 of LG&E’s Notes to Financial Statements under Item 8.

Income Taxes - Income taxes are accounted for under SFAS No.109, Accounting for Income Taxes.  In accordance with this statement, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, as measured by enacted tax rates that are expected to be in effect in the periods when the deferred tax assets and liabilities are expected to be settled or realized. Significant judgment is required in determining the provision for income taxes, and there are many transactions for which the ultimate tax outcome is uncertain.

To provide for these uncertainties or exposures, an allowance is maintained for tax contingencies, the balance of which management believes is adequate.  Tax contingencies are analyzed periodically and adjustments are made when events occur to warrant a change.  The company is currently in the examination phase of IRS audits for the years 1999 to 2003 and expects some or all of these audits to be completed within the next 12 months.  The results of audit assessments by taxing authorities are not anticipated to have a material adverse effect on cash flows or results of operations.

H. R. 4520, known as the “American Jobs Creation Act of 2004” allows electric utilities to take a deduction of up to 3% of their generation taxable income in 2005. On a stand-alone basis, LG&E expects to generate a deduction in 2005 which will reduce LG&E’s effective tax rate by less than 1%.

Kentucky House Bill 272, also known as Kentucky’s Tax Modernization Plan, was signed into law in March  2005.  This bill contains a number of changes in Kentucky’s tax system, including the reduction of the Corporate income tax rate from 8.25% to 7% effective January 1, 2005, and a further reduction to 6% effective January 1, 2007.  The impact of these reduced rates is expected to decrease LG&E’s income tax expense in future periods.  Furthermore, these reduced rates will result in the reversal of accumulated temporary differences at lower rates than originally provided.  LG&E is presently evaluating the impact of this and other changes to the Kentucky tax system, however, no material adverse impacts on cash flows or results of operations are expected.

LG&E is subject to periodic changes in state tax law, regulation or interpretation, as well as enforcement proceedings.  LG&E is currently undergoing a routine Kentucky sales tax audit for the period October 1997 through 2001.  The possible assessment or amount at issue is not known at this time, but is not expected to have a material adverse effect on cashflows or results of operations.

See Note 1 and Note 7 of LG&E’s Notes to Financial Statements under Item 8.

Deferred Income Taxes - LG&E expects to have adequate levels of taxable income to realize its recorded deferred tax assets.  See Note 7 of LG&E’s Notes to Financial Statements under Item 8 for a breakdown of deferred tax assets.

NEW ACCOUNTING PRONOUNCEMENTS

The following recent accounting pronouncements affected LG&E in 2004 and 2003:

SFAS No. 143

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.  As of January 1, 2003, LG&E recorded 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.

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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, 2004, LG&E had ARO assets, net of accumulated depreciation, of $3.3 million and liabilities of $10.3 million.  As of December 31, 2003, LG&E had ARO assets, net of accumulated depreciation, of $3.5 million and liabilities of $9.7 million.  LG&E recorded offsetting regulatory assets of $6.9 million and $6.0 million and regulatory liabilities of $0.1 million as of both December 31, 2004 and 2003, respectively.

For the year ended December 31, 2004, LG&E recorded ARO accretion expense of approximately $0.7 million, ARO depreciation expense of $0.2 million and an offsetting regulatory credit in the income statement of $0.9 million, pursuant to regulatory treatment prescribed under SFAS No. 71.  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.  Removal costs incurred and charged against the ARO liability during 2004 and 2003 were $0.1 million and $0.2 million, respectively.  SFAS No. 143 has no impact on the results of operations 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 years ended December 31, 2004 and 2003, LG&E recorded immaterial amounts (less than $0.1 million) 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, 2004 and 2003, LG&E has segregated this cost of removal, embedded in accumulated depreciation, of $220.2 million and $216.5 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.

EITF No. 02-03

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,

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•Contractsthat 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 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 previously reported 2002 balances as shown below. The reclassifications had no impact on previously reported net income or common equity.

(in thousands)
Gross electric operating revenues as previously reported	$	1,026,184
Less costs reclassified from power purchased	22,449
Net electric operating revenues	$	1,003,735
Gross power purchased as previously reported	$	84,330
Less costs reclassified to revenues	22,449
Net power purchased	$	61,881

SFAS No. 150

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 $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 and 2004, leaving 225,000 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.

FIN 46

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

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

In December 2003, FIN 46 was revised, delaying the effective dates for certain entities created before February 1, 2003, and making other amendments to clarify application of the guidance.  For potential variable interest entities other than special purpose entities, the revised FIN 46 (“FIN 46R”) was 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. The adoption of FIN 46 and FIN 46R had no impact on the financial position or results of operations for LG&E.

Although LG&E holds an investment interest in OVEC, it is not the primary beneficiary of OVEC and, therefore, OVEC is not consolidated into the financial statements of LG&E.  LG&E and 11 other electric utilities are participating owners of OVEC, located in Piketon, Ohio. 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’s original investment in OVEC was made in 1952. As of December 31, 2004, LG&E’s investment in OVEC totaled $0.5 million.  In March 2005, LG&E purchased from AEP an additional 0.73% interest in OVEC for a purchase price of approximately $0.1 million, which resulted in an increase in LG&E ownership in OVEC from 4.9% to 5.63%.  LG&E’s investment in OVEC is accounted for under the cost method of accounting.

LG&E’s maximum exposure to loss as a result of its involvement with OVEC is limited to the value of the investments.  In the event of the inability of OVEC to fulfill its power provision requirements, LG&E would substitute such power supply with either owned generation or market purchases and would generally recover associated incremental costs through regulatory rate mechanisms.  See Note 11 of LG&E’s Notes to Financial Statements under Item 8 for further discussion of developments regarding LG&E’s ownership interest and power purchase rights.

FSP 106-2

In May 2004, the FASB finalized FSP 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“Medicare Act”) with guidance on accounting for subsidies provided under the Medicare Act which became law in December 2003.  FSP No. 106-2 is effective for the first interim or annual period beginning after June 15, 2004.  FSP 106-2 does not have a material impact on LG&E.

FSP 109-1

In December 2004, the FASB finalized FSP 109-1, Accounting for Income Taxes, Application of FAS 109 to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004, whichrequires the tax deduction on qualified production activities to be treated as a special deduction in accordance with FAS 109.  FSP 109-1 became effective December 21, 2004, and does not have a material impact on LG&E.

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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.

As of December 31, 2004, LG&E is in a negative working capital position in part because of the classification of certain variable-rate pollution control bonds that are subject to tender for purchase at the option of the holder as current portion of long-term debt. Backup credit facilities totaling $185 million are in place to fund such tenders if necessary.  LG&E has never had to access these facilities.  LG&E expects to cover any working capital deficiencies with cash flow from operations, money pool borrowings, and borrowings from Fidelia.

Operating Activities

Cash provided by operations was $171.6 million, $163.3 million and $212.4 million in 2004, 2003, and 2002, respectively.  The 2004 increase of $8.3 million compared to 2003 resulted largely from the reduction in pension funding of $54.6 million, higher gas supply cost recovery of $15.0 million, higher earnings sharing mechanism of $10.1 million and receipt of a litigation settlement of $7.0 million. These increases were largely offset by a reduction in accounts receivable of $66.3 million, including the termination of the accounts receivable securitization program, and a reduction in accrued income taxes of $22.4 million. The 2003 decrease compared to 2002 of $49.1 million resulted primarily from pension funding in 2003 of $89.1 million and an increase 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 income taxes of $35.0 million and $36.0 million, respectively.  See Note 4 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 $148.3 million, $213.0 million and $220.4 million in 2004, 2003, and 2002, respectively.  LG&E expects its capital expenditures for 2005 and 2006 to total approximately $268 million, which consists primarily of construction estimates associated with the redevelopment of the Ohio Falls hydro facility, totaling $19.6 million, construction of Trimble County Unit 2, totaling $8.8 million, and on-going construction related to generation and distribution assets.

Net cash used for investing activities decreased $64.6 million in 2004 compared to 2003, primarily due to the level of construction expenditures.  NOx equipment expenditures were approximately $5.3 million in 2004 and $29.6 million in 2003, while CT expenditures were approximately $8.1 million in 2004 and $71.4 million in 2003.    Net cash used for investing activities decreased $7.2 million in 2003 compared to 2002 primarily due to the level of construction expenditures.

Financing Activities

Net cash inflows (outflows) for financing activities were $(18.3) million in 2004, $34.2 million in 2003 and $22.5 million in 2002.

In January 2004, LG&E entered into two long-term loans from Fidelia, one totaling $25 million with an interest

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rate of 4.33% that matures in January 2012, and one totaling $100 million with an interest rate of 1.53% that matured in January 2005.  The loans are collateralized by a pledge of substantially all assets of LG&E that is subordinated to the first mortgage bond lien. The proceeds were used to fund a pension contribution and to repay other debt obligations.  In April 2004, LG&E prepaid $50 million of the $100 million 1.53% note payable to Fidelia.  The prepayment was paid out of cash balances.  The remaining $50 million under this note was paid at maturity in January 2005.

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 Fidelia totaling $200 million.  $100 million of this total is unsecured and the remaining $100 million is collateralized by a pledge of substantially all assets of LG&E that is subordinated to the first mortgage bond lien.

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

In March 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. LG&E also refinanced its two $35 million unsecured pollution control bonds due November 1, 2027.  The replacement variable-rate bonds are secured by pollution control series bonds treated as 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.

Under the provisions of certain variable-rate pollution control bonds totaling $246.2 million, the bonds are subject to tender for purchase by LG&E 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.  Backup credit facilities totaling $185 million are in place to fund such tenders if necessary.  LG&E has never had to access these facilities.

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.  Fidelia also provides long-term intercompany funding to LG&E.

Certain regulatory approvals are required for the Company to incur additional debt.  The SEC authorizes the issuance of short-term debt while the Kentucky Commission authorizes issuance of long-term debt.  As of December 31, 2004 the Company has received approvals from the SEC to borrow up to $400 million in short-term funds.

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LG&E’s debt ratings as of December 31, 2004, 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.

Contractual Obligations

The following is provided to summarize LG&E’s contractual cash obligations for periods after December 31, 2004.  LG&E anticipates cash from operations and external financing will be sufficient to fund future obligations.

(in thousands)	Payments Due by Period
Contractual Cash Obligations	2005		2006		2007		2008		2009		Thereafter			Total
Short-term debt (a)	$	58,220	$	—	$	—	$	—	$	—	$	—		$	58,220
Long-term debt	297,450		1,250		1,250		18,750		—		553,104		(b)	871,804
Operating lease (c)	3,469		3,538		3,609		3,681		3,754		22,375			40,426
Unconditional power purchase obligations (d)	11,230		10,098		9,726		9,932		10,145		181,089			232,220
Coal and gas purchase obligations (e)	202,450		95,478		52,656		49,396		6,037		6,037			412,054
Retirement obligations (f)	9,250		10,106		13,305		10,992		15,839		—			59,492
Other long-term obligations (g)	14,767		—		—		—		—		—			14,767
Total contractual cash obligations	$	596,836	$	120,470	$	80,546	$	92,751	$	35,775	$	762,605		$	1,688,983

(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.  LG&E does not expect to pay these amounts in 2005.

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

(d)Represents future minimum payments under OVEC purchased power agreements through 2024.

(e)Represents contracts to purchase coal and natural gas.

(f)Represents currently projected cash flows for pension plans and other post-employment benefits as calculated by the actuary.

(g)Represents construction commitments.

Sale and Leaseback Transaction

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 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

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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, 2004, the maximum aggregate amount of default fees or amounts, which decrease over the term of the lease, was $9.5 million, of which LG&E would be responsible for $3.6 million (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.

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 Notes 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, 2004, the potential change in interest expense associated with a 1% change in base interest rates of LG&E’s unhedged debt is estimated at $3.6 million after the impact of interest rate swaps.

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

As of December 31, 2004, 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 $25.7 million as of December 31, 2004.  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, SFAS No. 138and SFAS No. 149.  Wholesale sales of excess asset capacity are treated as normal sales under these pronouncements and are not marked to market.  To be eligible for the normal sales exclusion under SFAS No. 133, sales are limited to the forecasted excess capacity of LG&E’s generation assets over what is needed to serve native load.  To be eligible for the normal purchases exclusion under SFAS No. 133 purchases must be used to serve LG&E’s

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native load.  Without the normal sales and purchases exclusion these transactions would be considered derivatives and marked to market under SFAS No. 133.

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 2004 and 2003:

(in thousands)	2004			2003
Fair value of contracts at beginning of period, net asset (liability)	$	572		$	(156	)
Fair value of contracts when entered into during the period	(75		)	2,654
Contracts realized or otherwise settled during the period	(858		)	(569		)
Changes in fair values due to changes in assumptions	164			(1,357		)
Fair value of contracts at end of period, net (liability) asset	$	(197	)	$	572

No changes to valuation techniques for energy trading and risk management activities occurred during 2004.  Changes in market pricing, interest rate and volatility assumptions were made during both years.  The outstanding mark-to-market value is sensitive to changes in prices, price volatilities, and interest rates.  The Company estimates that a movement in prices of $1 and a change in interest and volatilities of 1% would not result in a change of a material amount.  All contracts outstanding at December 31, 2004, 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, 2004, 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.  LG&E terminated the accounts receivable securitization program in January 2004, and in May 2004, dissolved its inactive accounts receivable securitization-related subsidiary, LG&E R. 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 had standard terms and were not past due.  LG&E was able to terminate the program at any time without penalty.

As part of the program, LG&E sold retail accounts receivable to 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 unrelated third-party purchasers.  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.

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,

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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.  No material pre-tax gains or losses from the sale of the receivables occurred in 2004, 2003, and 2002.  LG&E’s net cash flows from LG&E R were $(58.1) million, $(6.2) million, and $20.2 million for 2004, 2003 and 2002, respectively.

The allowance for doubtful accounts associated with the eligible securitized receivables at December 31, 2003 and 2002 was $1.4 million and $1.9 million, 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.  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.

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.

In June 2004, the Kentucky Commission issued an order approving increases in the base electric and gas rates of LG&E.  The Kentucky Commission’s order largely accepted proposed settlement agreements filed in May 2004 by LG&E and a majority of the parties to the rate case proceedings.   The rate increases took effect on July 1, 2004.

In the Kentucky Commission’s order, LG&E was granted increases in annual base electric rates of approximately $43.4 million (7.7%) and in annual base gas rates of approximately $11.9 million (3.4%).  Other provisions of the order include decisions on certain depreciation, gas supply clause, ECR and VDT amounts or mechanisms and a termination of the ESM with respect to all periods after 2003.  The order also provided for a recovery before March 31, 2005, by LG&E of previously requested amounts relating to the ESM during 2003.

During July 2004, the AG served subpoenas on LG&E, as well as on the Kentucky Commission and its staff, requesting information regarding allegedly improper communications between LG&E and the Kentucky Commission, particularly during the period covered by the rate cases. The Kentucky Commission has procedurally reopened the rate cases for the limited purpose of taking evidence, if any, as to the communication issues. Subsequently, the AG filed pleadings with the Kentucky Commission requesting rehearing of the rate cases on certain computational components of the increased rates, including income tax, cost of removal and depreciation amounts. In August 2004, the Kentucky Commission denied the AG’s rehearing request on the cost of removal and depreciation issues, with the effect that the rate increase order is final as to these matters, subject to the parties’ rights to judicial appeals. The Kentucky Commission further agreed to hold in abeyance further proceedings in the rate cases, including the AG’s concerns about alleged improper communications, until the AG could file with the Kentucky Commission an investigative report regarding the latter issue. In addition, the Kentucky Commission granted a rehearing on the income tax component once the abeyance discussed above is lifted.

In September and October 2004, various proceedings were held in circuit courts in Franklin and Jefferson Counties, Kentucky regarding the scope and timing of document production or other information required or

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agreed to be produced under the AG’s subpoenas and matters were consolidated into the Franklin County court. In October 2004, the AG filed a motion with the Kentucky Commission requesting that the previously granted rate increases be set aside, that LG&E resubmit any applications for rate increases and that relevant Kentucky Commission personnel be recused from participation in rate case proceedings.  In November 2004, the Franklin County, Kentucky court denied an AG request for sanctions on LG&E relating to production matters and narrowed the AG’s permitted scope of discovery.   In January 2005, the AG conducted interviews of certain Company individuals.

In January 2005, the AG submitted its report to the Franklin County, Kentucky Circuit Court in confidence.  Concurrently the AG filed a motion summarizing the report as containing evidence of improper communications and record-keeping errors by LG&E in its conduct of activities before the Kentucky Commission or other state governmental entities and requesting release of the report to such agencies.  During February 2005 the court ruled that the report be forwarded to the Kentucky Commission under continued confidential treatment to allow it to consider the report, including its impact, if any, on completing its investigation and any remaining steps in the rate cases, including ending the current abeyance.  To date, LG&E has neither seen nor requested copies of the report or its contents.

LG&E believes no improprieties have occurred in its communications with the Kentucky Commission and is cooperating with the proceedings before the AG and the Kentucky Commission.

LG&E is currently unable to determine the ultimate impact, if any, of, or any possible future actions of the AG or the Kentucky Commission arising out of, the AG’s report and investigation, including whether there will be further actions to appeal, review or otherwise challenge the granted increases in base rates.

VDT Costs - Kentucky Commission Settlement Order.  During the first quarter 2001, LG&E recorded a $144 million charge for a workforce reduction program.  Primary components of the charge were separation benefits, enhanced early retirement benefits, and 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.

In December 2001, the Kentucky Commission approved a settlement in the VDT case as well as other cases involving the depreciation rates and ESM.  The order approving the settlement 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.

As mentioned, the current five-year VDT amortization period is scheduled to expire in March 2006.  As part of the settlement agreements in the electric and gas rate cases, LG&E shall file with the Kentucky Commission a plan for the future ratemaking treatment of the VDT surcredits and costs six months prior to the March 2006 expiration.  The surcredit shall remain in effect following the expiration of the fifth year until the Commission enters an order on the future disposition of VDT-related issues.

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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 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.

ESM.  Prior to 2004, LG&E’s retail electric rates were subject to an ESM.  The ESM, initially in place for three years beginning in 2000, set an upper and lower point for rate of return on equity, whereby if LG&E’s rate of return for the calendar year fell within the range of 10.5% to 12.5%, no action was necessary.  If earnings were above the upper limit, the excess earnings were shared 40% with ratepayers and 60% with shareholders; if earnings were below the lower limit, the earnings deficiency was recovered 40% from ratepayers and 60% from shareholders.  By order of the Kentucky Commission, rate changes prompted by the ESM filing went 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.  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.

LG&E filed its final 2003 ESM calculations with the Kentucky Commission on March 1, 2004, and applied for recovery of $13.0 million. Based upon estimates, LG&E previously accrued $8.9 million for the 2003 ESM as of December 31, 2003.

On June 30, 2004, the Kentucky Commission issued an order largely accepting proposed settlement agreements by LG&E and all intervenors regarding the ESM.  Under the ESM settlements, LG&E will continue to collect approximately $13.0 million of previously requested 2003 ESM revenue amounts through March 2005.  As part of the settlement, the parties agreed to a termination of the ESM relating to all periods after 2003.

As a result of the settlement, LG&E accrued an additional $4.1 million in June 2004, related to 2003 ESM revenue.

FAC.  LG&E’s retail electric rates contain a FAC, whereby increases or decreases in the cost of fuel for electric generation are reflected in the rates charged to retail electric customers.  In January 2003, the Kentucky

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Commission reviewed KU’s FAC and, as part of the Order in that case, required that an independent audit be conducted to examine operational and management aspects of both LG&E’s and KU’s fuel procurement functions.  The final report was issued in February 2004. The report’s recommendations related to documentation and process improvements.  Management Audit Action Plans were agreed upon by LG&E and the Kentucky Commission Staff in the second quarter of 2004.  LG&E filed its first Audit Progress Report with the Kentucky Commission Staff in November 2004.  A second Audit Progress Report is due in May 2005.

The Kentucky Commission requires public hearings at six-month intervals to examine past fuel adjustments, and at two-year intervals to review past operations of the fuel clause and transfer of the then current fuel adjustment charge or credit to the base charges.  No significant issues have been identified as a result of these reviews.

In December 2004, the Kentucky Commission initiated a two-year review of LG&E’s past operations of the fuel clause and transfer of fuel costs from the fuel adjustment clause to base rates.  A public hearing on the matter was held on March 17, 2005.  An order by the Kentucky Commission is expected in April 2005.  LG&E is seeking to increase the fuel component of base rates.  LG&E does not anticipate any issues will arise during the regulatory proceeding.

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 LG&E 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 evaluations.

Gas Supply Cost PBR Mechanism.   Since November 1, 1997, LG&E has operated under an experimental PBR mechanism related to its gas procurement activities.   LG&E’s rates are adjusted annually to recover its portion of the savings (or expenses) incurred during each PBR year (12 months ending October 31). Since its implementation on November 1, 1997, through October 31, 2004, LG&E has achieved $60.7 million in savings. Of that total savings amount, LG&E’s portion has been $22.7 million and the ratepayers’ portion has been $38.0 million.  Pursuant to the extension of LG&E’s 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 filed a report and assessment with the Kentucky Commission in December 2004, seeking modification and extension of the mechanism.

ECR.  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.

In August 2002, LG&E filed an application with the Kentucky Commission to amend its compliance plan to

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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, approving 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.

In June 2004, the Kentucky Commission issued an order approving a settlement agreement that, among other things, revised the rate of return for LG&E’s post-1995 plan to 10.72%, with an 11% return on common equity.  The order also approved the elimination of LG&E’s 1995 plan from its ECR billing mechanism, with all remaining costs associated with that plan to be included in their entirety in base rates.

In December 2004, 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, including the expansion of the Mill Creek landfill. The estimated capital cost of the additional facilities is $40.2 million.  LG&E requested an overall rate of return of 10.72%, including an 11% return on common equity.  A final order in the case is anticipated in June 2005.

MISO.   LG&E is a founding member of the MISO.  Membership was obtained in 1998 in response to and consistent with federal policy initiatives.  In February 2002, LG&E turned over operational control of its 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 and the rest of the MISO owners.  On February 18, 2005, the United States Court of Appeals for the District of Columbia Circuit ruled that FERC did not provide proper notice that it would consider an incentive adder of 50 basis points, but affirmed the September 2002 FERC order in all other respects.  Effective ROE, retroactive to February 1, 2002, is 12.38% for LG&E and the original 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, 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, along with several other transmission owners, again petitioned the District Court of

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Columbia Circuit for review. In July 2004 the court affirmed the FERC ruling.

In August 2004, the MISO filed its FERC-required proposed Transmission and Energy Markets Tariff (“TEMT”).  In September and October 2004, many MISO-related parties (including LG&E) filed proposals with the FERC regarding pending MISO-filed changes to transmission pricing principles, including the TEMT and elimination of Regional Through and Out Rates (“RTORs”). Additional filings of the companies before FERC in September 2004 sought to address issues relating to the treatment of certain “grandfathered” transmission agreements (“GFA’s”) should TEMT become effective. The utility proposals generally seek to appropriately delay the RTORs and TEMT effective dates based upon errors in administrative or procedural processes used by FERC or to appropriately limit potential reductions in transmission revenues received by the utilities should the RTORs, TEMT or GFA structures be implemented.  At present, existing FERC orders conditionally approve elimination of RTORs and implementation of general TEMT rates in the MISO by spring 2005.  At this time, LG&E cannot predict the outcome or effects of the various FERC proceedings described above, including whether such will have a material impact on the financial condition or results of operations of the companies. Financial consequences (changes in transmission revenues and costs) associated with the upcoming transmission market tariff changes are subject to varying assumptions and calculations and are therefore difficult to estimate. Changes in revenues and costs related to broader shifts in energy market practices and economics are not currently estimable.  Should LG&E be ordered to exit MISO, current MISO rules may also impose an exit fee.  LG&E is not able to predict the estimated outcome or economic impact of any of the MISO-related matters.  While LG&E believes legal and regulatory precedent should permit most or many of the MISO-related costs to be recovered in their rates charged to customers, they can give no assurance that state or federal regulators will ultimately agree with such position with respect to all costs, components or timing of recovery.

The MISO plans to implement a Day-ahead and Real-time market, including a congestion management system in April 2005. 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, have objected to the allocation of costs among market participants and retail native load. FERC ruled in 2004 in favor of the MISO.

The Kentucky Commission opened an investigation into LG&E’s membership in the MISO in July 2003. The Kentucky Commission directed LG&E to file testimony addressing the costs and benefits of the MISO membership both currently and over the next five years and other legal issues surrounding continued membership.  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 the MISO, under certain conditions.  The MISO filed its own testimony and cost benefit analysis in December 2003.  A final Kentucky Commission order was expected in the second quarter of 2004; that ruling has since been delayed until summer 2005 due to the Kentucky Commission’s request for additional testimony on the MISO’s Market Tariff filing at FERC.

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, in July 2001 the Kentucky Commission opened Administrative Case No. 387 to review the adequacy of Kentucky’s generation capacity and transmission system.  Specifically, the items reviewed were the appropriate level of reliance on purchased power, the appropriate reserve margins to meet existing and future electric demand, the impact of spikes in natural gas prices on electric utility planning strategies, and the adequacy of Kentucky’s electric transmission facilities.  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.

Kentucky Commission Strategic Blueprint.  In February 2005, Kentucky’s Governor signed an executive order directing the Kentucky Commission, in conjunction with the Commerce Cabinet and the Environmental and Public Protection Cabinet, to ‘develop a Strategic Blueprint for the continued use and development of electric energy.’ This Strategic Blueprint will be designed to promote future investment in electric infrastructure for the Commonwealth of Kentucky, to protect Kentucky’s low-cost electric advantage, to maintain affordable rates for all Kentuckians, and to preserve Kentucky’s commitment to environmental protection.  In March

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2005, the Kentucky Commission established Administrative Case No. 2005-00090 to collect information from all jurisdictional utilities in Kentucky, including LG&E, pertaining to Kentucky electric generation, transmission and distribution systems.  The Kentucky Commission must provide its Strategic Blueprint to the Governor in early August 2005.  LG&E must respond to the Kentucky Commission’s first set of data requests by the end of March 2005.

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, 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’s revenues and expenses, the specific impact of the rulemaking is not known at this time.

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 their intent to promulgate new administrative regulations under the auspices of the new law.  This effort is still ongoing.

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 May 2004, in Case No. 2004-148, LG&E proposed a hedge plan for the 2004/2005 winter heating season relying upon LG&E’s storage to mitigate customer exposure to price volatility. In August 2004, the Kentucky Commission approved LG&E’s proposed hedge plan, validating the effectiveness of storage to mitigate potential volatility associated with high winter gas prices by approving this natural gas hedge plan.  The Kentucky Commission also ordered that LG&E need not file hedge plans in the future unless it intended to utilize financial hedging instruments.

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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 exempt from Phase I SO₂ requirements due to its low emission rates. LG&E opted into the Phase I NOx program to take advantage of the less stringent requirements and installed burner modifications as needed to meet these limitations.  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 the EPA on 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, the 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 31, 2004.  All LG&E generating units are in compliance with these NOx emissions reduction rules.

LG&E has added significant NOx controls to its generating units through the installation of SCR systems, advanced low-NOx burners and neural networks.  The NOx controls project commenced in late 2000 with the controls being placed into operation prior to the 2004 Summer Ozone Season. As of December 31, 2004, LG&E incurred total capital costs of approximately $186 million to reduce its NOx emissions below the 0.15 lb./MMBtu level on a company-wide basis.  In addition, LG&E will incur additional operating and maintenance costs in operating new NOx controls.  LG&E believes its costs in this regard to be comparable to those of similarly situated utilities with like generation assets. LG&E 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 Clean Air Mercury Rule which regulates mercury emissions from steam electric generating units and reductions in emissions of SO₂ and NOx required under the Clean Air Interstate Rule.  In addition, LG&E has worked 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 has converted 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 could incur additional costs of $0.4 million for additional cleanup.  Accordingly, an accrual for this amount has been recorded in the accompanying financial

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statements at December 31, 2004 and 2003.

See Note 11 of LG&E’s Notes to Financial Statements under Item 8 for an additional discussion of environmental issues.

FUTURE OUTLOOK

Competition and Customer Choice

In the last several years, LG&E has taken many steps to keep its rates low while maintaining high levels of

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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.  LG&E will take additional steps to better position itself should retail competition come to Kentucky.

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.  Some states that have already deregulated have begun discussions that could lead to re-regulation.

In February 2005, Kentucky’s Governor signed an executive order directing the Kentucky Commission, in conjunction with the Commerce Cabinet and the Environmental and Public Protection Cabinet, to ‘develop a Strategic Blueprint for the continued use and development of electric energy.’ This Strategic Blueprint will be designed to promote future investment in electric infrastructure for the Commonwealth of Kentucky, to protect Kentucky’s low-cost electric advantage, to maintain affordable rates for all Kentuckians, and to preserve Kentucky’s commitment to environmental protection.”  In March 2005, the Kentucky Commission established Administrative Case No. 2005-00090 to collect information from all jurisdictional utilities in Kentucky, including LG&E, pertaining to Kentucky electric generation, transmission and distribution systems.  The Kentucky Commission must provide its Strategic Blueprint to the Governor in early August 2005.  LG&E must respond to the Kentucky Commission’s first set of data requests by the end of March 2005.

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KU

RESULTS OF OPERATIONS

Net Income

KU’s net income in 2004 increased $42.1 million (46.0%) compared to 2003.  The increase resulted primarily from higher revenues, primarily in the retail sector, due to increased base rates resulting from the rate case order and higher volumes due to a warmer summer.  Offsetting the increase somewhat were $2.7 million in operating expenses related to severe May and July storms in 2004.

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.

Revenues

The following table presents a comparison of operating revenues for the years 2004 and 2003 with the immediately preceding year.

(in thousands)	Increase (Decrease) From Prior Period
Cause	2004			2003
Retail sales:
Fuel clause adjustments	$	7,549		$	20,959
KU/LG&E Merger surcredit	(2,593		)	(1,254		)
Environmental cost recovery surcharge	6,276			6,038
Earnings sharing mechanism	7,749			8,718
Demand side management	1,011			365
VDT surcredit	(486		)	(1,740		)
Rate and rate structure	21,694			—
Variation in sales volumes, and other	24,575			(1,755		)
Provision for rate collections (refunds)	13,285			(24,015		)
Total retail sales	79,060			7,316
Wholesale sales	21,999			20,751
Other	2,525			2,047
Total	$	103,584		$	30,114

Electric revenues increased in 2004 primarily due to an increase in rates and a change in the rate structure. New rates, implemented in July 2004 and the elimination of a volume dependent step rate structure, increased revenues by 3.1% in 2004. Retail volumes increased 3.3% due to a 1.4% increase in the customer base and 2.6% increase in demand due to weather. The KU service area experienced a warmer summer in 2004, partially offset by a milder winter.  Cooling degree days for 2004 increased 2.9% from 2003 and were 20% below the 20-year average while heating degree days decreased 6.8% from 2003 and were 4% below the 20-year average. Wholesale revenues increased due to a combination of a 14.2% increase in prices and 1.7% higher volumes.

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 were 3% above the 20-year average.  Wholesale revenues

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increased due to a combination of a 28.6% increase in volumes and 3.8% higher prices.

The provision for rate collections (refunds) increased $13.3 million in 2004. This increase resulted primarily from fuel ($18.1 million) and ECR ($12.8 million) accruals partially offset by a decrease in the ESM ($17.6 million) accruals. The decrease in the provision for rate collections (refunds) in 2003 from 2002 ($24.0 million) results primarily from a decrease in the ESM accruals ($13.5 million), a decrease in 2003 fuel accruals ($6.0 million), and a decrease in ECR accruals during 2003 ($4.5 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 a 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 $26.1 million (9.8%) in 2004 because of a 6% increase in the cost of fuel burned ($16.8 million) and an increase in generation ($9.3 million).   Fuel for electric generation increased $15.8 million (6.3%) in 2003 because of an increase in the cost of fuel burned ($18.9 million), partially offset by a decrease in generation ($3.1 million).   The average delivered cost per MMBtu of coal purchased was $1.56 in 2004, $1.47 in 2003 and $1.35 in 2002.

Power purchased expense in 2004 increased $4.2 million (3.0%) over 2003, primarily due to an increase in purchases to meet off-system sales requirements ($5.1 million) partially offset by a decrease in purchase price ($0.9 million).    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 ($15.1 million) partially offset by a decrease in purchase price ($6.4 million).

Other operation and maintenance expenses increased $0.8 million (0.4%) in 2004.

Other operation expenses decreased $0.4 million (0.3%) in 2004 primarily due to:

•Decreased benefits expense ($3.7 million), primarily due to lower pension expense.

•The KU/LG&E merger costs and the One Utility initiative costs were fully amortized in 2003, resulting in $2.9 million lower expense in 2004.

•Increased emission allowance expense ($4.5 million).

•Incremental operations expense due to storm restoration costs related to severe storms in May and July 2004 ($0.5 million).

•Increased combustion turbine operations expense ($0.9 million); 2003 included Alstom settlement payments, lowering expense.

Maintenance expenses increased $0.6 million (1.0%) in 2004 primarily due to:

•Increased maintenance expense due to storm restoration costs related to severe May and July storms ($2.2 million).

•Increased combustion turbine maintenance ($2.3 million); 2003 included Alstom settlement payments, lowering expense.

•Decreased expense due to reclassification of maintenance expense to a regulatory asset ($4.0 million) of costs related to the 2003 ice storm based on an order from the Kentucky Commission, to be amortized

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through June 2009.  KU earns a return of these amortized costs, which are included in KU’s jurisdictional operating expenses.

Property and other taxes increased $0.8 million (4.8%) in 2004 primarily due to:

•Increased property taxes of $0.6 million.

•Increased payroll taxes of $0.3 million.

Other operations and maintenance expenses decreased $0.2 million (0.1%) in 2003.

Other operation expenses increased $1.5 million (1.0%) in 2003 primarily due to:

•Increased employee benefits costs ($4.7 million).

•Increased property insurance expenses ($1.4 million).

•Decreased amortization of regulatory assets ($4.7 million).

Maintenance expenses decreased $2.6 million (4.2%) in 2003 primarily due to:

•Decreased steam generation and combustion turbine generation maintenance due to cancellation and postponement of scheduled outages ($5.1 million).

•Decreased communications maintenance expenses ($1.0 million).

•Increased maintenance to electric distribution equipment due to an ice storm ($4.1 million, net of $8.9 million in insurance recoveries).

Property and other taxes increased $0.9 million (6.0%) in 2003 primarily due to:

•Increased property taxes ($0.5 million)

•Increased Kentucky Commission assessment ($0.4 million).

Depreciation and amortization increased $6.8 million (6.7%) in 2004 and $6.3 million (6.6%) in 2003 primarily due to an increase in plant in service.

Other income - net increased $3.0 million (66.2%) in 2004.  In 2003, write-offs of $1.3 million decreased other income (see below).  In addition, 2004 miscellaneous non-operating income was $0.6 million higher and gains related to sale of property were $0.4 million higher. Other income - net decreased $1.9 million (30.1%) 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 terminated plant projects ($1.0 million) and a terminated software project ($0.6 million), 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.

Total interest expense increased $0.3 million (1.0%) in 2004 due primarily to increased borrowing from Fidelia ($9.0 million), partially offset by savings from retired first mortgage debt ($4.4 million), lower cost of interest rate swaps ($3.5 million) and reduced borrowing from the money pool ($0.8 million).

Total interest expense decreased $0.4 million (1.7%) in 2003 due primarily to savings from lower average interest rates on variable-rate long-term bonds ($9.0 million) and an increase in interest income from interest rate swaps ($0.8 million), offset by interest expense on new fixed-rate debt with Fidelia ($4.7 million) and additional expenses recognized from mark-to-market adjustments of underlying debt associated with the interest rate swaps ($5.1 million).

The weighted average interest rate on variable-rate long-term bonds for 2004, 2003 and 2002 was 1.32%, 1.07% and 1.56%, respectively.  At December 31, 2004, 2003 and 2002, KU’s percentage of long-term bonds having a

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variable-rate, including the impact of interest rate swaps, was 48.6% at $349.0 million, 53.6% at $386.6 million and 73.8% at $369.5 million, respectively.  KU’s weighted average cost of long-term debt, including amortization of debt expense and interest rate swaps, was 3.43%, 2.96%, and 3.30% at December 31, 2004, 2003, and 2002, respectively.  See Note 9 of KU’s Notes to the Financial Statements under Item 8.

Variations in income tax expense are largely attributable to changes in pre-tax income.  KU’s 2004 effective income tax rate increased to 36.4% from the 35.4% rate in 2003.  See Note 7 of KU’s Notes to Financial Statements under Item 8.

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

CRITICAL ACCOUNTING POLICIES/ESTIMATES

Preparation of financial statements and related disclosures in compliance with generally accepted accounting principles requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates.  The application of these policies necessarily involves judgments regarding future events, including legal and regulatory challenges and anticipated recovery of costs.  These judgments, in and of themselves, could materially impact the financial statements and disclosures based on varying assumptions, which may be appropriate to use.  In addition, the financial and operating environment also may have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies applied has not changed.  Specific risks for these critical accounting policies are described in the following paragraphs.  Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions.  Events rarely develop exactly as forecast and the best estimates routinely require adjustment.  See also Note 1 of KU’s Notes to Financial Statements under Item 8.

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.  Wholesale sales of excess asset capacity and wholesale purchases to be used to serve native load are treated as normal sales and purchases under SFAS No. 133, SFAS No. 138 and SFAS No. 149 and are not marked-to-market.   See Note 4 and Note 14 of KU’s Notes to Financial Statements under Item 8.

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, 2004, a 10% change in these estimated quantities would cause revenue and accounts receivable to change by approximately $4.8 million.  See also Note 1 of KU’s Notes to Financial Statements under Item 8.

Allowance for Doubtful Accounts - At December 31, 2004 and 2003, the KU allowance for doubtful accounts

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was $0.6 million and $0.7 million, respectively.  The allowance is based on the ratio of the amounts charged-off during the last twelve months to the retail revenues billed over the same period multiplied by the retail revenues billed over the last four months.  Accounts with no payment activity are charged-off after four months.

Benefit Plan Accounting - 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, healthcare cost trend rates, discount rate, contributions made to the plan, and other actuarial assumptions used to value benefit obligations.  In  2002, KU was required to recognize a minimum liability of $17.5 million as prescribed by SFAS No. 87 Employers’ Accounting for Pensions since the fair value of the plan assets was less than the accumulated benefit obligation at that time.  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.  The liability was recorded as a reduction to other comprehensive income, and did not affect net income.  In 2003, KU recognized a reduction of the minimum pension liability of $7.7 million.  During 2004, KU recognized an additional minimum pension liability of $12.4 million.  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.

Should poor market conditions return, these conditions could result in an increase in KU’s unfunded 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.

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

	2004		2003		2002
Discount rate	6.25	%	6.75	%	7.25	%
Expected long-term return on plan assets	8.50	%	9.00	%	9.50	%
Rate of compensation increase	3.50	%	3.75	%	4.25	%

KU made contributions to the pension plan of $43.4 million in January 2004 and $10.2 million during 2003.

A 1% increase or decrease in the assumed discount rate could have an approximate $26.8 million positive or negative impact to the accumulated benefit obligation of KU.

See also Note 6 and Note 14 of KU’s Notes to Financial Statements under Item 8.

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

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

See also Note 3 of KU’s Notes to Financial Statements under Item 8.

Income Taxes - Income taxes are accounted for under SFAS No.109.  In accordance with this statement, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, as measured by enacted tax rates that are expected to be in effect in the periods when the deferred tax assets and liabilities are expected to be settled or realized. Significant judgment is required in determining the provision for income taxes, and there are many transactions for which the ultimate tax outcome is uncertain. 

To provide for these uncertainties or exposures, an allowance is maintained for tax contingencies, the balance of which management believes is adequate.  Tax contingencies are analyzed periodically and adjustments are made when events occur to warrant a change. The company is currently in the examination phase of IRS audits for the years 1999 to 2003 and expects some or all of these audits to be completed within the next 12 months.  The results of audit assessments by taxing authorities are not anticipated to have a material adverse effect on cash flows or results of operations.

H. R. 4520, known as the “American Jobs Creation Act of 2004” allows electric utilities to take a deduction of up to 3% of their generation taxable income in 2005. On a stand-alone basis, KU expects to generate a deduction in 2005 which will reduce KU’s effective tax rate by less than 1%. See Note 1 and Note 7 of KU’s Notes to Financial Statements under Item 8.

Kentucky House Bill 272, also known as Kentucky’s Tax Modernization Plan, was signed into law in March 2005.  This bill contains a number of changes in Kentucky’s tax system, including the reduction of the Corporate income tax rate from 8.25% to 7% effective January 1, 2005, and a further reduction to 6% effective January 1, 2007.  The impact of these reduced rates is expected to decrease KU’s income tax expense in future periods.  Furthermore, these reduced rates will result in the reversal of accumulated temporary differences at lower rates than originally provided.  KU is presently evaluating the impact of this and other changes to the Kentucky tax system, however, no material adverse impacts on cash flows or results of operations are expected.

KU is subject to periodic changes in state tax law, regulation or interpretation, as well as enforcement proceedings.  KU is currently undergoing a routine Kentucky sales tax audit for the period January 1996 to July 2000.  The possible assessment or amount at issue is not known at this time, but is not expected to have a material adverse effect on cashflows or results of operations. 

See Note 1 and Note 7 of KU’s Notes to Financial Statements under Item 8.

Deferred Income Taxes - KU expects to have adequate levels of taxable income to realize its recorded deferred tax assets.  See Note 7 of KU’s Notes to Financial Statements under Item 8 for a breakdown of deferred tax assets.   

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NEW ACCOUNTING PRONOUNCEMENTS

The following recent accounting pronouncements affected KU in 2004 and 2003:

SFAS No. 143

SFAS No. 143 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.  As of January 1, 2003, KU recorded 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.  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, 2004, KU recorded ARO assets, net of accumulated depreciation, of $6.7 million and liabilities of $21.0 million.  As of December 31, 2003, KU had ARO assets, net of accumulated depreciation, of $6.9 million and liabilities of $19.7 million.  KU recorded offsetting regulatory assets of $12.8 million and $11.3 million and regulatory liabilities of $1.4 million and $1.2 million as of December 31, 2004 and 2003, respectively.

For the year ended December 31, 2004, KU recorded ARO accretion expense of $1.3 million, ARO depreciation expense of $0.2 million and an offsetting regulatory credit in the income statement of $1.5 million, pursuant to regulatory treatment prescribed under SFAS No. 71. 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.  SFAS No. 143 has no impact on the results of operations 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 years ended December 31, 2004 and 2003, KU recorded $0.3 million for both periods 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, 2004 and 2003, KU has segregated this cost of removal, embedded in accumulated

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depreciation, of $266.8 million and $256.7 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.

EITF No. 02-03

KU adopted EITF No. 98-10effective 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.  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 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 previously reported 2002 balances as shown below. The reclassifications had no impact on previously reported net income or common equity.

(in thousands)
Gross electric operating revenues as previously reported	$	888,219
Less costs reclassified from power purchased	26,555
Net electric operating revenues	$	861,664
Gross power purchased as previously reported	$	157,955
Less costs reclassified to revenues	26,555
Net power purchased	$	131,400

SFAS No. 150

In May 2003, the Financial Accounting Standards Board issued SFAS No. 150, which 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.

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FIN 46

In January 2003, the Financial Accounting Standards Board issued FIN 46.  FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties.  FIN 46 was effective immediately for all new variable interest entities created or acquired after January 31, 2003.  For variable interest entities created or acquired prior to February 1, 2003, the provisions of FIN 46 must have been applied for the first interim or annual period beginning after June 15, 2003.

In December 2003, FIN 46 was revised, delaying the effective dates for certain entities created before February 1, 2003, and making other amendments to clarify application of the guidance.  For potential variable interest entities other than special purpose entities, FIN 46R was 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. The adoption of FIN 46 and FIN 46R had no impact on the financial position or results of operations for KU.

Although KU holds investment interests in OVEC and EEI, it is not the primary beneficiary of OVEC or EEI, and, therefore, neither are consolidated into the financial statements of KU.  KU and 11 other electric utilities are participating owners of OVEC, located in Piketon, Ohio.  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%, representing approximately 55 Mw of generation capacity.

KU’s original investment in OVEC was made in 1952.  KU’s investment in OVEC is the equivalent of 2.5% of OVEC’s common stock and is accounted for under the cost method of accounting.  As of December 31, 2004, KU’s investment in OVEC totaled $0.3 million. KU’s maximum exposure to loss as a result of the involvement with OVEC is limited to the value of the investments.  In the event of the inability of OVEC to fulfill its power provision requirements, KU would substitute such power supply with either owned generation or market purchases and would generally recover associated incremental costs through regulatory rate mechanisms.  See Note 11 of KU’s Notes to Financial Statements under Item 8 for further discussion of developments regarding KU’s ownership interests and power purchase rights.

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 generated by KU.  This contract governing the purchases from EEI will terminate on December 31, 2005.  Such power equated to approximately 10% of KU’s net generation system output in 2004.

KU’s original investment in EEI was made in 1953.  KU’s investment in EEI is accounted for under the equity method of accounting and, as of December 31, 2004, totaled $13.4 million.  KU’s direct exposure to loss as a result of its involvement with EEI is generally limited to the value of its investment.  In the event of the inability of EEI to fulfill its power provision requirements, KU would substitute such power supply with either owned generation or market purchases and would generally recover associated incremental costs through regulatory

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rate mechanisms.

FSP 106-2

In May 2004, the FASB finalized FSP 106-2 with guidance on accounting for subsidies provided under the Medicare Act which became law in December 2003.  FSP 106-2 is effective for the first interim or annual period beginning after June 15, 2004.  FSP 106-2 does not have a material impact on KU.

FSP 109-1

In December 2004, the FASB finalized FSP 109-1, whichrequires the tax deduction on qualified production activities to be treated as a special deduction in accordance with FAS 109.  FSP 109-1 became effective December 21, 2004, and does not have a material impact on KU.

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.

As of December 31, 2004, KU is in a negative working capital position in part because of the classification of certain variable-rate pollution control bonds that are subject to tender for purchase at the option of the holder as current portion of long-term debt. KU expects to cover any working capital deficiencies with cash flow from operations, money pool borrowings, and borrowings from Fidelia.

Operating Activities

Cash provided by operations was $185.9 million, $233.4 million and $175.8 million 2004, 2003, and 2002, respectively.  The 2004 decrease compared to 2003 of $47.5 million was primarily due to an increase in accounts receivable of $63.0 million, including the termination of the accounts receivable securitization program, additional pension funding of $33.2 million and lower environmental cost recovery of $14.2 million. These decreases were partially offset by higher earnings of $42.1 million, higher accounts payable of $13.5 million and receipt of a litigation settlement of $11.4 million. The 2003 increase compared to 2002 of $57.6 million was primarily the result of an increase in accrued income 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.  See Note 4 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 $157.6 million, $341.9 million and $237.9 million in 2004, 2003 and 2002, respectively.  KU expects its capital expenditures for 2005 and 2006 to total approximately $448 million, which consists primarily of construction estimates associated with installation of FGDs on Ghent units, totaling $195.9 million, as described in the section titled “Environmental Matters,” the construction of Trimble County Unit 2, totaling $37.4 million, and on-going construction on generation and distribution assets.

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Net cash used for investing activities decreased $185.2 million in 2004 compared to 2003 primarily due to the level of construction expenditures.  NOx expenditures were approximately $45.0 million in 2004 and $110.0 million in 2003, while CT expenditures were approximately $13.7 million in 2004 and $117.2 million in 2003. Net cash used for investment activities increased $107.5 million in 2003 compared to 2002 due to increased CT and NOx expenditures.

Financing Activities

Net cash inflows (outflows) from financing activities were $(30.6) million, $107.8 million and $64.2 million in 2004, 2003 and 2002, respectively.

In January 2004, KU entered into an unsecured long-term loan from Fidelia totaling $50 million with an interest rate of 4.39% that matures in January 2012.  The proceeds were used to fund a pension contribution and to repay other debt obligations.

In May 2004, KU redeemed $4.8 million of its Series 14 Pollution Control Bonds which were initially issued in the amount of $7.2 million.

In October 2004, KU completed a refinancing transaction regarding $50 million in existing pollution control indebtedness.  The original indebtedness, 5.75% Pollution Control Bonds, Series 9, due December 1, 2023, was discharged in November 2004, with the proceeds from the replacement indebtedness, KU Pollution Control Bonds, Series 17, due October 1, 2034, which carries a variable, auction rate of interest.  The call premium and unamortized debt expense of the Series 9 bonds are deferred assets being amortized over the life of the Series 17 bonds.

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 2027, and replaced it with a loan from Fidelia.

During 2003, KU entered into four long-term loans from Fidelia totaling $283 million.  $100 million of this total is unsecured and the remaining $183 million is collateralized by a pledge of substantially all assets of KU that is subordinated to the first mortgage bond lien.

In May 2002, KU issued $37.9 million variable-rate pollution control Series 12, 13, 14 and 15 due February 1, 2032, and exercised its call option on $37.9 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.

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

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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/or LG&E make funds available to KU at market-based rates up to $400 million.  Fidelia also provides long-term intercompany funding to KU.

Certain regulatory approvals are required for the Company to incur additional debt.  The Virginia Commission and the SEC authorize the issuance of short-term debt while the Kentucky Commission, the Virginia Commission, and the Tennessee Regulatory Authority authorize issuance of long-term debt.  As of December 31, 2004 the Company has received approvals from the Virginia Commission and the SEC to borrow up to $400 million in short-term funds.

KU’s debt ratings as of December 31, 2004, 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.

Contractual Obligations

The following is provided to summarize KU’s contractual cash obligations for periods after December 31, 2004.  KU anticipates cash from operations and external financing will be sufficient to fund future obligations.

(in thousands) Contractual Cash Obligations	Payments Due by Period
	2005		2006		2007		2008		2009		Thereafter			Total
Short-term debt (a)	$	34,820	$	—	$	—	$	—	$	—	$	—		$	34,820
Long-term debt	162,130		36,000		58,088		—		—		469,993		(b)	726,211
Unconditional power purchase obligations (c)	40,098		41,141		42,625		43,690		45,138		655,720			868,412
Coal purchase obligations (d)	263,418		156,613		64,886		35,808		—		—			520,725
Retirement obligations (e)	6,564		6,915		7,236		7,479		7,757		—			35,951
Other long-term obligations (f)	14,771		—		—		—		—		—			14,771
Total contractual cash obligations	$	521,801	$	240,669	$	172,835	$	86,977	$	52,895	$	1,125,713		$	2,200,890

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

(b)Includes long-term debt of $87.1 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 2024 to 2032.  KU does not expect to pay these amounts in 2005.

(c)Represents future minimum payments under OVEC, OMU and EEI purchased power agreements through 2024.

(d)Represents contracts to purchase coal.

(e)Represents currently projected cash flows for pension plans and other post-employment benefits as calculated by the actuary.

(f)Represents construction commitments.

Sale and Leaseback Transaction

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,

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and have executed an irrevocable notice to exercise an early purchase option contained in the lease after 15.5 years. The financial statement treatment of this transaction is no different than if KU had retained its ownership. 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, 2004, the maximum aggregate amount of default fees or amounts, which decrease over the term of the lease, was $9.5 million, of which KU would be responsible for $5.9 million (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.

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, 2004, the potential change in interest expense associated with a 1% change in base interest rates of KU’s variable-rate debt is estimated at $3.8 million after the impact of interest rate swaps.

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

As of December 31, 2004, KU has swaps with a combined notional value of $103 million.  The swaps exchange fixed-rate interest payments for floating rate interest payments on KU’s Series P and R first mortgage bonds.  The potential loss in fair value resulting from a hypothetical 1% adverse movement in base interest rates is estimated at $1.5 million as of December 31, 2004.  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

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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, SFAS No. 138 and SFAS No. 149. Wholesale sales of excess asset capacity are treated as normal sales under these pronouncements and are not marked to market.  To be eligible for the normal sales exclusion under SFAS No. 133, sales are limited to the forecasted excess capacity of KU’s generation assets over what is needed to serve native load.  To be eligible for the normal purchases exclusion under SFAS No. 133 purchases must be used to serve KU’s native load. Without the normal sales and purchases exclusion these transactions would be considered derivatives and marked to market under SFAS No. 133.

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 2004 and 2003:

(in thousands)	2004			2003
Fair value of contracts at beginning of period, net asset (liability)	$	572		$	(156	)
Fair value of contracts when entered into during the period	(75		)	2,654
Contracts realized or otherwise settled during the period	(858		)	(569		)
Changes in fair values due to changes in assumptions	164			(1,357		)
Fair value of contracts at end of period, net (liability) asset	$	(197	)	$	572

No changes to valuation techniques for energy trading and risk management activities occurred during 2004.  Changes in market pricing, interest rate and volatility assumptions were made during both years. The outstanding mark-to-market value is sensitive to changes in prices, price volatilities, and interest rates.  The Company estimates that a movement in prices of $1 and a change in interest and volatilities of 1% would not result in a change of a material amount.  All contracts outstanding at December 31, 2004 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, 2004, 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.  KU terminated the accounts receivable securitization program in January 2004, and in May 2004, dissolved its inactive accounts receivable securitization-related subsidiary, KU R. 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 had standard terms and were not past due.  KU was able to terminate this program at any time without penalty.

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As part of the program, KU sold retail accounts receivable to 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 unrelated third-party purchasers.  The effective cost of the receivable 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 purchasers.  KU obtained an opinion from independent legal counsel indicating these transactions qualified as a true sale of receivables.

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.  No material pre-tax gains or losses from the sale of the receivables occurred during 2004, 2003 and 2002.  KU’s net cash flows from KU R were $(50.1) million, $(0.1) million and $3.3 million for 2004, 2003 and 2002, respectively.

The allowance for doubtful accounts associated with the eligible securitized receivables at December 31 was $0.5 million in 2003 and 2002.  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, the Tennessee Regulatory Authority, and FERC in virtually all matters related to electric utility regulation, and as such, its accounting is subject to SFAS No. 71.  Given KU’s competitive position in the marketplace 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.

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.

On June 30, 2004, the Kentucky Commission issued an order approving an increase in the base electric rates of KU.  The Kentucky Commission’s order largely accepted proposed settlement agreements filed in May 2004 by KU and a majority of the parties to the rate case proceedings.   The rate increases took effect on July 1, 2004.

In the Kentucky Commission’s order, KU was granted an increase in annual base electric rates of approximately $46.1 million (6.8%).  Other provisions of the order include decisions on certain depreciation, ECR and VDT amounts or mechanisms and a termination of the ESM with respect to all periods after 2003.  The order also provided for a recovery before March 31, 2005, by KU of previously requested amounts relating to the ESM during 2003.

During July 2004, the AG served subpoenas on KU, as well as on the Kentucky Commission and its staff, requesting information regarding allegedly improper communications between KU and the Kentucky Commission, particularly during the period covered by the rate case. The Kentucky Commission has procedurally reopened the rate cases for the limited purpose of taking evidence, if any, as to the communication

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issues. Subsequently, the AG filed pleadings with the Kentucky Commission requesting rehearing of the rate case on certain computational components of the increased rates, including income tax, cost of removal and depreciation amounts. In August 2004, the Kentucky Commission denied the AG’s rehearing request on the cost of removal and depreciation issues, with the effect that the rate increase order is final as to these matters, subject to the parties’ rights to judicial appeals. The Kentucky Commission further agreed to hold in abeyance further proceedings in the rate case, including the AG’s concerns about alleged improper communications, until the AG could file with the Kentucky Commission an investigative report regarding the latter issue. In addition, the Kentucky Commission granted a rehearing on the income tax component once the abeyance discussed above is lifted.

In September and October 2004, various proceedings were held in circuit courts in Franklin and Jefferson Counties, Kentucky regarding the scope and timing of document production or other information required or agreed to be produced under the AG’s subpoenas and matters were consolidated into the Franklin County court.  In October 2004, the AG filed a motion with the Kentucky Commission requesting that the previously granted rate increase be set aside, that KU resubmit any applications for rate increases and that relevant Kentucky Commission personnel be recused from participation in rate case proceedings.  In November 2004, the Franklin County, Kentucky court denied an AG request for sanctions on KU relating to production matters and narrowed the AG’s permitted scope of discovery.   In January 2005, the AG conducted interviews of certain Company individuals.

In January 2005, the AG submitted its report to the Franklin County, Kentucky Circuit Court in confidence.  Concurrently the AG filed a motion summarizing the report as containing evidence of improper communications and record-keeping errors by KU in its conduct of activities before the Kentucky Commission or other state governmental entities and requesting release of the report to such agencies.  During February 2005 the court ruled that the report be forwarded to the Kentucky Commission under continued confidential treatment to allow it to consider the report, including its impact, if any, on completing its investigation and any remaining steps in the rate case, including ending the current abeyance.  To date, KU has neither seen nor requested copies of the report or its contents.

KU believes no improprieties have occurred in its communications with the Kentucky Commission and is cooperating with the proceedings before the AG and the Kentucky Commission.

KU is currently unable to determine the ultimate impact, if any, of, or any possible future actions of the AG or the Kentucky Commission arising out of, the AG’s report and investigation, including whether there will be further actions to appeal, review or otherwise challenge the granted increase in base rates.

VDT Costs - Kentucky Commission Settlement Order.  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.

In December 2001, the Kentucky Commission approved a settlement in the VDT case as well as other cases

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involving the depreciation rates and ESM.  The order approving the settlement 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 net savings stipulated  by KU.

As mentioned, the current five-year VDT amortization period is scheduled to expire in March 2006.  As part of the settlement agreements in the electric and gas rate cases, KU shall file with the Kentucky Commission a plan for the future ratemaking treatment of the VDT surcredits and costs six months prior to the March 2006 expiration.  The surcredit shall remain in effect following the expiration of the fifth year until the Commission enters an order on the future disposition of VDT-related issues.

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.

ESM.  Prior to 2004, KU’s Kentucky retail electric rates were subject to an ESM.  The ESM, initially in place for three years beginning in 2000, set an upper and lower point for rate of return on equity, whereby if KU’s rate of return for the calendar year fell within the range of 10.5% to 12.5%, no action was necessary.  If earnings were above the upper limit, the excess earnings were shared 40% with ratepayers and 60% with shareholders; if earnings were below the lower limit, the earnings deficiency was recovered 40% from ratepayers and 60% from shareholders.  By order of the Kentucky Commission, rate changes prompted by the ESM filing went into effect in April of each year subject to a balancing adjustment in successive periods.  There is no ESM for Virginia retail electric rates.

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.  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.

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KU filed its final 2003 ESM calculations with the Kentucky Commission on March 1, 2004, and applied for recovery of $16.2 million. Based upon estimates, KU previously accrued $9.3 million for the 2003 ESM as of December 31, 2003.

On June 30, 2004, the Kentucky Commission issued an order largely accepting proposed settlement agreements by KU and all intervenors regarding the ESM.  Under the ESM settlements, KU will continue to collect approximately $16.2 million of previously requested 2003 ESM revenue amounts through March 2005.  As part of the settlement, the parties agreed to a termination of the ESM mechanism relating to all periods after 2003.

As a result of the settlement, KU accrued an additional $6.9 million in June 2004, related to 2003 ESM revenue.

FAC.  KU’s Kentucky retail electric rates contain a FAC, whereby increases or decreases in the cost of fuel for electric generation are reflected in the rates charged to retail electric customers.  In January 2003, the Kentucky Commission reviewed KU’s FAC for the six month period ended October 31, 2001. 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.  Management Audit Action Plans were agreed upon by KU and the Kentucky Commission Staff in the second quarter of 2004.  KU filed its first Audit Progress Report with the Kentucky Commission Staff in November 2004.  A second Audit Progress Report is due in May 2005.

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.

In December 2004, the Kentucky Commission initiated a two-year review of KU’s past operations of the fuel clause and transfer of fuel costs from the fuel adjustment clause to base rates.   A public hearing on the matter was held on March 17, 2005.  An order by the Kentucky Commission is expected in April 2005.  KU is seeking to increase the fuel component of base rates.  KU does not anticipate any issues will arise during the regulatory proceeding.

In February 2005, KU filed with the Virginia Commission an application seeking approval of an increase in its fuel cost factor to reflect higher fuel costs incurred.   KU anticipates implementing the increased fuel cost factor with April 2005 billings.

DSM.  In May 2001, the Kentucky Commission approved a plan that would expand LG&E’s 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.

ECR.  In August 2002, KU filed an application with the Kentucky Commission to amend its compliance plan to

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allow recovery of the cost of a new and additional environmental compliance facilities.  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.

In June 2004, the Kentucky Commission issued an order approving a settlement agreement that, among other things, revised the rate of return for KU’s post-1994 plan to 11.19%, with an 11% return on common equity.  The order also approved the elimination of KU’s 1994 Plan for its ECR billing mechanism, with all remaining costs associated with that plan to be included in their entirety in base rates.

In December 2004, KU filed an application with the Kentucky Commission for approval of a CCN to construct new SO₂ control technology (FGDs) at the Ghent and Brown stations, and to amend its compliance plan to allow recovery of costs associated with new and additional environmental compliance facilities.  The estimated capital cost of the additional facilities is $702.5 million, of which $658.9 million is for the FGDs.  A final order in the case is expected in June 2005.

MISO.  KU is a founding member of the MISO.  Membership was obtained in 1998 in response to and consistent with federal policy initiatives.  In February 2002, KU turned over operational control of its 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 and the rest of the MISO owners.  On February 18, 2005, the United States Court of Appeals for the District of Columbia Circuit ruled that FERC did not provide proper notice that it would consider an incentive adder of 50 basis points, but affirmed the September 2002 FERC order in all other respects.  Effective ROE, retroactive to February 1, 2002, is 12.38% for KU and the original 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, 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, along with several other transmission owners, again petitioned the District Court of Columbia Circuit for review. In July 2004, the court affirmed the FERC ruling.

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In August 2004, the MISO filed its FERC-required proposed TEMT.  In September and October 2004, many MISO-related parties (including KU) filed proposals with the FERC regarding pending MISO-filed changes to transmission pricing principles, including the TEMT and elimination of RTORs. Additional filings of the companies before FERC in September 2004 sought to address issues relating to the treatment of certain GFA's should TEMT become effective. The utility proposals generally seek to appropriately delay the RTORs and TEMT effective dates based upon errors in administrative or procedural processes used by FERC or to appropriately limit potential reductions in transmission revenues received by the utilities should the RTORs, TEMT or GFA structures be implemented.  At present, existing FERC orders conditionally approve elimination of RTORs and implementation of general TEMT rates in the MISO by spring 2005.  At this time, KU cannot predict the outcome or effects of the various FERC proceedings described above, including whether such will have a material impact on the financial condition or results of operations of the companies. Financial consequences (changes in transmission revenues and costs) associated with the upcoming transmission market tariff changes are subject to varying assumptions and calculations and are therefore difficult to estimate. Changes in revenues and costs related to broader shifts in energy market practices and economics are not currently estimable.  Should KU be ordered to exit MISO, current MISO rules may also impose an exit fee.  KU is not able to predict the estimated outcome or economic impact of any of the MISO-related matters.  While KU believes legal and regulatory precedent should permit most or many of the MISO-related costs to be recovered in their rates charged to customers, they can give no assurance that state or federal regulators will ultimately agree with such position with respect to all costs, components or timing of recovery.

The MISO plans to implement a Day-ahead and Real-time market, including a congestion management system in April 2005. This system will be similar to the 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, have objected to the allocation of costs among market participants and retail native load. FERC ruled in 2004 in favor of the MISO.

The Kentucky Commission opened an investigation into KU’s membership in the MISO in July 2003. The Kentucky Commission directed KU to file testimony addressing the costs and benefits of the MISO membership both currently and over the next five years and other legal issues surrounding continued membership.  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 the MISO, under certain conditions.  The MISO filed its own testimony and cost benefit analysis in December 2003.  A final Kentucky Commission order was expected in the second quarter of 2004; that ruling has since been delayed until summer 2005 due to the Kentucky Commission’s request for additional testimony on the MISO’s Market Tariff filing at FERC.

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, in July 2001 the Kentucky Commission opened Administrative Case No. 387 to review the adequacy of Kentucky’s generation capacity and transmission system.  Specifically, the items reviewed were the appropriate level of reliance on purchased power, the appropriate reserve margins to meet existing and future electric demand, the impact of spikes in natural gas prices on electric utility planning strategies, and the adequacy of Kentucky’s electric transmission facilities.  In December 2001, the Kentucky Commission issued an order in which it noted that KU is responsibly addressing the long-term supply needs of native load customers and that current reserve margins are appropriate.  However, due to the rapid pace of change in the industry, the order also requires KU to provide an annual assessment of supply resources, future demand, reserve margin, and the need for new resources.

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

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

Kentucky Commission Strategic Blueprint.  In February 2005, Kentucky’s Governor signed an executive order directing the Kentucky Commission, in conjunction with the Commerce Cabinet and the Environmental and Public Protection Cabinet, to ‘develop a Strategic Blueprint for the continued use and development of electric energy.’ This Strategic Blueprint will be designed to promote future investment in electric infrastructure for the Commonwealth of Kentucky, to protect Kentucky’s low-cost electric advantage, to maintain affordable rates for all Kentuckians, and to preserve Kentucky’s commitment to environmental protection.  In March 2005, the Kentucky Commission established Administrative Case No. 2005-00090 to collect information from

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all jurisdictional utilities in Kentucky, including KU, pertaining to Kentucky electric generation, transmission and distribution systems.  The Kentucky Commission must provide its Strategic Blueprint to the Governor in early August 2005.  KU must respond to the Kentucky Commission’s first set of data requests by the end of March 2005.

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, defined as SMD. The SMD NOPR would require each public utility that owns, operates, or controls interstate transmission facilities to become an 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’s revenues and expenses, the specific impact of the rulemaking is not known at this time.

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.

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 and through the consumption of emission allowances granted under the Clean Air Act.  KU’s strategy for Phase II SO₂ reductions, which commenced January 1, 2000, has been to use accumulated emissions allowances to delay additional capital expenditures and will include fuel switching and the installation of additional FGDs as necessary. KU decided in December 2004 that additional FGDs will be necessary to maintain compliance with Phase II SO₂ reductions.  Those installations are currently scheduled for completion in 2007-2009.   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 the EPA on June 24, 2003,

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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, the 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 the 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 31, 2004.  All KU generating units are in compliance with these NOx emissions reduction rules.

KU has added significant NOx controls to its generating units through the installation of SCR systems, advanced low-NOx burners and neural networks.  The NOx controls project commenced in late 2000 with the controls being placed into operation prior to the 2004 Summer Ozone Season. As of December 31, 2004, KU incurred total capital costs of approximately $219 million to reduce its NOx emissions below the 0.15 lb./MMBtu level on a company-wide basis.  In addition, KU will incur additional operating and maintenance costs in operating new NOx controls.  KU believes its costs in this regard to be comparable to those of similarly situated utilities with like generation assets. KU 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 Clean Air Mercury Rule which regulates mercury emissions from steam electric generating units and reductions in emissions of SO₂ and NOx required under the Clean Air Interstate Rule.  KU has implemented a plan for adding significant additional SO₂ controls to its generating units.  Installation of additional SO₂ controls will proceed on a phased basis, with construction of controls (i.e. FGD’s) commencing in mid 2005 and continuing through the final installation and operation in 2009.  KU estimates that it will incur $678 million in capital costs related to the reduction of its SO₂ emissions to achieve compliance with current emission limits on a company-wide basis.  In addition, KU will incur additional operating and maintenance costs in operating new SO₂ controls.  KU believes its costs in this regard to be comparable to those of similarly situated utilities with like generation assets.  KU anticipates that such capital and operating costs are the type of costs that are eligible for recovery from customers under its environmental surcharge mechanism and believes that a significant portion of such costs could be recovered.  In December 2004, KU filed an application seeking recovery of its costs. KU expects the Kentucky Commission to issue an Order granting recovery of these costs in June 2005.

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

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a per-gallon fine for the amount of oil discharged.  During August 2004, KU, the EPA, and the Department of Justice agreed in principle to settle outstanding matters concerning the 1999 oil discharge at KU’s E.W. Brown plant for approximately $0.6 million. The settlement is subject to completion of final definitive documents but is anticipated to be resolved by the construction of a separate environmental capital project and a cash payment of approximately $0.2 million. At December 31, 2004, KU has recorded an accrual and expense to operations of $0.2 million.

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 parties, among a number of potentially responsible parties, and has entered into settlement discussions with the EPA and the Kentucky Division of Waste Management on this matter.

In January 2005, approximately 1,000 gallons of fuel oil leaked from a cracked weld in a storage tank at KU’s Green River Generating Station.  KU commenced immediate spill containment, recovery and remediation actions and has received satisfactory inspections from state regulators to date.  The cost related to the cleanup of the oil spill is expected to be immaterial.

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

Lock 7 License Matter.  KU's 1.8 Mw hydroelectric facility located at Lock No. 7 on the Kentucky River has been inactive since 1999.  In connection with a possible transfer of Lock No.7 and the dam at the site from the U.S. Army Corps of Engineers to the Kentucky River Authority, KU is seeking to surrender or transfer its FERC license governing the hydroelectric facility.  KU has entered into negotiations with a prospective third party acquirer for the license.  If KU is unable to successfully transfer the license, it may become or remain obligated for certain construction or demolition expenditures or other financial liabilities in the approximate amount of $4 million.

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FUTURE OUTLOOK

Competition and Customer Choice

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

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.  Some states that have already deregulated have begun discussions that could lead to re-regulation.

In February 2005, Kentucky’s Governor signed an executive order directing the Kentucky Commission, in conjunction with the Commerce Cabinet and the Environmental and Public Protection Cabinet, to ‘develop a Strategic Blueprint for the continued use and development of electric energy.’ This Strategic Blueprint will be designed to promote future investment in electric infrastructure for the Commonwealth of Kentucky, to protect Kentucky’s low-cost electric advantage, to maintain affordable rates for all Kentuckians, and to preserve Kentucky’s commitment to environmental protection.”  In March 2005, the Kentucky Commission established Administrative Case No. 2005-00090 to collect information from all jurisdictional utilities in Kentucky, including KU, pertaining to Kentucky electric generation, transmission and distribution systems.  The Kentucky Commission must provide its Strategic Blueprint to the Governor in early August 2005.  KU must respond to the Kentucky Commission’s first set of data requests by the end of March 2005.

Virginia has enacted a phase-in of customer choice through the Virginia Electric Restructuring Act.  The Virginia Commission is promulgating regulations to govern the various activities required by the Act.  Effective July 1, 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 customers in KU’s other service territories.

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

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

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ITEM 8. Financial Statements and Supplementary Data.

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INDEX OF ABBREVIATIONS

AFUDC	Allowance for Funds Used During Construction
ARO	Asset Retirement Obligation
Capital Corp.	LG&E Capital Corp.
Clean Air Act	The Clean Air Act, as amended in 1990
CCN	Certificate of Public Convenience and Necessity
CO2	Carbon Dioxide
CT	Combustion Turbines
CWIP	Construction Work in Progress
DSM	Demand Side Management
ECAR	East Central Area Reliability Region
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.
LNG	Liquefied Natural Gas
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

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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 Executive 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
Trimble County	LG&E’s Trimble County Unit 1
USWA	United Steelworkers of America
Utility Operations	Operations of LG&E and KU
VDT	Value Delivery Team Process
Virginia Commission	Virginia State Corporation Commission
Virginia Staff	Virginia State Corporation Commission Staff
WNA	Weather Normalization Adjustment

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Louisville Gas and Electric Company and Subsidiary

Consolidated Statements of Income

(Thousands of $)

	Years Ended December 31
	2004				2003				2002
OPERATING REVENUES:
Electric (Note 14)	$	815,697			$	768,188			$	736,042
Gas	357,071				325,333				267,693
Total operating revenues (Note 1)	1,172,768				1,093,521				1,003,735
OPERATING EXPENSES:
Fuel for electric generation	207,092				196,965				194,900
Power purchased (Note 14)	92,047				79,621				61,881
Gas supply expenses	266,013				233,601				182,108
Other operation and maintenance expenses	306,008				291,295				285,991
Depreciation and amortization (Note 1)	116,577				113,287				105,906
Total operating expenses	987,737				914,769				830,786
Net operating income	185,031				178,752				172,949
Other income (expense) - net (Note 8 and Note 14)	(3,332			)	(7,193			)	(1,536		)
Interest expense (Notes 9 and 10)	20,545				23,863				27,630
Interest expense to affiliated companies (Note 14)	12,242				6,784				2,175
Income before income taxes	148,912				140,912				141,608
Federal and state income taxes (Note 7)	53,294				50,073				52,679
Net income	$		95,618		$		90,839		$	88,929

Consolidated Statements of Retained Earnings

(Thousands of $)

		Years Ended December 31
		2004			2003		2002
Balance January 1		$	497,441		$	409,319	$	393,636
Add net income		95,618			90,839		88,929
		593,059			500,158		482,565
Deduct:	Cash dividends declared on stock:
5% cumulative preferred		1,075			1,075		1,075
Auction rate cumulative preferred		962			908		1,702
$5.875 cumulative preferred		—			734		1,469
Common		57,000			—		69,000
		59,037			2,717		73,246
Balance December 31		$		534,022	$	497,441	$	409,319

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

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Louisville Gas and Electric Company and Subsidiary

Consolidated Statements of Comprehensive Income

(Thousands of $)

	Years Ended December 31
	2004			2003		2002
Net income	$	95,618		$	90,839	$	88,929
Gain/(losses) on derivative instruments and hedging activities, net of tax benefit/(expense) of $947, $(368) and $3,457 for 2004, 2003 and 2002, respectively (Notes 1 and 4)	(1,399		)	544		(5,107		)
Additional minimum pension liability adjustment, net of tax benefit/(expense) of $4,128, $(1,257) and $10,493 for 2004, 2003 and 2002, respectively (Note 6)	(6,100		)	1,857		(15,505		)
Other comprehensive (loss) income, net of tax (Note 15)	(7,499		)	2,401		(20,612		)
Comprehensive income	$	88,119		$	93,240	$	68,317

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

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Louisville Gas and Electric Company and Subsidiary

Consolidated Balance Sheets

(Thousands of $)

	December 31
	2004			2003
ASSETS:
Current assets:
Cash and cash equivalents (Note 1)	$		6,809	$	1,706
Accounts receivable - less reserve of $785 in 2004 and $3,515 in 2003 (Note 4)	166,990			84,585
Materials and supplies - at average cost:
Fuel (predominantly coal) (Note 1)	21,771			25,260
Gas stored underground (Note 1)	77,503			69,884
Other (Note 1)	26,159			24,971
Prepayments and other	3,921			5,281
	303,153			211,687
Other property and investments – less reserve of $63 in 2004 and 2003 (Note 1)	507			611
Utility plant, at original cost (Note 1):
Electric	3,113,653			2,809,957
Gas	487,771			468,504
Common	177,538			186,556
	3,778,962			3,465,017
Less: reserve for depreciation	1,396,341			1,326,899
	2,382,621			2,138,118
Construction work in progress	136,842			339,166
	2,519,463			2,477,284
Deferred debits and other assets:
Restricted cash (Note 1)	10,943			—
Unamortized debt expense (Note 1)	8,453			8,753
Regulatory assets (Note 3)	91,866			143,626
Other	32,167			40,121
	143,429			192,500
	$	2,966,552		$		2,882,082

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

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Louisville Gas and Electric Company and Subsidiary

Consolidated Balance Sheets (continued)

(Thousands of $)

	December 31
	2004		2003
CAPITAL AND LIABILITIES:
Current liabilities:
Current portion of long-term debt:
Long-term bonds (Note 9)	$	246,200	$	246,200
Long-term notes to affiliated company (Note 9)	50,000		—
Mandatorily redeemable preferred stock (Note 9)	1,250		1,250
	297,450		247,450
Notes payable to affiliated company (Notes 10 and 14)	58,220		80,332
Accounts payable	106,090		93,118
Accounts payable to affiliated companies (Note 14)	31,709		38,343
Accrued income taxes	6,208		11,472
Customer deposits	14,016		10,493
Other	18,624		16,533
	234,867		250,291
	532,317		497,741
Long-term debt (see statements of capitalization):
Long-term bonds (Note 9)	328,104		328,104
Long-term notes to affiliated company (Note 9)	225,000		200,000
Mandatorily redeemable preferred stock (Note 9)	21,250		22,500
	574,354		550,604
Deferred credits and other liabilities:
Accumulated deferred income taxes (Notes 1 and 7)	347,233		337,704
Investment tax credit, in process of amortization	46,176		50,329
Accumulated provision for pensions and related benefits (Note 6)	120,566		140,598
Asset retirement obligations	10,266		9,747
Regulatory liabilities (Note 3):
Accumulated cost of removal of utility plant	220,214		216,491
Other	52,150		51,822
Other	40,105		32,957
	836,710		839,648
Commitments and contingencies (Note 11)
Cumulative preferred stock (see statements of capitalization)	70,425		70,425
Common equity (see statements of capitalization)	952,746		923,664
	$	2,966,552	$	2,882,082

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

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Louisville Gas and Electric Company and Subsidiary

Consolidated Statements of Cash Flows

(Thousands of $)

	Years Ended December 31
	2004			2003			2002
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	95,618		$	90,839		$	88,929
Items not requiring cash currently:
Depreciation and amortization	116,577			113,287			105,906
Deferred income taxes - net	5,533			20,123			11,915
Investment tax credit - net	(4,153		)	(4,207		)	(4,153		)
VDT amortization	30,135			30,400			30,000
Mark-to-market financial instruments	2,576			(1,149		)	8,512
Other	(2,023		)	10,812			11,226
Change in certain net current assets:
Accounts receivable	(24,405		)	(10,945		)	(3,973		)
Materials and supplies	(5,318		)	(7,598		)	(15,048		)
Accounts payable	6,338			8,690			(26,299		)
Accrued income taxes	(5,264		)	17,165			(18,807		)
Prepayments and other	6,827			906			321
Sale of accounts receivable (Note 4)	(58,000		)	(5,200		)	21,200
Pension funding	(34,492		)	(89,125		)	336
Gas supply clause receivable, net	10,296			(4,712		)	3,873
Litigation settlement	6,972			—			—
Earnings sharing mechanism receivable	10,241			142			—
Other	14,178			(6,178		)	(1,557		)
Net cash provided by operating activities	171,636			163,250			212,381
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sales of securities	103			153			412
Construction expenditures	(148,306		)	(212,957		)	(220,416		)
Net cash used for investing activities	(148,203		)	(212,804		)	(220,004		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase in restricted cash	(10,943		)	—			—
Long-term borrowings from affiliated company	125,000			200,000			—
Repayment of long-term borrowings from affiliated company	(50,000		)	—			—
Repayment of short-term borrowings	—			—			(29,944		)
Short-term borrowings from affiliated company	552,800			602,700			652,300
Repayment of short-term borrowings from affiliated company	(574,912		)	(715,421		)	(523,500		)
Retirement of first mortgage bonds	—			(42,600		)	—
Issuance of pollution control bonds	—			128,000			161,665
Issuance expense on pollution control bonds	(135		)	(5,843		)	(3,030		)
Retirement of pollution control bonds	—			(128,000		)	(161,665		)
Retirement of mandatorily redeemable preferred stock	(1,250		)	(1,250		)	—
Payment of dividends	(58,890		)	(3,341		)	(73,300		)
Net cash (used for) provided by financing activities	(18,330		)	34,245			22,526
Change in cash and cash equivalents	5,103			(15,309		)	14,903
Cash and cash equivalents at beginning of year	1,706			17,015			2,112
Cash and cash equivalents at end of year	$	6,809		$	1,706		$	17,015
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Income taxes	$	52,121		$	24,868		$	51,540
Interest on borrowed money	18,144			23,829			25,673
Interest to affiliated companies on borrowed money	11,323			4,162			1,850

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

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Louisville Gas and Electric Company and Subsidiary

Consolidated Statements of Capitalization

(Thousands of $)

				December 31
				2004			2003
LONG-TERM DEBT (Note 9):
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
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			128,000
Notes payable to Fidelia:
Due April 30, 2013, 4.55%, unsecured				100,000			100,000
Due August 15, 2013, 5.31%, secured				100,000			100,000
Due January 6, 2005, 1.53%, secured				50,000			—
Due January 16, 2012, 4.33%, secured				25,000			—
Mandatorily redeemable preferred stock:
$ 5.875 series, outstanding shares of 225,000 in 2004 and 237,500 in 2003				22,500			23,750
Total long-term debt outstanding				871,804			798,054
Less current portion of long-term debt				297,450			247,450
Long-term debt				574,354			550,604
CUMULATIVE PREFERRED STOCK:
	Shares Outstanding	Current Redemption Price
$25 par value, 1,720,000 shares authorized - 5% series	860,287	$	28.00	21,507			21,507
Without par value, 6,750,000 shares authorized - Auction rate	500,000	$	100.00	50,000			50,000
Preferred stock expense, net				(1,082		)	(1,082		)
				70,425			70,425
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 (Note 15)				(45,610		)	(38,111		)
Retained earnings				534,022			497,441
				952,746			923,664
Total capitalization				$	1,597,525		$	1,544,693

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

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

Note 1 - Summary of Significant Accounting Policies

LG&E, a subsidiary of LG&E Energy and an indirect subsidiary of E.ON, is a regulated public utility engaged in the generation, transmission, distribution, and sale of electric energy and the storage, distribution, and sale of natural gas in Louisville and adjacent areas in Kentucky.  LG&E Energy is an exempt 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.  In May 2004, LG&E dissolved its accounts receivable securitization-related subsidiary, LG&E R.  Prior to May 2004, 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 is a registered public utility holding company 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 2004 presentation with no impact on the balance sheet net assets or previously reported income.  Effective December 31, 2004, operating and non-operating income taxes are presented as “Federal and State Income Taxes” on LG&E’s Consolidated Statements of Income.  Prior to December 31, 2004, the component of income taxes associated with operating income was included in net operating income and the component of income taxes associated with non-operating income taxes was included in other income (expense) – net.  LG&E has applied this change in presentation to all prior periods.

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 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 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.

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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 2004 (2.9% electric, 2.8% gas, and 7.6% common); 3.3% in 2003 (2.9% electric, 2.8% gas and 9.4% common); and 3.1% for 2002 (2.9% electric, 2.8% gas and 6.6% common), of average depreciable plant.  Of the amount provided for depreciation, at December 31, 2004, approximately 0.4% electric, 0.9% gas and 0.04% common were related to the retirement, removal and disposal costs of long lived assets.   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 Cash Equivalents.  LG&E considers all debt instruments purchased with a maturity of three months or less to be cash equivalents.

Restricted Cash.  A deposit in the amount of $10.9 million, used as collateral for a $83.3 million interest rate swap, is classified as restricted cash on LG&E’s balance sheet.

Fuel Inventory.  Fuel inventories of $21.8 million and $25.3 million at December 31, 2004, and 2003, 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 $77.5 million and $69.9 million at December 31, 2004, and 2003, 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 $26.2 million and $25.0 million at December 31, 2004 and 2003, 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.  Wholesale sales of excess asset capacity and wholesale purchases to be used to serve native load are treated as normal sales and purchases under SFAS No. 133, SFAS No. 138 and SFAS No. 149 and are not marked-to-market.  See Note 4, Financial Instruments and Note 15, Accumulated Other Comprehensive Income.

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.

Income Taxes. Income taxes are accounted for under SFAS No.109.  In accordance with this statement, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, as measured by enacted tax rates that are expected to be in effect in the periods when the deferred tax assets and liabilities are expected to be settled or realized. Significant judgment is required in determining the provision

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for income taxes, and there are many transactions for which the ultimate tax outcome is uncertain.  To provide for these uncertainties or exposures, an allowance is maintained for tax contingencies, the balance of which management believes is adequate.  Tax contingencies are analyzed periodically and adjustments are made when events occur to warrant a change.  The company is currently in the examination phase of IRS audits for the years 1999 to 2003 and expects some or all of these audits to be completed within the next 12 months.  The results of audit assessments by taxing authorities are not anticipated to have a material adverse effect on cash flows or results of operations.

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 $63.0 million and $50.8 million at December 31, 2004 and 2003, respectively.

Allowance for Doubtful Accounts. At December 31, 2004 and 2003, the LG&E allowance for doubtful accounts was $0.8 million and $3.5 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.

Other Property and Investments.  Other property and investments on the Balance Sheet consists of LG&E’s investment in OVEC and non-utility plant.  As of December 31, 2004 and 2003, LG&E’s investment in OVEC totaled $0.5 million.  In March 2005, LG&E purchased from AEP an additional 0.73% interest in OVEC for a purchase price of approximately $0.1 million, which resulted in an increase in LG&E ownership in OVEC from 4.9% to 5.63%.  LG&E is not the primary beneficiary of OVEC, and, therefore, it is not consolidated into the financial statements of LG&E and is accounted for under the cost method of accounting.

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 probable 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 issued that affected LG&E in 2004 and 2003:

SFAS No. 143

SFAS No. 143 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.

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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.  As of January 1, 2003, LG&E recorded 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.  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, 2004, LG&E had ARO assets, net of accumulated depreciation, of $3.3 million and liabilities of $10.3 million.  As of December 31, 2003, LG&E had ARO assets, net of accumulated depreciation, of $3.5 million and liabilities of $9.7 million.  LG&E recorded regulatory assets of $6.9 million and $6.0 million and regulatory liabilities of $0.1 million as of both December 31, 2004 and 2003, respectively.

For the year ended December 31, 2004, LG&E recorded ARO accretion expense of approximately $0.7 million, ARO depreciation expense of $0.2 million and an offsetting regulatory credit in the income statement of $0.9 million, pursuant to regulatory treatment prescribed under SFAS No. 71.  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.  Removal costs incurred and charged against the ARO liability during 2004 and 2003, were $0.1 million and $0.2 million, respectively.  SFAS No. 143 has no impact on the results of operations 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 years ended December 31, 2004 and 2003, LG&E recorded immaterial amounts (less than $0.1 million) 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, 2004 and 2003, LG&E has segregated this cost of removal, embedded in accumulated depreciation, of $220.2 million and $216.5 million, respectively, in accordance with FERC Order No. 631. For reporting purposes in its Consolidated Balance Sheets, LG&E has presented this cost of removal as a regulatory liability pursuant to SFAS No. 71.

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

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EITF No. 02-03

LG&E adopted EITF No. 98-10effective 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.  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 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 previously reported 2002 balances as shown below.  The reclassifications had no impact on previously reported net income or common equity.

(in thousands)
Gross electric operating revenues as previously reported	$	1,026,184
Less costs reclassified from power purchased	22,449
Net electric operating revenues	$	1,003,735
Gross power purchased as previously reported	$	84,330
Less costs reclassified to revenues	22,449
Net power purchased	$	61,881

SFAS No. 150

In May 2003, the Financial Accounting Standards Board issued SFAS No. 150, which 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 $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, 2004 and 2003, leaving 225,000 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.

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FIN 46

In January 2003, the Financial Accounting Standards Board issued FIN 46.  FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties.  FIN 46 was effective immediately for all new variable interest entities created or acquired after January 31, 2003.  For variable interest entities created or acquired prior to February 1, 2003, the provisions of FIN 46 must have been applied for the first interim or annual period beginning after June 15, 2003.

In December 2003, FIN 46 was revised, delaying the effective dates for certain entities created before February 1, 2003, and making other amendments to clarify application of the guidance.  For potential variable interest entities other than special purpose entities, FIN 46R was 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. The adoption of FIN 46 and FIN 46R has no impact on the financial position or results of operations of LG&E.

Although LG&E holds an investment interest in OVEC, it is not the primary beneficiary of OVEC and, therefore, OVEC is not consolidated into the financial statements of LG&E.

LG&E and 11 other electric utilities are participating owners of OVEC, located in Piketon, Ohio. OVEC owns and operates two power plants that burn coal to generate electricity, Kyger Creek Station in Ohio and Clifty Creek Station in Indiana.  Through March 2006, LG&E’s share is 7%, representing approximately 155 Mw of generation capacity, and 5.63% thereafter.

LG&E’s original investment in OVEC was made in 1952.  As of December 31, 2004, LG&E’s investment in OVEC totaled $0.5 million.  In March 2005, LG&E purchased from AEP an additional 0.73% interest in OVEC for a purchase price of approximately $0.1 million, which resulted in an increase in LG&E ownership in OVEC from 4.9% to 5.63%.  LG&E’s investment in OVEC is accounted for under the cost method of accounting.

LG&E’s maximum exposure to loss as a result of its involvement with OVEC is limited to the value of the investment.  In the event of the inability of OVEC to fulfill its power provision requirements, LG&E would substitute such power supply with either owned generation or market purchases and would generally recover associated incremental costs through regulatory rate mechanisms.  See Note 11 for further discussion of developments regarding LG&E’s ownership interest and power purchase rights.

FSP 106-2

In May 2004, the FASB finalized FSP 106-2 with guidance on accounting for subsidies provided under the Medicare Act which became law in December 2003.  FSP 106-2 is effective for the first interim or annual period beginning after June 15, 2004.  FSP 106-2 does not have a material impact on LG&E.

FSP 109-1

In December 2004, the FASB finalized FSP 109-1, whichrequires the tax deduction on qualified production activities to be treated as a special deduction in accordance with FAS 109.  FSP 109-1 became effective

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December 21, 2004, and does not have a material impact on LG&E.

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 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 a registered holding company under PUHCA. LG&E, as a subsidiary of a registered holding company, is subject to additional regulations under PUHCA.  In March 2003, 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.  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

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.

On June 30, 2004, the Kentucky Commission issued an order approving increases in the base electric and gas rates of LG&E.  The Kentucky Commission’s order largely accepted proposed settlement agreements filed in May 2004 by LG&E and a majority of the parties to the rate case proceedings.   The rate increases took effect on July 1, 2004.

In the Kentucky Commission’s order, LG&E was granted increases in annual base electric rates of approximately $43.4 million (7.7%) and in annual base gas rates of approximately $11.9 million (3.4%).  Other provisions of the order include decisions on certain depreciation, gas supply clause, ECR and VDT amounts or mechanisms and a termination of the ESM with respect to all periods after 2003.  The order also provided for a recovery before March 31, 2005, by LG&E of previously requested amounts relating to the ESM during 2003.

During July 2004, the AG served subpoenas on LG&E, as well as on the Kentucky Commission and its staff, requesting information regarding allegedly improper communications between LG&E and the Kentucky Commission, particularly during the period covered by the rate cases. The Kentucky Commission has procedurally reopened the rate cases for the limited purpose of taking evidence, if any, as to the communication issues. Subsequently, the AG filed pleadings with the Kentucky Commission requesting rehearing of the rate cases on certain computational components of the increased rates, including income tax, cost of removal and depreciation amounts. In August 2004, the Kentucky Commission denied the AG’s rehearing request on the cost of removal and depreciation issues, with the effect that the rate increase order is final as to these matters, subject to the parties’ rights to judicial appeals. The Kentucky Commission further agreed to hold in abeyance further proceedings in the rate cases, including the AG’s concerns about alleged improper communications,

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until the AG could file with the Kentucky Commission an investigative report regarding the latter issue. In addition, the Kentucky Commission granted a rehearing on the income tax component once the abeyance discussed above is lifted.

In September and October 2004, various proceedings were held in circuit courts in Franklin and Jefferson Counties, Kentucky regarding the scope and timing of document production or other information required or agreed to be produced under the AG’s subpoenas and matters were consolidated into the Franklin County court.  In October 2004, the AG filed a motion with the Kentucky Commission requesting that the previously granted rate increases be set aside, that LG&E resubmit any applications for rate increases and that relevant Kentucky Commission personnel be recused from participation in rate case proceedings.  In November 2004, the Franklin County, Kentucky court denied an AG request for sanctions on LG&E relating to production matters and narrowed the AG’s permitted scope of discovery.   In January 2005, the AG conducted interviews of certain Company individuals.

In January 2005, the AG submitted its report to the Franklin County, Kentucky Circuit Court in confidence.  Concurrently the AG filed a motion summarizing the report as containing evidence of improper communications and record-keeping errors by LG&E in its conduct of activities before the Kentucky Commission or other state governmental entities and requesting release of the report to such agencies.  During February 2005 the court ruled that the report be forwarded to the Kentucky Commission under continued confidential treatment to allow it to consider the report, including its impact, if any, on completing its investigation and any remaining steps in the rate cases, including ending the current abeyance.  To date, LG&E has neither seen nor requested copies of the report or its contents.

LG&E believes no improprieties have occurred in its communications with the Kentucky Commission and is cooperating with the proceedings before the AG and the Kentucky Commission.

LG&E is currently unable to determine the ultimate impact, if any, of, or any possible future actions of the AG or the Kentucky Commission arising out of, the AG’s report and investigation, including whether there will be further actions to appeal, review or otherwise challenge the granted increases in base rates.

Regulatory Assets and Liabilities

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

(in thousands)	2004		2003
VDT Costs	$	37,676	$	67,810
Unamortized loss on bonds	20,272		21,333
ARO	6,870		6,015
Merger surcredit	4,838		6,220
ESM	2,118		12,359
Rate case expenses	1,111		854
FAC	842		—
DSM	—		24
Gas supply adjustments due from customers	13,320		22,077
Gas performance base ratemaking	3,673		5,480
Manufactured gas sites	1,146		1,454
Total regulatory assets	$	91,866	$	143,626
Accumulated cost of removal of utility plant	$	220,214	$	216,491
Deferred income taxes - net	37,184		41,180
ECR	4,039		17
DSM	2,439		1,706
ARO	136		85
FAC	8		1,950
ESM	—		79
Gas supply adjustments due to customers	8,344		6,805
Total regulatory liabilities	$	272,364	$	268,313

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LG&E currently earns a return on all regulatory assets except for gas supply adjustments, ESM, FAC, 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.  See Note 1, Summary of Significant Accounting Policies.

VDT Costs - Kentucky Commission Settlement Order.  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.

In December 2001, the Kentucky Commission approved a settlement in the VDT case as well as other cases involving the depreciation rates and ESM. The order approving the settlement 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.

As mentioned, the current five-year VDT amortization period is scheduled to expire in March 2006.  As part of the settlement agreements in the electric and gas rate cases, LG&E shall file with the Kentucky Commission a plan for the future ratemaking treatment of the VDT surcredits and costs six months prior to the March 2006 expiration.  The surcredit shall remain in effect following the expiration of the fifth year until the Commission enters an order on the future disposition of VDT-related issues.

ARO.  At December 31, 2004 and 2003, LG&E had recorded $6.9 million and $6.0 million in regulatory assets and $0.1 million and $0.1 million in regulatory liabilities, respectively, related to SFAS No. 143.

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

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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.

ESM.  Prior to 2004, LG&E’s retail electric rates were subject to an ESM.  The ESM, initially in place for three years beginning in 2000, set an upper and lower point for rate of return on equity, whereby if LG&E’s rate of return for the calendar year fell within the range of 10.5% to 12.5%, no action was necessary.  If earnings were above the upper limit, the excess earnings were shared 40% with ratepayers and 60% with shareholders; if earnings were below the lower limit, the earnings deficiency was recovered 40% from ratepayers and 60% from shareholders.  By order of the Kentucky Commission, rate changes prompted by the ESM filing went 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.  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.

LG&E filed its final 2003 ESM calculations with the Kentucky Commission on March 1, 2004, and applied for recovery of $13.0 million. Based upon estimates, LG&E previously accrued $8.9 million for the 2003 ESM as of December 31, 2003.

On June 30, 2004, the Kentucky Commission issued an order largely accepting proposed settlement agreements by LG&E and all intervenors regarding the ESM.  Under the ESM settlements, LG&E will continue to collect approximately $13.0 million of previously requested 2003 ESM revenue amounts through March 2005.  As part of the settlement, the parties agreed to a termination of the ESM mechanism relating to all periods after 2003.

As a result of the settlement, LG&E accrued an additional $4.1 million in June 2004, related to 2003 ESM revenue.

FAC.  LG&E’s retail electric rates contain a FAC, whereby increases and decreases in the cost of fuel for electric generation are reflected in the rates charged to retail customers.  In January 2003, the Kentucky Commission reviewed KU’s FAC and, as part of the order in that case, required that an independent audit be conducted to examine operational and management aspects of both LG&E’s and KU’s fuel procurement functions.  The final report was issued in February 2004.  The report’s recommendations related to documentation and process improvements.  Management Audit Action Plans were agreed upon by LG&E and the Kentucky Commission Staff in the second quarter of 2004.  LG&E filed its first Audit Progress Report with the Kentucky Commission Staff in November 2004.  A second Audit Progress Report is due in May 2005.

The Kentucky Commission requires public hearings at six-month intervals to examine past fuel adjustments, and at two-year intervals to review past operations of the fuel clause and transfer of the then current fuel adjustment charge or credit to the base charges.  No significant issues have been identified as a result of these reviews.

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In December 2004, the Kentucky Commission initiated a two-year review of LG&E’s past operations of the fuel clause and transfer of fuel costs from the fuel adjustment clause to base rates.  A public hearing on the matter was held on March 17, 2005.  An order by the Kentucky Commission is expected in April 2005.  LG&E is seeking to increase the fuel component of base rates.  LG&E does not anticipate any issues will arise during the regulatory proceeding.

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 LG&E 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 evaluations.

Gas Supply Cost PBR Mechanism.   Since November 1, 1997, LG&E has operated under a PBR mechanism related to its gas procurement activities.   LG&E’s rates are adjusted annually to recover its portion of the savings (or expenses) incurred during each PBR year (12 months ending October 31). Since its implementation on November 1, 1997, through October 31, 2004, LG&E has achieved $60.7 million in savings. Of that total savings amount, LG&E’s portion has been $22.7 million and the ratepayers’ portion has been $38.0 million.  Pursuant to the extension of LG&E’s 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 filed a report and assessment with the Kentucky Commission on December 30, 2004, seeking modification and extension of the mechanism.

Accumulated Cost of Removal.  As of December 31, 2004 and 2003, LG&E has segregated the cost of removal, embedded in accumulated depreciation, of $220.2 million and $216.5 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.

ECR.  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.

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, approving 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.

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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 June 2004, the Kentucky Commission issued an order approving a settlement agreement that, among other things, revised the rate of return for LG&E’s post-1995 plan to 10.72%, with an 11% return on common equity. The order also approved the elimination of LG&E’s 1995 plan from its ECR billing mechanism, with all remaining costs associated with that plan to be included in their entirety in base rates.

In December 2004, 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, including the expansion of the landfill facility at the Mill Creek station.  The estimated capital cost of the additional facilities is $40.2 million.  LG&E requested an overall rate of return of 10.72%, including an 11% return on common equity.  A final order in the case is anticipated in June 2005.

Other Regulatory Matters

MISO.  LG&E is a founding member of the MISO.  Membership was obtained in 1998 in response to and consistent with federal policy initiatives.  In February 2002, 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 lines 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 and the rest of the MISO owners.  On February 18, 2005, the United States Court of Appeals for the District of Columbia Circuit ruled that FERC did not provide proper notice that it would consider an incentive adder of 50 basis points, but affirmed the September 2002 FERC order in all other respects.  Effective ROE, retroactive to February 1, 2002, is 12.38% for LG&E and the original 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, 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, along with several other transmission owners, again petitioned the District Court of Columbia Circuit for review. In July 2004 the court affirmed the FERC ruling.

In August 2004, the MISO filed its FERC-required proposed TEMT.  In September and October 2004, many MISO-related parties (including LG&E) filed proposals with the FERC regarding pending MISO-filed changes to transmission pricing principles, including the TEMT and elimination of RTORs. Additional filings of the companies before FERC in September 2004 sought to address issues relating to the treatment of certain GFA's should TEMT become effective. The utility proposals generally seek to appropriately delay the RTOR and TEMT effective dates based upon errors in administrative or procedural processes used by FERC or to appropriately limit potential reductions in transmission revenues received by the utilities should the RTOR, TEMT or GFA structures be implemented.  At present, existing FERC orders conditionally approve elimination of RTORs and implementation of general TEMT rates in the MISO by spring 2005.  At this time, LG&E cannot predict the outcome or effects of the various FERC proceedings described above, including whether such will have a material impact on the financial condition or results of operations of the companies. Financial consequences (changes in transmission revenues and costs) associated with the upcoming transmission market tariff changes are subject to varying assumptions and calculations and are therefore difficult to estimate. Changes in revenues and costs related to broader shifts in energy market practices and economics are not currently estimable.  Should LG&E be ordered to exit MISO, current MISO rules may also impose an exit fee.  LG&E is not able to predict the estimated outcome or economic impact of any of the MISO-related matters.  While LG&E believes legal and regulatory precedent should permit most or many of the MISO-related costs to be recovered in their rates charged to customers, they can give no assurance that state or federal regulators will ultimately agree with such position with respect to all costs, components or timing of recovery.

The MISO plans to implement a Day-ahead and Real-time market, including a congestion management system in April 2005. This system will be similar to the 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

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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, have objected to the allocation of costs among market participants and retail native load. FERC ruled in 2004 in favor of the MISO.

The Kentucky Commission opened an investigation into LG&E’s membership in the MISO in July 2003. The Kentucky Commission directed LG&E to file testimony addressing the costs and benefits of the MISO membership both currently and over the next five years and other legal issues surrounding continued membership.  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 the MISO, under certain conditions.  The MISO filed its own testimony and cost benefit analysis in December 2003.  A final Kentucky Commission order was expected in the second quarter of 2004; that ruling has since been delayed until summer 2005 due to the Kentucky Commission’s request for additional testimony on the MISO’s Market Tariff filing at FERC.

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, in July 2001 the Kentucky Commission opened Administrative Case No. 387 to review the adequacy of Kentucky’s generation capacity and transmission system.  Specifically, the items reviewed were the appropriate level of reliance on purchased power, the appropriate reserve margins to meet existing and future electric demand, the impact of spikes in natural gas prices on electric utility planning strategies, and the adequacy of Kentucky’s electric transmission facilities.  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.

Kentucky Commission Strategic Blueprint.  In February 2005, Kentucky’s Governor signed an executive order directing the Kentucky Commission, in conjunction with the Commerce Cabinet and the Environmental and Public Protection Cabinet, to ‘develop a Strategic Blueprint for the continued use and development of electric energy.’ This Strategic Blueprint will be designed to promote future investment in electric infrastructure for the Commonwealth of Kentucky, to protect Kentucky’s low-cost electric advantage, to maintain affordable rates for all Kentuckians, and to preserve Kentucky’s commitment to environmental protection.  In March 2005, the Kentucky Commission established Administrative Case No. 2005-00090 to collect information from all jurisdictional utilities in Kentucky, including LG&E, pertaining to Kentucky electric generation, transmission and distribution systems.  The Kentucky Commission must provide its Strategic Blueprint to the Governor in early August 2005.  LG&E must respond to the Kentucky Commission’s first set of data requests by the end of March 2005.

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, defined as SMD. The SMD NOPR would require each public utility that owns, operates,

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or controls interstate transmission facilities to become an 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 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.

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.

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 May 2004, in Case No. 2004-148, LG&E proposed a hedge plan for the 2004/2005 winter heating season  relying upon LG&E’s storage to mitigate customer exposure to price volatility. In August 2004, the Kentucky Commission approved LG&E’s proposed hedge plan, validating the effectiveness of storage to mitigate potential volatility associated with high winter gas prices by approving this natural gas hedge plan.  The Kentucky Commission also ordered that LG&E need not file hedge plans in the future unless it intended to utilize financial hedging instruments.

Note 4 - Financial Instruments

The cost and estimated fair values of LG&E’s non-trading financial instruments as of December 31, 2004, and 2003 follow:

(in thousands)	2004					2003
	Cost		Fair Value			Cost		Fair Value
Preferred stock subject to mandatory redemption	$	22,500	$	22,781		$	23,750	$	23,893
Long-term debt (including current portion)	$	574,304	$	575,419		$	574,304	$	576,174
Long-term debt from affiliate	$	275,000	$	280,684		$	200,000	$	206,333
Interest-rate swaps - liability	—		$	(18,542	)	—		$	(15,966	)

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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, earnings and cash flow 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 designated as a cash flow hedge 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. See Note 15, Accumulated Other Comprehensive Income.  Financial instruments designated as fair value hedges and the underlying hedged items are periodically marked to market with the resulting net gains and losses recorded directly into net income.  Upon termination of any fair value hedge, the resulting gain or loss is recorded into net income.

LG&E was party to various interest rate swap agreements with aggregate notional amounts of $228.3 million as of December 31, 2004 and 2003.  Under these swap agreements, LG&E paid fixed rates averaging 4.38%  and received variable rates based on LIBOR or the Bond Market Association’s municipal swap index averaging 1.74% and 1.11% at December 31, 2004 and 2003, respectively. The swap agreements in effect at December 31, 2004 have been designated as cash flow hedges and mature on dates ranging from 2005 to 2033.  The cash flow designation was assigned because the underlying variable rate debt has variable future cash flows. The hedges have been deemed to be fully effective resulting in a pretax gain of $2.3 million for 2004, 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 (less than $0.1 million). A deposit in the amount of $10.9 million, used as collateral for the $83.3 million interest rate swap, is classified as restricted cash on LG&E’s balance sheet. The amount of the deposit required is tied to the market value of the swap.

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, SFAS No. 138and SFAS No. 149.  Wholesale sales of excess asset capacity are treated as normal sales under  these pronouncements and are not marked to market.  To be eligible for the normal sales exclusion under SFAS No. 133, sales are limited to the forecasted excess capacity of LG&E’s generation assets over what is needed to serve native load.  To be eligible for the normal purchases exclusion under SFAS No. 133 purchases must be used to serve LG&E’s native load.  Without the normal sales and purchases exclusion these transactions would be considered derivatives and marked to market under SFAS No. 133.

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.

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No changes to valuation techniques for energy trading and risk management activities occurred during 2004.  Changes in market pricing, interest rate and volatility assumptions were made during both years.  All contracts outstanding at December 31, 2004, 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, 2004, 100% of the trading and risk management commitments were with counterparties rated BBB-/Baa3 equivalent or better.

LG&E 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 cash flow 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.  No material pre-tax gains and losses resulted from these cash flow hedges in 2004, 2003 and 2002.   See Note 15, Accumulated Other Comprehensive Income.

Accounts Receivable Securitization.  On February 6, 2001, LG&E implemented an accounts receivable securitization program. LG&E terminated the accounts receivable securitization program in January 2004, and in May 2004, LG&E dissolved its inactive accounts receivable securitization-related subsidiary, LG&E R.  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 had standard terms and were not past due.  LG&E was able to terminate the program at any time without penalty.

As part of the program, LG&E sold retail accounts receivable to 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 unrelated third-party purchasers.  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.

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.  No material pre-tax gains and losses from the sale of the receivables occurred in 2004, 2003 and 2002.  LG&E’s net cash flows from LG&E R were $(58.1) million, $(6.2) million and $20.2 million for 2004, 2003 and 2002, respectively.

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

Note 5 - Concentrations of Credit and Other Risk

Credit risk represents the accounting loss that would be recognized at the reporting date if counterparties failed to perform as contracted.  Concentrations of credit risk (whether on- or off-balance sheet) relate to groups of customers or counterparties that have similar economic or industry characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in economic or other conditions.

LG&E’s customer receivables and gas and electric revenues arise from deliveries of natural gas to approximately 318,000 customers and electricity to approximately 390,000 customers in Louisville and adjacent areas in Kentucky.  For the year ended December 31, 2004, 70% of total revenue was derived from electric operations and 30% from gas operations.

In November 2001, LG&E and IBEW Local 2100 employees, that represent approximately 72% 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, 2004, and a statement of the funded status as of December 31, 2004, for LG&E’s sponsored defined benefit plan:

(in thousands)	2004			2003			2002
Pension Plans:
Change in benefit obligation
Benefit obligation at beginning of year	$	378,691		$	364,794		$	356,293
Service cost	2,777			1,757			1,484
Interest cost	22,742			23,190			24,512
Plan amendments	3,301			3,978			576
Change due to transfers	(1,144		)	(2,759		)	—
Benefits paid	(30,520		)	(33,539		)	(34,823		)
Actuarial (gain) or loss and other	26,529			21,270			16,752
Benefit obligation at end of year	$	402,376		$	378,691		$	364,794
Change in plan assets
Fair value of plan assets at beginning of year	$	297,778		$	196,314		$	233,944
Actual return on plan assets	39,240			47,152			(15,648		)
Employer contributions	34,492			89,125			336
Change due to transfers	(1,071		)	238			13,814
Benefits paid	(30,520		)	(33,539		)	(34,824		)
Administrative expenses	(1,764		)	(1,512		)	(1,308		)
Fair value of plan assets at end of year	$	338,155		$	297,778		$	196,314
Reconciliation of funded status
Funded status	$	(64,221	)	$	(80,913	)	$	(168,480	)
Unrecognized actuarial (gain) or loss	70,304			56,219			60,313
Unrecognized transition (asset) or obligation	(1,455		)	(2,183		)	(3,199		)
Unrecognized prior service cost	31,505			32,275			32,265
Net amount recognized at end of year	$	36,133		$	5,398		$	(79,101	)
Other Benefits:
Change in benefit obligation
Benefit obligation at beginning of year	$	108,030		$	93,233		$	89,946
Service cost	895			604			444
Interest cost	6,524			6,872			5,956
Plan amendments	355			7,380			—
Benefits paid	(7,119		)	(9,313		)	(4,988		)
Actuarial (gain) or loss	4,265			9,254			1,875
Benefit obligation at end of year	$	112,950		$	108,030		$	93,233
Change in plan assets
Fair value of plan assets at beginning of year	$	674		$	1,478		$	2,802
Actual return on plan assets	(2,007		)	2,076			(533		)
Employer contributions	9,339			6,401			4,213
Change due to transfers	(105		)	—			—
Benefits paid	(7,126		)	(9,281		)	(5,004		)
Fair value of plan assets at end of year	$	775		$	674		$	1,478
Reconciliation of funded status
Funded status	$	(112,175	)	$	(107,356	)	$	(91,755	)
Unrecognized actuarial (gain) or loss	29,414			23,724			16,971
Unrecognized transition (asset) or obligation	5,357			6,027			6,697
Unrecognized prior service cost	10,036			11,482			5,995
Net amount recognized at end of year	$	(67,368	)	$	(66,123	)	$	(62,092	)

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Amounts Recognized in Statement of Financial Position. The following tables provide the amounts recognized in the balance sheet and information for plans with benefit obligations in excess of plan assets as of December 31, 2004, 2003 and 2002:

(in thousands)	2004			2003			2002
Pension Plans:
Amounts recognized in the balance sheet consisted of:
Accrued benefit liability	$	(53,197	)	$	(74,474	)	$	(162,611	)
Intangible asset	31,505			32,275			32,799
Accumulated other comprehensive income	57,825			47,597			50,711
Net amount recognized at year-end	$	36,133		$	5,398		$	(79,101	)
Increase (decrease) in minimum liability included in other comprehensive income	$	10,228		$	(3,114	)	$	25,999
Additional year-end information for plans with accumulated benefit obligations in excess of plan assets:
Projected benefit obligation	$	402,376		$	378,691		$	364,794
Accumulated benefit obligation	391,353			372,252			358,956
Fair value of plan assets	338,155			297,778			196,314
Other Benefits:
Amounts recognized in the balance sheet consisted of:
Accrued benefit liability	$	(67,368	)	$	(66,123	)	$	(62,092	)
Additional year-end information for plans with benefit obligations in excess of plan assets:
Benefit obligation	$	112,950		$	108,030		$	93,233
Fair value of plan assets	775			674			1,478

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Components of Net Periodic Benefit Cost.  The following table provides the components of net periodic benefit cost for the plans for 2004, 2003 and 2002:

(in thousands)	2004			2003			2002
Pension Plans:
Components of net periodic benefit cost
Service cost	$	2,777		$	1,756		$	1,484
Interest cost	22,742			23,190			24,512
Expected return on plan assets	(26,975		)	(22,785		)	(21,639		)
Amortization of prior service cost	4,071			3,792			3,777
Amortization of transition (asset) or obligation	(728		)	(1,016		)	(1,016		)
Amortization of actuarial (gain) or loss	1,870			2,219			21
Net periodic benefit cost	$	3,757		$	7,156		$	7,139
Other Benefits:
Components of net periodic benefit cost
Service cost	$	895		$	604		$	444
Interest cost	6,524			6,872			5,956
Expected return on plan assets	—			(51		)	(204		)
Amortization of prior service cost	1,800			1,768			920
Amortization of transition (asset) or obligation	670			670			650
Amortization of actuarial (gain) or loss	695			505			116
Net periodic benefit cost	$	10,584		$	10,368		$	7,882

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

	2004		2003		2002
Weighted-average assumptions as of December 31:
Discount rate	5.75	%	6.25	%	6.75	%
Rate of compensation increase	4.50	%	3.00	%	3.75	%

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

	2004		2003		2002
Discount rate	6.25	%	6.75	%	7.25	%
Expected long-term return on plan assets	8.50	%	9.00	%	9.50	%
Rate of compensation increase	3.50	%	3.75	%	4.25	%

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.

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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 2004	$	(283	)	$	322
Effect on year-end 2004 postretirement benefit obligations	$	(3,603	)	$	4,016

Expected Future Benefit Payments.  The following list provides the amount of expected future benefit payments, which reflect expected future service, as appropriate:

(in thousands)	Pension Plans		Other Benefits
2005	$	29,783	$	8,207
2006	$	28,878	$	8,095
2007	$	28,118	$	8,367
2008	$	27,353	$	8,520
2009	$	26,466	$	8,716
2010-2014	$	122,939	$	46,850

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

	Target Range		2004		2003		2002
Pension Plans:
Equity securities	55% - 85	%	66	%	66	%	64	%
Debt securities	20% - 40	%	33	%	33	%	34	%
Other	0% - 10	%	1	%	1	%	2	%
Totals			100	%	100	%	100	%
Other Benefits:
Equity securities	—	%	—	%	—	%	—	%
Debt securities	100	%	100	%	100	%	100	%
	100	%	100	%	100	%	100	%

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

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

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

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

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

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

Contributions.  LG&E made discretionary contributions to the pension plan of $34.5 million in January 2004 and $89.2 million during 2003.  No discretionary contributions are planned for 2005.

FSP 106-2.  In May 2004, the FASB finalized FSP 106-2 with the guidance on accounting for subsidies provided under the Medicare Act which became law in December 2003.  FSP 106-2 was effective for the first interim or annual period beginning after June 15, 2004.  The following table reflects the impact of the subsidy:

(in thousands)
Reduction in accumulated postretirement benefit obligation (“APBO”)	$	3,166
Effect of the subsidy on the measurement of the net periodic postretirement benefit cost:
Amortization of the actuarial experience gain/(loss)	$	198
Reduction in service cost due to the subsidy	0
Resulting reduction in interest cost on the APBO	198
Total	$	396

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 $1.4 million for 2004, $1.8 million for 2003, and $1.7 million for 2002.

Note 7 - Income Taxes

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

(in thousands)			2004			2003			2002
Related to operating income:
Current		- federal	$	35,190		$	30,598		$	26,231
		- state	13,358			11,007			8,083
Deferred		- federal – net	11,363			16,922			20,464
		- state – net	(800		)	1,746			4,410
Amortization of investment tax credit			(4,153		)	(4,207		)	(4,153		)
Total			54,958			56,066			55,035
Related to other income - net:
Current	- federal		(1,340		)	(4,830		)	(1,667		)
	- state		(350		)	(1,004		)	(430		)
Deferred	- federal – net		21			(129		)	(206		)
	- state – net		5			(30		)	(53		)
Total			(1,664		)	(5,993		)	(2,356		)
Total income tax expense			$	53,294		$	50,073		$	52,679

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

(in thousands)	2004		2003
Deferred tax liabilities:
Depreciation and other plant-related items	$	397,806	$	365,460
Regulatory assets and other	33,335		52,976
	431,141		418,436
Deferred tax assets:
Investment tax credit	18,638		20,314
Income taxes due to customers	15,008		16,620
Pensions and related benefits	32,219		29,508
Liabilities and other	18,043		14,290
	83,908		80,732
Net deferred income tax liability	$	347,233	$	337,704
Thereof non-current	$	342,609	$	332,796
Thereof current	4,624		4,908
	$	347,233	$	337,704

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

	2004		2003		2002
Statutory federal income tax rate	35.0	%	35.0	%	35.0	%
State income taxes, net of federal benefit	5.3		5.4		5.6
Amortization of investment tax credit	(3.6	)	(3.0	)	(2.9	)
Other differences – net	(0.9	)	(1.9	)	(0.5	)
Effective income tax rate	35.8	%	35.5	%	37.2	%

H. R. 4520, known as the “American Jobs Creation Act of 2004” allows electric utilities to take a deduction of up to 3% of their generation taxable income in 2005. On a stand-alone basis, LG&E expects to generate a deduction in 2005 which will reduce LG&E’s effective tax rate by less than 1%.

Kentucky House Bill 272, also known as Kentucky’s Tax Modernization Plan, was signed into law in March  2005.  This bill contains a number of changes in Kentucky’s tax system, including the reduction of the Corporate income tax rate from 8.25% to 7% effective January 1, 2005, and a further reduction to 6% effective January 1, 2007.  The impact of these reduced rates is expected to decrease LG&E’s income tax expense in future periods.  Furthermore, these reduced rates will result in the reversal of accumulated temporary differences at lower rates than originally provided.  LG&E is presently evaluating the impact of this and other changes to the Kentucky tax system, however, no material adverse impacts on cash flows or results of operations are expected.

LG&E is subject to periodic changes in state tax law, regulation or interpretation, as well as enforcement proceedings.  LG&E is currently undergoing a routine Kentucky sales tax audit for the period October 1997 through 2001.  The possible assessment or amount at issue is not known at this time, but is not expected to have a material adverse effect on cashflows or results of operations. 

Note 8 - Other Income (Expense) - - Net

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

(in thousands)	2004			2003			2002
Interest and dividend income (expense)	$	304		$	100		$	554
IMEA/IMPA fees	719			806			859
Gain on disposition of property	166			2			421
Terminated projects	0			(2,997		)	0
Benefits expense	0			0			(1,655		)
Other	(4,521		)	(5,104		)	(1,715		)
	$	(3,332	)	$	(7,193	)	$	(1,536	)

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Note 9 - Long-Term Debt

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

As of December 31, 2004, long-term debt and the current portion of long-term debt consists primarily of pollution control bonds and long-term loans from affiliated companies as summarized below.  Interest rates and maturities in the table below reflect the impact of interest rate swaps.

(in thousands)	Stated Interest Rates	Weighted Average Interest Rate	Maturities	Principal Amounts
Outstanding at December 31, 2004:
Noncurrent portion	Variable - 5.90%	4.39%	2008-2033	$	574,354
Current portion	Variable	1.96%	2005-2027	297,450
Outstanding at December 31, 2003:
Noncurrent portion	Variable - 5.90%	4.23%	2027-2033	$	550,604
Current portion	Variable	1.46%	2017-2027	247,450

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 2004 was 1.29%.

Pollution control series bonds are first mortgage bonds that have been issued by LG&E in connection with tax-exempt pollution control revenue bonds issued by various governmental entities, principally counties in Kentucky.  A loan agreement obligates LG&E to make debt service payments to the county that equate to the debt service due from the county on the related pollution control revenue bonds.  The county’s debt is also secured by an equal amount of LG&E’s first mortgage bonds (the pollution control series bonds) that are pledged to the trustee for the pollution control revenue bonds, and that match the terms and conditions of the county’s debt, but require no payment of principal and interest unless LG&E defaults on the loan agreement.

Substantially all of LG&E’s utility assets are 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. No portion of retained earnings was restricted by this provision as of December 31, 2004 or 2003.

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.  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.   As of December 31, 2004 and 2003, LG&E had swaps with a combined notional value of $228.3 million.  See Note 4.

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

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.

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

During 2003, LG&E entered into two long-term loans from Fidelia totaling $200 million (see Note 14).  Of this total, $100 million is unsecured with an interest rate of 4.55% and matures in April 2013.  The remaining $100 million is collateralized by a pledge of substantially all assets of LG&E that is 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 assets of LG&E.

LG&E has existing $5.875 series mandatorily redeemable preferred stock outstanding having a current redemption price of $100 per share. The preferred stock has a sinking fund requirement sufficient to retire a minimum of 12,500 shares on July 15 of each year commencing with July 15, 2003, and the remaining 187,500 shares on July 15, 2008 at $100 per share.  LG&E redeemed 12,500 shares in accordance with these provisions on July 15, 2004 and 2003, leaving 225,000 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.

See Note 11, Commitments and Contingencies for all long-term debt maturities.

Note 10 - Notes Payable and Other Short-Term Obligations

LG&E participates in an intercompany money pool agreement wherein LG&E Energy and/or 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.  The balance of the money pool loan from LG&E Energy (shown as “Notes payable to affiliated company”) was $58.2 million at an average rate of 2.22% and $80.3 million at an average rate of 1.00%, at December 31, 2004 and 2003, respectively.  The amount available to LG&E under the money pool agreement at December 31, 2004 was $341.8 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, 2004 was $65.4 million, and availability of $84.6 million remained.  LG&E Energy increased the size of its revolving credit facility to $200 million effective January 24, 2005.

During June 2004, LG&E renewed five revolving lines of credit with banks totaling $185 million.  These credit facilities expire in June 2005, and there was no outstanding balance under any of these facilities at December 31, 2004.

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.A limitation on disposing of assets aggregating more than 15% of total assets as of December 31, 2003.

In January 2004, LG&E entered into a one year loan totaling $100 million with Fidelia.  The interest rate on the loan is 1.53%, and the proceeds were used to repay notes payable to LG&E Energy under the money pool arrangement.  The loan is collateralized by a pledge of substantially all assets of LG&E that is subordinated to the first mortgage bond lien.  A prepayment of $50 million was made in 2004 and the remaining $50 million was paid at maturity in January 2005.

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Note 11 - Commitments and Contingencies

The following is provided to summarize LG&E’s contractual cash obligations for periods after December 31, 2004.  LG&E anticipates cash from operations and external financing will be sufficient to fund future obligations.  Future interest obligations cannot be quantified because most of LG&E's debt is variable rate (see LG&E's Consolidated Statements of Capitalization).

(in thousands)	Payments Due by Period
Contractual Cash Obligations	2005		2006		2007		2008		2009		Thereafter			Total
Short-term debt (a)	$	58,220	$	—	$	—	$	—	$	—	$	—		$	58,220
Long-term debt	297,450		1,250		1,250		18,750		—		553,104		(b)	871,804
Operating lease (c)	3,469		3,538		3,609		3,681		3,754		22,375			40,426
Unconditional power purchase obligations (d)	11,230		10,098		9,726		9,932		10,145		181,089			232,220
Coal and gas purchase obligations (e)	202,450		95,478		52,656		49,396		6,037		6,037			412,054
Retirement obligations (f)	9,250		10,106		13,305		10,992		15,839		—			59,492
Other long-term obligations (g)	14,767		—		—		—		—		—			14,767
Total contractual cash obligations	$	596,836	$	120,470	$	80,546	$	92,751	$	35,775	$	762,605		$	1,688,983

(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.  LG&E does not expect to pay these amounts in 2005.

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

(d)Represents future minimum payments under OVEC purchased power agreements through 2024.

(e)Represents contracts to purchase coal and natural gas.

(f)Represents currently projected contributions to pension plans and other post-employment benefit obligations as calculated by the actuary.

(g)Represents construction commitments.

Operating Leases.  LG&E leases office space, office equipment and vehicles.  LG&E accounts for its leases as operating leases.  Total lease expense for 2004, 2003 and 2002, less amounts contributed by affiliated companies occupying a portion of the office space leased by LG&E, was $2.8 million, $2.2 million, and $2.2 million, respectively.  The future minimum annual lease payments under LG&E’s office space lease agreement for years subsequent to December 31, 2004, are in the Contractual Cash Obligations table above.

Sale and Leaseback Transaction.  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 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, 2004, the maximum aggregate amount of default fees or amounts, which decrease over the term of the lease, was $9.5 million, of which LG&E would be responsible for $3.6 million (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.

Letters of Credit.  LG&E has provided letters of credit totaling $3.0 million to support certain obligations

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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 5.63% ownership in OVEC’s common stock, which is accounted for on the cost method of accounting.  Through March 2006, LG&E’s entitlement is 7% of OVEC’s generation capacity or approximately 155 Mw, and 5.63% thereafter.

In March 2005, LG&E purchased from AEP an additional 0.73% interest in OVEC for a purchase price of approximately $0.1 million, which resulted in the increase in LG&E ownership in OVEC from 4.9% to 5.63%.

Construction Program.  LG&E had approximately $14.8 million of commitments in connection with its construction program at December 31, 2004.  Construction expenditures for the years 2005 and 2006 are estimated to total approximately $268 million, although all of this amount is not currently committed, including future expenditures related to the construction of Trimble County Unit 2.

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 exempt from Phase I SO₂ requirements due to its low emission rates. LG&E opted into the Phase I NOx program to take advantage of the less stringent requirements and installed burner modifications as needed to meet these limitations.  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 the EPA on 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, the 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 31, 2004.  All LG&E generating units are in compliance with these NOx emissions reduction rules.

LG&E has added significant NOx controls to its generating units through the installation of SCR systems, advanced low-NOx burners and neural networks.  The NOx controls project commenced in late 2000 with the controls being placed into operation prior to the 2004 Summer Ozone Season. As of December 31, 2004, LG&E incurred total capital costs of approximately $186 million to reduce its NOx emissions below the 0.15 lb./MMBtu level on a company-wide basis.  In addition, LG&E will incur additional operating and maintenance costs in operating new NOx controls.  LG&E believes its costs in this regard to be comparable to those of similarly situated utilities with like generation assets. LG&E 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 Clean Air Mercury Rule which regulates mercury emissions from steam electric

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generating units and reductions in emissions of SO₂ and NOx required under the Clean Air Interstate Rule.  In addition, LG&E has worked 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 has converted the Mill Creek Station to a 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 could incur additional costs of $0.4 million for additional cleanup.  Accordingly, an accrual for this amount has been recorded in the accompanying financial statements at December 31, 2004 and 2003.

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	383			66		62		511
LG&E’s 75% ownership: (in thousands)
Cost	$	597,433
Accumulated depreciation	207,022
Net book value	$	390,411
Construction work in progress (included above)	$	4,378

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

(in thousands)		LG&E			KU			Total
Paddy’s Run 13	Ownership %	53		%	47		%	100		%
	Mw capacity	84			74			158
	Cost	$	34,033		$	30,038		$	64,071
	Depreciation	4,042			3,555			7,597
	Net book value	$	29,991		$	26,483		$	56,474
E.W. Brown 5	Ownership %	53		%	47		%	100		%
	Mw capacity	62			55			117
	Cost	$	23,978		$	20,221		$	44,199
	Depreciation	2,712			2,269			4,981
	Net book value	$	21,266		$	17,952		$	39,218
E.W. Brown 6	Ownership %	38		%	62		%	100		%
	Mw capacity	59			95			154
	Cost	$	25,353		$	38,935		$	64,288
	Depreciation	3,426			6,644			10,070
	Net book value	$	21,927		$	32,291		$	54,218
E.W. Brown 7	Ownership %	38		%	62		%	100		%
	Mw capacity	59			95			154
	Cost	$	22,718		$	36,137		$	58,855
	Depreciation	5,679			7,012			12,691
	Net book value	$	17,039		$	29,125		$	46,164
Trimble 5	Ownership %	29		%	71		%	100		%
	Mw capacity	46			114			160
	Cost	$	16,241		$	39,665		$	55,906
	Depreciation	1,363			3,327			4,690
	Net book value	$	14,878		$	36,338		$	51,216
Trimble 6	Ownership %	29		%	71		%	100		%
	Mw capacity	46			114			160
	Cost	$	16,205		$	39,703		$	55,908
	Depreciation	1,361			3,332			4,693
	Net book value	$	14,844		$	36,371		$	51,215
Trimble 7	Ownership %	37		%	63		%	100		%
	Mw capacity	59			101			160
	Cost	$	19,274		$	32,913		$	52,187
	Depreciation	355			606			961
	Net book value	$	18,919		$	32,307		$	51,226
Trimble 8	Ownership %	37		%	63		%	100		%
	Mw capacity	59			101			160
	Cost	$	19,161		$	32,762		$	51,923
	Depreciation	353			604			957
	Net book value	$	18,808		$	32,158		$	50,966
Trimble 9	Ownership %	37		%	63		%	100		%
	Mw capacity	59			101			160
	Cost	$	19,195		$	32,835		$	52,030
	Depreciation	299			512			811
	Net book value	$	18,896		$	32,323		$	51,219
Trimble 10	Ownership %	37		%	63		%	100		%
	Mw capacity	59			101			160
	Cost	$	19,141		$	32,802		$	51,943
	Depreciation	298			511			809
	Net book value	$	18,843		$	32,291		$	51,134
Trimble CT Pipeline	Ownership %	29		%	71		%	100		%
	Cost	$	1,978		$	4,813		$	6,791
	Depreciation	165			403			568
	Net book value	$	1,813		$	4,410		$	6,223
Trimble CT Substation	Ownership %	29		%	71		%	100		%
5 & 6	Cost	$	1,474		$	3,598		$	5,072
	Depreciation	76			196			272
	Net book value	$	1,398		$	3,402		$	4,800
Trimble CT Substation	Ownership %	37		%	63		%	100		%
7 - 10	Cost	$	2,856		$	4,711		$	7,567
	Depreciation	30			53			83
	Net book value	$	2,826		$	4,658		$	7,484

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In addition to these generating units, LG&E and KU share joint ownership in the Brown Inlet Air Cooling system. LG&E owns 10% of the system, attributable to Brown Unit 5, which provides an additional 10 Mw of capacity.

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
2004
Operating revenues	$	815,697	$	357,071	$	1,172,768
Depreciation and amortization	99,971		16,606		116,577
Income taxes	48,296		4,998		53,294
Interest income	223		31		254
Interest expense	27,320		5,467		32,787
Net income	87,249		8,369		95,618
Total assets	2,416,500		550,052		2,966,552
Construction expenditures	113,382		34,924		148,306
2003
Operating revenues	$	768,188	$	325,333	$	1,093,521
Depreciation and amortization	96,486		16,801		113,287
Income taxes	44,692		5,381		50,073
Interest income	27		4		31
Interest expense	25,694		4,953		30,647
Net income	80,612		10,227		90,839
Total assets	2,338,938		543,144		2,882,082
Construction expenditures	177,961		34,996		212,957
2002
Operating revenues	$	736,042	$	267,693	$	1,003,735
Depreciation and amortization	90,248		15,658		105,906
Income taxes	47,419		5,260		52,679
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

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

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Fidelia 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 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, 2004, 2003 and 2002 were as follows:

(in thousands)	2004		2003		2002
Electric operating revenues from KU	$	58,687	$	53,747	$	41,480
Electric operating revenues from LEM	374		9,372		9,939
Purchased power from KU	61,743		46,690		33,249
Purchased power from LEM	—		—		913

Interest Charges

LG&E participates in an intercompany money pool agreement wherein LG&E Energy and/or 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.  The balance of the money pool loan from LG&E Energy (shown as “Notes payable to affiliated company”) was $58.2 million at an average rate of 2.22% and $80.3 million at an average rate of 1.00%, at December 31, 2004 and 2003, respectively.  The amount available to LG&E under the money pool agreement at December 31, 2004 was $341.8 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, 2004 was $65.4 million, and availability of $84.6 million remained.  LG&E Energy increased the size of its revolving credit facility to $200 million effective January 24, 2005.

In addition, in 2003 LG&E began borrowing long-term funds from Fidelia (see Note 9).

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 LG&E relates to its receipt and payment of KU’s portion of off-system sales and purchases.

LG&E’s intercompany interest income and expense for the years ended December 31, 2004, 2003 and 2002 were as follows:

(in thousands)	2004		2003		2002
Interest on money pool loans	$	303	$	1,751	$	2,114
Interest on Fidelia loans	11,895		5,025		—
Interest expense paid to KU	44		8		61
Interest income received from KU	2		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

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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 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 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, 2004, 2003 and 2002 were as follows:

(in thousands)	2004		2003		2002
LG&E Services billings to LG&E	$	190,351	$	194,394	$	183,100
LG&E billings to KU	59,513		77,166		71,127
KU billings to LG&E	7,188		16,636		11,921
LG&E billings to LG&E Services	12,470		23,743		15,079

Note 15 – Accumulated Other Comprehensive Income

Accumulated other comprehensive income consisted of the following:

	Minimum Pension			Accumulated Derivative						Income
(in thousands)	Liability Adjustment			Gain or Loss			Pre-Tax			Taxes			Net
Balance at December 31, 2001	$	(24,712	)	$	(8,655	)	$	(33,367	)	$	(13,467	)	$	(19,900	)
Minimum pension liability adjustment	(25,999		)	—			(25,999		)	(10,493		)	(15,506		)
Gains (losses) on derivative instruments designated and qualifying as cash flow hedging instruments	—			(8,563		)	(8,563		)	(3,457		)	(5,106		)
Balance at December 31, 2002	(50,711		)	(17,218		)	(67,929		)	(27,417		)	(40,512		)
Minimum pension liability adjustment	3,114			—			3,114			1,257			1,857
Gains (losses) on derivative instruments designated and qualifying as cash flow hedging instruments	—			912			912			368			544
Balance at December 31, 2003	(47,597		)	(16,306		)	(63,903		)	(25,792		)	(38,111		)
Minimum pension liability adjustment	(10,228		)	—			(10,228		)	(4,128		)	(6,100		)
Gains (losses) on derivative instruments designated and qualifying as cash flow hedging instruments	—			(2,346		)	(2,346		)	(947		)	(1,399		)
Balance at December 31, 2004	$	(57,825	)	$	(18,652	)	$	(76,477	)	$	(30,867	)	$	(45,610	)

Note 16 - Selected Quarterly Data (Unaudited)

Selected financial data for the four quarters of 2004 and 2003 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
2004
Operating revenues	$	361,963	$	236,211	$	261,842	$	312,752
Net operating income	47,623		34,592		62,830		39,986
Net income	24,219		17,139		32,538		21,722
2003
Operating revenues	$	326,844	$	215,373	$	262,833	$	288,471
Net operating income	49,831		21,004		71,387		36,530
Net income	27,264		7,755		39,871		15,949

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Effective December 31, 2004, operating and non-operating income taxes are presented as “Federal and State Income Taxes” on LG&E’s Consolidated Statements of Income.  Prior to December 31, 2004, the component of income taxes associated with operating income was included in net operating income and the component of income taxes associated with non-operating income taxes was included in other income (expense) – net.  LG&E has applied this change in presentation to all prior periods.

	Quarters Ended
(in thousands)	March		June		September		December
2004
Net operating income as previously reported	$	32,598	$	25,219	$	41,741
Plus income taxes reclassified from total operating expenses	15,025		9,373		21,089
Net operating income	$	47,623	$	34,592	$	62,830
2003
Net operating income as previously reported	$	33,190	$	16,290	$	47,680	$	25,525
Plus income taxes reclassified from total operating expenses	16,641		4,714		23,707		11,005
Net operating income	$	49,831	$	21,004	$	71,387	$	36,530

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).

	Quarter Ended
(in thousands)	March 31, 2003
Gross operating revenues as previously reported	$	335,117
Less costs reclassified from power purchased	8,273
Net operating revenues	$	326,844

Note 17 - Subsequent Events

In January 2005, LG&E paid at maturity the $50 million loan from Fidelia using proceeds from short-term loans from the money pool.

In February 2005, Kentucky’s Governor signed an executive order directing the Kentucky Commission, in conjunction with the Commerce Cabinet and the Environmental and Public Protection Cabinet, to ‘develop a Strategic Blueprint for the continued use and development of electric energy.’ This Strategic Blueprint will be designed to promote future investment in electric infrastructure for the Commonwealth of Kentucky, to protect Kentucky’s low-cost electric advantage, to maintain affordable rates for all Kentuckians, and to preserve Kentucky’s commitment to environmental protection.  In March 2005, the Kentucky Commission established Administrative Case No. 2005-00090 to collect information from all jurisdictional utilities in Kentucky, including LG&E, pertaining to Kentucky electric generation, transmission and distribution systems.  The Kentucky Commission must provide its Strategic Blueprint to the Governor in early August 2005.  LG&E must respond to the Kentucky Commission’s first set of data requests by the end of March 2005.

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LG&E purchased from AEP an additional 0.73% interest in OVEC for a purchase price of approximately $0.1 million, resulting in an increase in LG&E ownership in OVEC from 4.9% to 5.63%.  The parties completed the share purchase transaction during March 2005.

Kentucky House Bill 272, also known as Kentucky’s Tax Modernization Plan, was signed into law in March  2005.  This bill contains a number of changes in Kentucky’s tax system, including the reduction of the Corporate income tax rate from 8.25% to 7% effective January 1, 2005, and a further reduction to 6% effective January 1, 2007.  The impact of these reduced rates is expected to decrease LG&E’s income tax expense in future periods.  Furthermore, these reduced rates will result in the reversal of accumulated temporary differences at lower rates than originally provided.  LG&E is presently evaluating the impact of this and other changes to the Kentucky tax system, however, no material adverse impacts on cash flows or results of operations are expected.

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Louisville Gas and Electric Company

REPORT OF MANAGEMENT

The management of Louisville Gas and Electric Company (“LG&E”) 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 financial statements for the three years ended December 31, 2004 have been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm.  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, 2004, did not identify any material weaknesses in the design and operation of LG&E’s internal control structure.

LG&E is not an accelerated filer under the Sarbanes-Oxley Act of 2002 and associated rules (the “Act”) and consequently anticipates issuing Management’s Certification on Internal Controls over Financial Reporting pursuant to Section 404 of the Act in its first periodic report covering the fiscal year ended December 31, 2006 as permitted by SEC rulemaking.

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 registered public accounting firm and the internal auditors have access to the Board of Directors at any time.

LG&E 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

Louisville, Kentucky

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Louisville Gas and Electric Company and Subsidiary

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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 at December 31, 2004 and December 31, 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 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 three years in the period ended December 31, 2004, listed in the index appearing under Item 15(a)(2), presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidatedfinancial statements.  These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.  We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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

Louisville, Kentucky

February 4, 2005

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INDEX OF ABBREVIATIONS

AFUDC	Allowance for Funds Used During Construction
ARO	Asset Retirement Obligation
Capital Corp.	LG&E Capital Corp.
Clean Air Act	The Clean Air Act, as amended in 1990
CCN	Certificate of Public Convenience and Necessity
CT	Combustion Turbines
CWIP	Construction Work in Progress
DSM	Demand Side Management
ECAR	East Central Area Reliability Region
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
IRP	Integrated Resource Plan
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

125

RTO	Regional Transmission Organization
S&P	Standard & Poor’s Rating Services
SCR	Selective Catalytic Reduction
SEC	Securities and Exchange Commission
SERP	Supplemental Executive 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
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

126

Kentucky Utilities Company and Subsidiary

Consolidated Statements of Income

(Thousands of $)

	Years Ended December 31
	2004		2003			2002
OPERATING REVENUES:
Total operating revenues (Notes 1 and 13)	$	995,362	$	891,778		$	861,664
OPERATING EXPENSES:
Fuel for electric generation	292,046		265,935			250,117
Power purchased (Note 11)	144,232		140,063			131,400
Other operation and maintenance expenses	222,584		221,765			222,010
Depreciation and amortization (Note 1)	108,653		101,805			95,462
Total operating expenses	767,515		729,568			698,989
Net operating income	227,847		162,210			162,675
Other income – net (Note 8 and Note 13)	7,545		4,522			6,521
Interest expense (Notes 9 and 10)	11,343		19,309			24,612
Interest expense to affiliated companies (Note 13)	14,158		5,940			1,076
Net income before income taxes	209,891		141,483			143,508
Federal and state income taxes (Note 7)	76,420		50,081			50,124
Net income	$	133,471	$		91,402	$		93,384

Consolidated Statements of Retained Earnings

(Thousands of $)

		Years Ended December 31
		2004		2003		2002
Balance January 1		$	591,170	$	502,024	$	410,896
Add net income		133,471		91,402		93,384
		724,641		593,426		504,280
Deduct:	Cash dividends declared on stock:
	4.75% cumulative preferred	950		950		950
	6.53% cumulative preferred	1,305		1,306		1,306
	Common	63,000		—		—
		65,255		2,256		2,256
Balance December 31		$	659,386	$	591,170	$	502,024

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

127

Kentucky Utilities Company and Subsidiary

Consolidated Statements of Comprehensive Income

(Thousands of $)

	Years Ended December 31
	2004			2003			2002
Net income	$	133,471		$	91,402		$	93,384
Gains (losses) on derivative instruments and hedging activities, net of tax benefit/(expense) of $(100), $99 and $1,075 for 2004, 2003 and 2002, respectively (Notes 1 and 4)	146			(147		)	(1,588		)
Additional minimum pension liability adjustment, net of tax benefit/(expense) of $4,990, $(3,098) and $7,081 for 2004, 2003 and 2002, respectively (Note 6)	(7,373		)	4,578			(10,462		)
Other comprehensive (loss) income, net of tax (Note 14)	(7,227		)	4,431			(12,050		)
Comprehensive income	$	126,244		$	95,833		$	81,334

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

128

Kentucky Utilities Company and Subsidiary

Consolidated Balance Sheets

(Thousands of $)

	December 31
	2004			2003
ASSETS:
Current assets:
Cash and cash equivalents (Note 1)	$		4,581	$		4,869
Accounts receivable-less reserve of $623 in 2004 and $672 in 2003 (Note 4)	112,580			49,289
Materials and supplies - at average cost:
Fuel (predominantly coal) (Note 1)	52,249			45,538
Other (Note 1)	27,972			27,094
Prepayments and other	9,910			13,100
	207,292			139,890
Other property and investments - less reserve of $131 in 2004 and $130 in 2003 (Note 1)	20,478			17,862
Utility plant, at original cost (Note 1)	3,571,166			3,193,145
Less: reserve for depreciation	1,415,008			1,360,253
	2,156,158			1,832,892
Construction work in progress	140,983			403,512
	2,297,141			2,236,404
Deferred debits and other assets:
Unamortized debt expense (Note 1)	4,732			4,481
Regulatory assets (Note 3)	61,435			72,318
Long-term derivative asset	6,102			12,223
Other	13,259			21,916
	85,528			110,938
	$	2,610,439		$	2,505,094

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

129

Kentucky Utilities Company and Subsidiary

Consolidated Balance Sheets(continued)

(Thousands of $)

	December 31
	2004		2003
CAPITAL AND LIABILITIES:
Current liabilities:
Current portion of long-term debt:
Current portion of long-term bonds (Note 9)	$	87,130	$	91,930
Current portion of long-term notes to affiliated company	75,000		—
	162,130		91,930
Notes payable to affiliated company (Notes 10 and 13)	34,820		43,231
Accounts payable	77,885		69,947
Accounts payable to affiliated companies (Note 13)	32,834		26,426
Accrued income taxes	5,889		7,104
Customer deposits	14,998		13,453
Other	15,338		14,245
	181,764		174,406
	343,894		266,336
Long-term debt (see statements of capitalization):
Long-term bonds (Note 9)	306,081		312,646
Long-term notes to affiliated company (Note 9)	258,000		283,000
	564,081		595,646
Deferred credits and other liabilities:
Accumulated deferred income taxes (Notes 1 and 7)	282,635		261,258
Investment tax credit, in process of amortization	3,805		5,859
Accumulated provision for pensions and related benefits (Note 6)	77,915		103,101
Asset retirement obligations	20,953		19,698
Regulatory liabilities (Note 3):
Accumulated cost of removal of utility plant	266,805		256,744
Other	24,718		38,027
Other	16,960		10,741
	693,791		695,428
Commitments and contingencies (Note 11)
Cumulative preferred stock (see statements of capitalization)	39,727		39,727
Common equity (see statements of capitalization)	968,946		907,957
	$	2,610,439	$	2,505,094

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

130

Kentucky Utilities Company and Subsidiary

Consolidated Statements of Cash Flows

(Thousands of $)

	Years Ended December 31
	2004			2003			2002
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	133,471		$	91,402		$	93,384
Items not requiring cash currently:
Depreciation and amortization	108,653			101,805			95,462
Deferred income taxes - net	16,597			15,278			(2,038		)
Investment tax credit - net	(2,054		)	(2,641		)	(2,955		)
VDT amortization	11,754			12,030			11,500
Deferred storm costs	(3,562		)	—			—
Other	(4,239		)	16,112			12,784
Change in certain net current assets:
Accounts receivable	(13,291		)	(401		)	(8,497		)
Materials and supplies	(7,589		)	(134		)	(2,928		)
Accounts payable	14,346			999			10,225
Accrued income taxes	(1,215		)	3,854			(15,565		)
Prepayments and other	5,828			(2,851		)	(2,350		)
Sale of accounts receivable (Note 4)	(50,000		)	700			4,200
Pension funding	(43,409		)	(10,231		)	(15,283		)
Earnings sharing mechanism receivable	9,267			1,118			—
Environmental cost recovery mechanism refundable	(8,013		)	6,227			2,326
Litigation settlement	11,386			—			—
Other	7,990			98			(4,508		)
Net cash provided by operating activities	185,920			233,365			175,757
CASH FLOWS FROM INVESTING ACTIVITIES:
Long-term investments	(57		)	140			—
Construction expenditures	(157,579		)	(341,869		)	(237,909		)
Net cash used for investing activities	(157,636		)	(341,729		)	(237,909		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Long-term borrowings from affiliated company	50,000			283,000			—
Short-term borrowings from affiliated company	497,750			655,241			518,400
Repayment of short-term borrowings from affiliated company	(506,161		)	(731,500		)	(446,700		)
Retirement of first mortgage bonds	—			(95,000		)	—
Issuance of pollution control bonds	50,000			—			133,930
Issuance expense on pollution control bonds	(2,126		)	(1,643		)	(5,196		)
Retirement of pollution control bonds	(54,800		)	—			(133,930		)
Interest rate swap settlement	2,020			—			—
Payment of dividends	(65,255		)	(2,256		)	(2,256		)
Net cash (used for) provided by financing activities	(28,572		)	107,842			64,248
Change in cash and cash equivalents	(288		)	(522		)	2,096
Cash and cash equivalents at beginning of year	4,869			5,391			3,295
Cash and cash equivalents at end of year	$	4,581		$	4,869		$	5,391
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Income taxes	$	58,203		$	37,166		$	59,580
Interest on borrowed money	15,641			20,204			37,866
Interest to affiliated companies on borrowed money	13,164			3,533			1,725

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

131

Kentucky Utilities Company and Subsidiary

Consolidated Statements of Capitalization

(Thousands of $)

				December 31
				2004			2003
LONG-TERM DEBT (Note 9):
First mortgage bonds -
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
Pollution control series:
9, due December 1, 2023, 5.75%				—			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 %				2,400			7,200
15, due February 1, 2032, variable %				7,400			7,400
16, due October 1, 2032, variable %				96,000			96,000
17, due October 1, 2034, variable %				50,000			—
Notes payable to Fidelia:
Due April 30, 2013, 4.55%, unsecured				100,000			100,000
Due August 15, 2013, 5.31%, secured				75,000			75,000
Due November 24, 2010, 4.24%, secured				33,000			33,000
Due December 19, 2005, 2.29%, secured				75,000			75,000
Due January 16, 2012, 4.39%, unsecured				50,000			—
Long-term debt marked to market (Note 4)				8,181			14,746
Total long-term debt outstanding				726,211			687,576
Less current portion of long-term debt				162,130			91,930
Long-term debt				564,081			595,646
CUMULATIVE PREFERRED STOCK:
	Shares Outstanding	Current Redemption Price
Without par value, 5,300,000 shares authorized -
4.75% series, $100 stated value redeemable on 30 days notice by KU	200,000	$	101.00	20,000			20,000
6.53% series, $100 stated value	200,000	$	102.94	20,000			20,000
Preferred stock expense				(273		)	(273		)
				39,727			39,727
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 (Note 14)				(13,258		)	(6,031		)
Retained earnings				647,300			581,644
Undistributed subsidiary earnings				12,086			9,526
Total retained earnings				659,386			591,170
				968,946			907,957
Total capitalization				$	1,572,754		$	1,543,330

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

132

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 an exempt 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.  In May 2004, KU dissolved its accounts receivable securitization-related subsidiary, KU R.  Prior to May 2004, 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 is a registered public utility holding company under PUHCA.

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

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

Certain reclassification entries have been made to the previous years’ financial statements to conform to the 2004 presentation with no impact on the balance sheet net assets or previously reported income.  Effective December 31, 2004, operating and non-operating income taxes are presented as “Federal and State Income Taxes” on KU’s Consolidated Statements of Income.  Prior to December 31, 2004, the component of income taxes associated with operating income was included in net operating income and the component of income taxes associated with non-operating income taxes was included in other income (expense) – net.  KU has applied this change in presentation to all prior periods.

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, 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 based on specific ratemaking decisions or precedent for each item.   See Note 3 for additional detail regarding regulatory assets and liabilities.

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

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

Depreciation and Amortization.  Depreciation is provided on the straight-line method over the estimated service lives of depreciable plant.  The amounts provided were approximately 3.1% in 2004, 3.1% in 2003 and

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3.1% in 2002, of average depreciable plant. Of the amount provided for depreciation at December 31, 2004 and 2003, approximately 0.5% and 0.6%, respectively, was related to the retirement, removal and disposal costs of long lived assets.

Cash and Cash Equivalents.  KU considers all debt instruments purchased with a maturity of three months or less to be cash equivalents.

Fuel Inventory.  Fuel inventories of $52.2 million and $45.5 million at December 31, 2004 and 2003, 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 $28.0 million and $27.1 million at December 31, 2004 and 2003, 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.  Wholesale sales of excess asset capacity and wholesale purchases are treated as normal sales and purchases under SFAS No. 133, SFAS No. 138 and SFAS No. 149 and are not marked-to-market.  See Note 4, Financial Instruments and Note 14, Accumulated Other Comprehensive Income.

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

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

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

Income Taxes. Income taxes are accounted for under SFAS No. 109.  In accordance with this statement, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, as measured by enacted tax rates that are expected to be in effect in the periods when the deferred tax assets and liabilities are expected to be settled or realized. Significant judgment is required in determining the provision for income taxes, and there are many transactions for which the ultimate tax outcome is uncertain.  To provide for these uncertainties or exposures, an allowance is maintained for tax contingencies, the balance of which management believes is adequate.  Tax contingencies are analyzed periodically and adjustments are made when events occur to warrant a change.  The company is currently in the examination phase of IRS audits for the years 1999 to 2003 and expects some or all of these audits to be completed within the next 12 months.  The results of audit assessments by taxing authorities are not anticipated to have a material adverse effect on cash flows or results of operations.

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

134

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 $47.5 million and $38.7 million at December 31, 2004, and 2003, respectively.

Allowance for Doubtful Accounts.  At December 31, 2004 and 2003, the KU allowance for doubtful accounts was $0.6 million and $0.7 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.

Other Property and Investments.  Other property and investments on the Balance Sheet consists of KU’s investment in EEI, economic development loans provided to various communities in KU’s service territory, KU’s investment in OVEC, funds related to KU’s long-term purchased power contract with OMU and non-utility plant.   KU’s investment in EEI is accounted for under the equity method of accounting and, as of December 31, 2004 and 2003, totaled $13.4 million and $10.8 million, respectively.  KU’s investment in OVEC is accounted for under the cost method of accounting.  As of December 31, 2004 and 2003, KU’s investment in OVEC totaled $0.3 million.  KU is not the primary beneficiary of EEI or OVEC, and, therefore, neither are consolidated into the financial statements of KU.

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 probable 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 issued that affected KU in 2003:

SFAS No. 143

SFAS No. 143 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.  As of January 1, 2003, KU recorded 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.  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

135

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, 2004, KU recorded ARO assets, net of accumulated depreciation, of $6.7 million and liabilities of $21 million.  As of December 31, 2003, KU recorded ARO assets, net of accumulated depreciation, of $6.9 million and liabilities of $19.7 million.  KU recorded offsetting regulatory assets of $12.8 million and $11.3 million and regulatory liabilities of $1.4 million and $1.2 million as of December 31, 2004 and 2003, respectively.

For the year ended December 31, 2004, KU recorded ARO accretion expense of $1.3 million, ARO depreciation expense of $0.2 million and an offsetting regulatory credit in the income statement of $1.5 million, pursuant to regulatory treatment prescribed under SFAS No. 71. 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.  SFAS No. 143 has no impact on the results of operations 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 years ended December 31, 2004 and 2003, KU recorded $0.3 million for both periods, 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, 2004 and 2003, KU has segregated this cost of removal, embedded in accumulated depreciation, of $266.8 million and $256.7 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 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.

EITF No. 02-03

KU adopted EITF No. 98-10effective 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.  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

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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 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 2002 balances as shown below.  The reclassifications had no impact on previously reported net income or common equity.

(in thousands)
Gross electric operating revenues as previously reported	$		888,219
Less costs reclassified from power purchased	26,555
Net electric operating revenues	$	861,664
Gross power purchased as previously reported	$	157,955
Less costs reclassified to revenues	26,555
Net power purchased	$	131,400

SFAS No. 150

In May 2003, the Financial Accounting Standards Board issued SFAS No. 150, which 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.

FIN 46

In January 2003, the Financial Accounting Standards Board issued FIN 46.  FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties.  FIN 46 was effective immediately for all new variable interest entities created or acquired after January 31, 2003.  For variable interest entities created or acquired prior to February 1, 2003, the provisions of FIN 46 must have been applied for the first interim or annual period beginning after June 15, 2003.

In December 2003, FIN 46 was revised, delaying the effective dates for certain entities created before February 1, 2003, and making other amendments to clarify application of the guidance.  For potential variable interest entities other than special purpose entities, FIN 46R was 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.  The adoption of FIN 46 and FIN 46R has no impact on the financial position or results of operations for KU.

Although KU holds investment interests in OVEC and EEI, it is not the primary beneficiary of OVEC or EEI, and, therefore, neither are consolidated into the financial statements of KU.

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KU and 11 other electric utilities are participating owners of OVEC, located in Piketon, Ohio.  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%, representing approximately 55 Mw of generation capacity.

KU’s original investment in OVEC was made in 1952.  KU’s investment in OVEC is the equivalent of 2.5% of OVEC’s common stock and is accounted for under the cost method of accounting.  As of December 31, 2004, KU’s investment in OVEC totaled $0.3 million. KU’s maximum exposure to loss as a result of the involvement with OVEC is limited to the value of the investment.  In the event of the inability of OVEC to fulfill its power provision requirements, KU would substitute such power supply with either owned generation or market purchases and would generally recover associated incremental costs through regulatory rate mechanisms.  See Note 11 for further discussion of developments regarding KU’s ownership interests and power purchase rights.

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 generated by KU.  This contract governing the purchases from EEI will terminate on December 31, 2005.  Such power equated to approximately 10% of KU’s net generation system output in 2004.

KU’s original investment in EEI was made in 1953.  KU’s investment in EEI is accounted for under the equity method of accounting and, as of December 31, 2004, totaled $13.4 million.  KU’s direct exposure to loss as a result of its involvement with EEI is generally limited to the value of its investment.  In the event of the inability of EEI to fulfill its power provision requirements, KU would substitute such power supply with either owned generation or market purchases and would generally recover associated incremental costs through regulatory rate mechanisms.

FSP 106-2

In May 2004, the FASB finalized FSP 106-2 with guidance on accounting for subsidies provided under the Medicare Act which became law in December 2003.  FSP 106-2 is effective for the first interim or annual period beginning after June 15, 2004.  FSP 106-2 does not have a material impact on KU.

FSP 109-1

In December 2004, the FASB finalized FSP 109-1, whichrequires the tax deduction on qualified production activities to be treated as a special deduction in accordance with FAS 109.  FSP 109-1 became effective December 21, 2004, and does not have a material impact on KU.

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 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 a registered holding company under PUHCA.  KU, as a subsidiary of a registered holding company, is subject to additional regulations under PUHCA.  In March 2003, 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.  In early 2004, LG&E Energy commenced direct reporting arrangements to E.ON.

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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

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.

On June 30, 2004, the Kentucky Commission issued an order approving an increase in the base electric rates of KU.  The Kentucky Commission’s order largely accepted proposed settlement agreements filed in May 2004 by KU and a majority of the parties to the rate case proceedings.   The rate increase took effect on July 1, 2004.

In the Kentucky Commission’s order, KU was granted an increase in annual base electric rates of approximately $46.1 million (6.8%).  Other provisions of the order include decisions on certain depreciation, ECR and VDT amounts or mechanisms and a termination of the ESM with respect to all periods after 2003.  The order also provided for a recovery before March 31, 2005, by KU of previously requested amounts relating to the ESM during 2003.

During July 2004, the AG served subpoenas on KU, as well as on the Kentucky Commission and its staff, requesting information regarding allegedly improper communications between KU and the Kentucky Commission, particularly during the period covered by the rate case. The Kentucky Commission has procedurally reopened the rate case for the limited purpose of taking evidence, if any, as to the communication issues. Subsequently, the AG filed pleadings with the Kentucky Commission requesting rehearing of the rate case on certain computational components of the increased rates, including income tax, cost of removal and depreciation amounts. In August 2004, the Kentucky Commission denied the AG’s rehearing request on the cost of removal and depreciation issues, with the effect that the rate increase order is final as to these matters, subject to the parties’ rights to judicial appeals. The Kentucky Commission further agreed to hold in abeyance further proceedings in the rate case, including the AG’s concerns about alleged improper communications, until the AG could file with the Kentucky Commission an investigative report regarding the latter issue. In addition, the Kentucky Commission granted a rehearing on the income tax component once the abeyance discussed above is lifted.

In September and October 2004, various proceedings were held in circuit courts in Franklin and Jefferson Counties, Kentucky regarding the scope and timing of document production or other information required or agreed to be produced under the AG’s subpoenas and matters were consolidated into the Franklin County court.  In October 2004, the AG filed a motion with the Kentucky Commission requesting that the previously granted rate increase be set aside, that KU resubmit any applications for rate increases and that relevant Kentucky Commission personnel be recused from participation in rate case proceedings.  In November 2004, the Franklin County, Kentucky court denied an AG request for sanctions on KU relating to production matters and narrowed the AG’s permitted scope of discovery.   In January 2005, the AG conducted interviews of certain Company individuals.

In January 2005, the AG submitted its report to the Franklin County, Kentucky Circuit Court in confidence.  Concurrently the AG filed a motion summarizing the report as containing evidence of improper communications and record-keeping errors by KU in its conduct of activities before the Kentucky Commission or other

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state governmental entities and requesting release of the report to such agencies.  During February 2005 the court ruled that the report be forwarded to the Kentucky Commission under continued confidential treatment to allow it to consider the report, including its impact, if any, on completing its investigation and any remaining steps in the rate case, including ending the current abeyance.  To date, KU has neither seen nor requested copies of the report or its contents.

KU believes no improprieties have occurred in its communications with the Kentucky Commission and is cooperating with the proceedings before the AG and the Kentucky Commission.

KU is currently unable to determine the ultimate impact, if any, of, or any possible future actions of the AG or the Kentucky Commission arising out of, the AG’s report and investigation, including whether there will be further actions to appeal, review or otherwise challenge the granted increase in base rates.

Regulatory Assets and Liabilities

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

(in thousands)	2004				2003
VDT costs	$		14,697		$		26,451
Unamortized loss on bonds	11,370				10,511
ARO	12,844				11,322
Merger surcredit	3,745				4,815
ESM	3,115				12,382
Rate case expenses	1,136				1,041
FAC	9,375				4,298
Deferred storm costs	3,562				—
Post retirement and pension	1,181				1,006
Management audit	410				492
Total regulatory assets	$			61,435	$		72,318
Accumulated cost of removal of utility plant	$	266,805			$	256,744
Deferred income taxes - net	19,277				24,058
ECR	1,176				9,189
DSM	1,640				1,563
ARO	1,415				1,162
FAC	119				1,000
Spare parts	1,091				1,055
Total regulatory liabilities	$		291,523		$	294,771

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.  See Note 1, Summary of Significant Accounting Policies.

VDT Costs - Kentucky Commission Settlement Order.  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

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relating to these first quarter 2001 charges.  The application requested permission to amortize these costs over a four-year period.  The Kentucky Commission also opened a case to review a new depreciation study and resulting depreciation rates implemented in 2001.

In December 2001, the Kentucky Commission approved a settlement in the VDT case as well as other cases involving the depreciation rates and ESM. The order approving the settlement 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.

As mentioned, the current five-year VDT amortization period is scheduled to expire in March 2006.  As part of the settlement agreements in the electric and gas rate cases, KU shall file with the Kentucky Commission a plan for the future ratemaking treatment of the VDT surcredits and costs six months prior to the March 2006 expiration.  The surcredit shall remain in effect following the expiration of the fifth year until the Commission enters an order on the future disposition of VDT-related issues.

ARO.  At December 31, 2004 and 2003, KU had recorded approximately $12.8 million and $11.3 million in regulatory assets and approximately $1.4 million and $1.2 million in regulatory liabilities, respectively, related to SFAS No. 143.

Merger Surcredit.  As part of the LG&E Energy merger with KU Energy in 1998, KU estimated non-fuel savings over a ten-year period following the merger.  Costs to achieve these savings for KU of $42.3 million were recorded in the second quarter of 1998, $20.5 million of which was deferred and amortized over a five-year period pursuant to regulatory orders.  Primary components of the merger costs were separation benefits, relocation costs, and transaction fees, the majority of which were paid by December 31, 1998.  KU expensed the remaining costs associated with the merger ($21.8 million) in the second quarter of 1998.

In approving the merger, the Kentucky Commission adopted KU’s proposal to reduce its retail customers’ bills based on one-half of the estimated merger-related savings, net of deferred and amortized amounts, over a five-year period.  The surcredit mechanism provides that 50% of the net non-fuel cost savings estimated to be achieved from the merger be provided to ratepayers through a monthly bill credit, and 50% be retained by KU and LG&E, 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.  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.

ESM.  Prior to 2004, KU’s Kentucky retail electric rates were subject to an ESM.  The ESM, initially in place for three years beginning in 2000, set an upper and lower point for rate of return on equity, whereby if KU’s rate of return for the calendar year fell within the range of 10.5% to 12.5%, no action was necessary.  If earnings were above the upper limit, the excess earnings were shared 40% with ratepayers and 60% with shareholders; if earnings were below the lower limit, the earnings deficiency was recovered 40% from ratepayers and 60% from shareholders.  By order of the Kentucky Commission, rate changes prompted by the ESM filing went into effect in April of

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each year subject to a balancing adjustment in successive periods.  There is no ESM for Virginia retail electric rates.

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.  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.

KU filed its final 2003 ESM calculations with the Kentucky Commission on March 1, 2004, and applied for recovery of $16.2 million. Based upon estimates, KU previously accrued $9.3 million for the 2003 ESM as of December 31, 2003.

On June 30, 2004, the Kentucky Commission issued an order largely accepting proposed settlement agreements by KU and all intervenors regarding the ESM.  Under the ESM settlements, KU will continue to collect approximately $16.2 million of previously requested 2003 ESM revenue amounts through March 2005.  As part of the settlement, the parties agreed to a termination of the ESM mechanism relating to all periods after 2003.

As a result of the settlement, KU accrued an additional $6.9 million in June 2004, related to 2003 ESM revenue.

FAC.  KU’s retail electric rates contain a FAC, whereby increases or decreases in the cost of fuel for electric generation are reflected in the rates charged to retail electric customers.  In January 2003, the Kentucky Commission reviewed KU’s FAC for the six month period ended October 31, 2001. 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.  Management Audit Action Plans were agreed upon by KU and the Kentucky Commission Staff in the second quarter of 2004.  KU filed its first Audit Progress Report with the Kentucky Commission Staff in November 2004.  A second Audit Progress Report is due in May 2005.

In December 2004, the Kentucky Commission initiated a two-year review of KU’s past operations of the fuel clause and transfer of fuel costs from the fuel adjustment clause to base rates.   A public hearing on the matter was held on March 17, 2005.  An order by the Kentucky Commission is expected in April 2005.  KU is seeking to increase the fuel component of base rates.  KU does not anticipate any issues will arise during the regulatory proceeding.

In February 2005, KU filed with the Virginia Commission an application seeking approval of an increase in its fuel cost factor to reflect higher fuel costs incurred. KU anticipates implementing the increased fuel cost factor with April 2005 billings.

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.

DSM.  In May 2001, the Kentucky Commission approved a plan that would expand LG&E’s DSM programs into the service territory served by KU.  The plan included a rate mechanism that provided for concurrent

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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.

Deferred Storm Costs.  Based on an order from the Kentucky Commission in September 2004, KU reclassified from maintenance expense to a regulatory asset, $4.0 million related to costs not reimbursed from the 2003 ice storm.  These costs will be amortized through June 2009.  KU earns a return of these amortized costs, which are included in KU’s jurisdictional operating expenses.

Accumulated Cost of Removal.  As of December 31, 2004 and 2003, KU has segregated the cost of removal, embedded in accumulated depreciation, of $266.8 million and $256.7 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.

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 facilities.  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 adjustments 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.

In June 2004, the Kentucky Commission issued an order approving a settlement agreement that, among other things, revised the rate of return for KU’s post-1994 plan to 11.19%, with an 11% return on common equity.  The order also approved the elimination of KU’s 1994 Plan for its ECR billing mechanism, with all remaining costs associated with that plan to be included in their entirety in base rates.

In December 2004, KU filed an application with the Kentucky Commission for approval of a CCN to construct new SO₂ control technology (FGDs) at the Ghent and Brown stations, and to amend its compliance plan to allow recovery of new and additional environmental compliance facilities.  The estimated capital cost of the additional facilities is $702.5 million, of which $658.9 million is for the FGDs.  A final order in the case is expected in June 2005.

Other Regulatory Matters

MISO.  KU is a founding member of the MISO.  Membership was obtained in 1998 in response to and consistent with federal policy initiatives.  In February 2002, KU turned over operational control of its 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 and the rest of the MISO owners.  On February 18, 2005, the United States Court of Appeals for the District of Columbia Circuit ruled that FERC did not provide proper notice that it would consider an incentive adder of 50 basis

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points, but affirmed the September 2002 FERC order in all other respects.  Effective ROE, retroactive to February 1, 2002, is 12.38% for KU and the original 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, 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, along with several other transmission owners, again petitioned the District Court of Columbia Circuit for review. In July 2004, the court affirmed the FERC ruling.

In August 2004, the MISO filed its FERC-required proposed TEMT.  In September and October 2004, many MISO-related parties (including KU) filed proposals with the FERC regarding pending MISO-filed changes to transmission pricing principles, including the TEMT and elimination of RTORs. Additional filings of the companies before FERC in September 2004 sought to address issues relating to the treatment of certain GFA's should TEMT become effective. The utility proposals generally seek to appropriately delay the RTORs and TEMT effective dates based upon errors in administrative or procedural processes used by FERC or to appropriately limit potential reductions in transmission revenues received by the utilities should the RTORs, TEMT or GFA structures be implemented.  At present, existing FERC orders conditionally approve elimination of RTORs and implementation of general TEMT rates in the MISO by spring 2005.  At this time, KU cannot predict the outcome or effects of the various FERC proceedings described above, including whether such will have a material impact on the financial condition or results of operations of the companies. Financial consequences (changes in transmission revenues and costs) associated with the upcoming transmission market tariff changes are subject to varying assumptions and calculations and are therefore difficult to estimate. Changes in revenues and costs related to broader shifts in energy market practices and economics are not currently estimable.  Should KU be ordered to exit MISO, current MISO rules may also impose an exit fee.  KU is not able to predict the estimated outcome or economic impact of any of the MISO-related matters.  While KU believes legal and regulatory precedent should permit most or many of the MISO-related costs to be recovered in their rates charged to customers, they can give no assurance that state or federal regulators will ultimately agree with such position with respect to all costs, components or timing of recovery.

The MISO plans to implement a Day ahead and Real-time market, including a congestion management system in April 2005. This system will be similar to the 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, have objected to the allocation of costs among market participants and retail native load. FERC ruled in 2004 in favor of the MISO.

The Kentucky Commission opened an investigation into KU’s membership in the MISO in July 2003. The Kentucky Commission directed KU to file testimony addressing the costs and benefits of the MISO membership both currently and over the next five years and other legal issues surrounding continued membership.  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 the MISO, under certain conditions.  The MISO filed its own testimony and cost benefit analysis in December 2003.  A final Kentucky Commission order was expected in the second quarter of 2004; that ruling has since been delayed until summer 2005 due to the Kentucky Commission’s request for additional testimony on the MISO’s Market Tariff filing at FERC.

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, in July 2001 the Kentucky Commission opened Administrative Case No. 387 to review the adequacy of Kentucky’s generation capacity and transmission system.  Specifically, the items reviewed were the appropriate level of reliance on purchased power, the appropriate reserve margins to meet existing and future electric demand, the impact of spikes in natural gas prices on electric utility planning strategies, and the adequacy of Kentucky’s electric transmission facilities.  In December 2001, the Kentucky Commission issued an order in which it noted that KU is responsibly addressing the long-term supply needs of native load customers and that current reserve margins are appropriate.  However, due to the rapid pace of change in the industry, the order also requires KU to provide an annual assessment of supply resources, future demand, reserve margin, and the need for new resources.

Regarding the transmission system, the Kentucky Commission concluded that the transmission system within Kentucky can reliably serve native load and a significant portion of the proposed new unregulated power plants.

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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.

Kentucky Commission Strategic Blueprint.  In February 2005, Kentucky’s Governor signed an executive order directing the Kentucky Commission, in conjunction with the Commerce Cabinet and the Environmental and Public Protection Cabinet, to ‘develop a Strategic Blueprint for the continued use and development of electric energy.’ This Strategic Blueprint will be designed to promote future investment in electric infrastructure for the Commonwealth of Kentucky, to protect Kentucky’s low-cost electric advantage, to maintain affordable rates for all Kentuckians, and to preserve Kentucky’s commitment to environmental protection.  In March 2005, the Kentucky Commission established Administrative Case No. 2005-00090 to collect information from all jurisdictional utilities in Kentucky, including KU, pertaining to Kentucky electric generation, transmission and distribution systems.  The Kentucky Commission must provide its Strategic Blueprint to the Governor in early August 2005.  KU must respond to the Kentucky Commission’s first set of data requests by the end of March 2005.

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, defined as SMD. The SMD NOPR would require each public utility that owns, operates, or controls interstate transmission facilities to become an 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 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.

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.

Note 4 - Financial Instruments

The cost and estimated fair values of KU’s non-trading financial instruments as of December 31, 2004, and 2003 follow:

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	2004						2003
				Fair					Fair
(in thousands)	Cost			Value			Cost		Value
Long-term debt (including current portion)	$	385,030		$	393,484		$	389,830	$	405,439
Long-term debt from affiliate	$		333,000	$		336,969	$	283,000	$	288,292
Interest-rate swaps - asset	—			$		6,102	—		$	12,223

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, earnings and cash flow 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 and the underlying hedged items are periodically marked to market with the resulting net gains and losses recorded directly into net income.  Upon termination of any fair value hedge, the resulting gain or loss is recorded into net income. 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 designated as a cash flow hedge 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, 2004 and 2003, KU was party to various interest rate swap agreements with aggregate notional amounts of $103 million in 2004 and $153 million 2003.  Under these swap agreements, KU paid variable rates based on either LIBOR or the Bond Market Association’s municipal swap index averaging 3.29% and 1.85%, and received fixed rates averaging 7.74% and 7.13% at December 31, 2004 and 2003, respectively. The swap agreements in effect at December 31, 2004 have been designated as fair value hedges and mature on dates ranging from 2007 to 2025.  The fair value designation was assigned because the underlying fixed rate debt has a firm future commitment.  For 2004 and 2003, the effect of marking these financial instruments and the underlying debt to market resulted in immaterial pretax gains (less than $0.1 million) recorded in interest expense.

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, 2004, KU’s debt reflects a $8.2 million mark-to-market adjustment.

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, SFAS No. 138and SFAS No. 149.  Wholesale sales of excess asset capacity are treated as normal sales under  these pronouncements and are not marked to market.  To be eligible for the normal sales exclusion under SFAS No. 133, sales are limited to the forecasted excess capacity of KU’s generation assets over what is needed to serve KU’s native load.  To be eligible for the normal purchases exclusion under SFAS No. 133

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purchases must be used to serve KU’s native load.  Without the normal sales and purchases exclusion these transactions would be considered derivatives and marked to market under SFAS No. 133.

The rescission of EITF 98-10, effective for fiscal years 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 98-10 are also within the scope of SFAS No. 133.

No changes to valuation techniques for energy trading and risk management activities occurred during 2004.  Changes in market pricing, interest rate and volatility assumptions were made during both years.  All contracts outstanding at December 31, 2004, 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, 2004, 100% of the trading and risk management commitments were with counterparties rated BBB-/Baa3 equivalent or better.

KU hedges the price volatility of its forecasted peak electric off-system sales with the sales of market-traded electric forward contracts for periods less than one year.  These electric forward sales have been designated as cash flow 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. No material pre-tax gains and losses resulted from these cash flow hedges in 2004, 2003 and 2002. See Note 14, Accumulated Other Comprehensive Income.

Accounts Receivable Securitization.   On February 6, 2001, KU implemented an accounts receivable securitization program.  KU terminated the accounts receivable securitization program in January 2004, and in May 2004, KU dissolved its inactive accounts receivable securitization-related subsidiary, KU R.  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 had standard terms and were not past due.  KU was able to terminate this program at any time without penalty.

As part of the program, KU sold retail accounts receivable to 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 unrelated third-party purchasers.  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 purchasers.  KU obtained an opinion from independent legal counsel indicating these transactions qualified as a true sale of receivables.

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To determine KU’s retained interest, the proceeds on the sale of receivables to the financial institutions were 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.  No material pre-tax gains and losses resulted from the sale of the receivables in 2004, 2003 and 2002.  KU’s net cash flows from KU R were $(50.1) million, $(0.1) million, and $3.3 million for 2004, 2003 and 2002, respectively.

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

Note 5 - Concentrations of Credit and Other Risk

Credit risk represents the accounting loss that would be recognized at the reporting date if counterparties failed to perform as contracted.  Concentrations of credit risk (whether on- or off-balance sheet) relate to groups of customers or counterparties that have similar economic or industry characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in economic or other conditions.

KU’s customer receivables and revenues arise from deliveries of electricity to approximately 488,000 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, 2004, 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 collective bargaining agreement effective August 2002 and expiring August 2005.  The employees represented by these two bargaining units comprise approximately 17% of KU’s workforce.

Note 6 - Pension Plans and Other Postretirement Benefit Plans

KU 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.

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

Obligations and 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, 2004, and a statement of the funded status as of December 31, 2004, for KU’s sponsored defined benefit:

(in thousands)	2004			2003			2002
Pension Plans:
Change in benefit obligation
Benefit obligation at beginning of year	$	257,705		$	247,727		$	244,472
Service cost	3,711			2,962			2,637
Interest cost	15,959			15,924			16,598
Plan amendment	18			40			28
Change due to transfers	81			(269		)	—
Benefits paid	(19,569		)	(22,594		)	(23,291		)
Actuarial (gain) or loss and other	32,810			13,915			7,283
Benefit obligation at end of year	$	290,715		$	257,705		$	247,727
Change in plan assets
Fair value of plan assets at beginning of year	$	201,093		$	178,534		$	216,947
Actual return on plan assets	24,613			36,528			(13,767		)
Employer contributions	43,409			10,231			15,283
Change due to transfers	23			(206		)	(15,382		)
Benefits paid	(19,569		)	(22,594		)	(23,291		)
Administrative expenses	(1,333		)	(1,400		)	(1,256		)
Fair value of plan assets at end of year	$	248,236		$	201,093		$	178,534
Reconciliation of funded status
Funded status	$	(42,479	)	$	(56,611	)	$	(69,193	)
Unrecognized actuarial (gain) or loss	56,216			27,917			36,233
Unrecognized transition (asset) or obligation	(266		)	(399		)	(532		)
Unrecognized prior service cost	8,331			9,184			10,106
Net amount recognized at end of year	$	21,802		$	(19,909	)	$	(23,386	)
Other Benefits:
Change in benefit obligation
Benefit obligation at beginning of year	$	105,763		$	104,602		$	83,223
Service cost	1,252			805			610
Interest cost	5,761			6,313			6,379
Benefits paid net of retiree contributions	(6,132		)	(7,329		)	(4,640		)
Actuarial (gain) or loss	(6,359		)	1,372			19,030
Benefit obligation at end of year	$	100,285		$	105,763		$	104,602
Change in plan assets
Fair value of plan assets at beginning of year	$	5,379		$	7,943		$	14,330
Actual return on plan assets	2,499			(775		)	(2,698		)
Employer contributions	4,430			5,506			1,648
Change due to transfers	(202		)	—			—
Benefits paid net of retiree contributions	(6,182		)	(7,295		)	(5,337		)
Fair value of plan assets at end of year	$	5,924		$	5,379		$	7,943
Reconciliation of funded status
Funded status	$	(94,361	)	$	(100,383	)	$	(96,659	)
Unrecognized actuarial (gain) or loss	14,811			24,013			22,667
Unrecognized transition (asset) or obligation	8,967			10,088			11,209
Unrecognized prior service cost	1,428			2,142			2,891
Net amount recognized at end of year	$	(69,155	)	$	(64,140	)	$	(59,892	)

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Amounts Recognized in Statement of Financial Position.  The following tables provide the amounts recognized in the balance sheet and information for plans with benefit obligations in excess of plan assets as of December 31, 2004, 2003 and 2002:

(in thousands)	2004			2003			2002
Pension Plans:
Amounts recognized in the balance sheet consisted of:
Accrued benefit liability	$	(8,759	)	$	(38,960	)	$	(51,035	)
Intangible asset	8,331			9,184			10,106
Accumulated other comprehensive income	22,230			9,867			17,543
Net amount recognized at year-end	$	21,802		$	(19,909	)	$	(23,386	)
Increase (decrease) in minimum liability included in other comprehensive income	$	12,363		$	(7,676	)	$	17,543
Additional year-end information for plans with accumulated benefit obligations in excess of plan assets:
Projected benefit obligation	$	290,715		$	257,705		$	247,727
Accumulated benefit obligation	256,995			240,054			229,569
Fair value of plan assets	248,236			201,093			178,534
Other Benefits:
Amounts recognized in the balance sheet consisted of:
Accrued benefit liability	$	(69,155	)	$	(64,140	)	$	(59,892	)
Additional year-end information for plans with benefit obligations in excess of plan assets:
Benefit obligation	$	100,285		$	105,763		$	104,602
Fair value of plan assets	5,924			5,379			7,943

Components of Net Periodic Benefit Cost.  The following table provides the components of net periodic benefit cost for the plans for 2004, 2003 and 2002:

(in thousands)	2004			2003			2002
Pension Plans:
Components of net periodic benefit cost
Service cost	$	3,711		$	2,962		$	2,637
Interest cost	15,959			15,925			16,598
Expected return on plan assets	(19,543		)	(14,888		)	(18,406		)
Amortization of transition (asset) or obligation	(133		)	(133		)	(133		)
Amortization of prior service cost	871			957			956
Amortization of actuarial (gain) or loss	833			1,211			1
Net periodic benefit cost	$	1,698		$	6,034		$	1,653
Other Benefits:
Components of net periodic benefit cost
Service cost	$	1,252		$	806		$	610
Interest cost	5,761			6,313			6,379
Expected return on plan assets	(396		)	(337		)	(1,022		)
Amortization of prior service cost	714			714			691
Amortization of transitional (asset) or obligation	1,121			1,121			1,081
Amortization of actuarial (gain) or loss	993			1,137			343
Net periodic benefit cost	$	9,445		$	9,754		$	8,082

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

	2004		2003		2002
Weighted-average assumptions as of December 31:
Discount rate	5.75	%	6.25	%	6.75	%
Rate of compensation increase	4.50	%	3.00	%	3.75	%

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

	2004		2003		2002
Discount rate	6.25	%	6.75	%	7.25	%
Expected long-term return on plan assets	8.50	%	9.00	%	9.50	%
Rate of compensation increase	3.50	%	3.75	%	4.25	%

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

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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 2004	$	(450	)	$	512
Effect on year-end 2004 postretirement benefit obligations	$	(6,549	)	$	7,449

Expected Future Benefit Payments.  The following list provides the amount of expected future benefit payments, which reflect expected future service, as appropriate:

(in thousands)	Pension Plans		Other Benefits
2005	$	20,005	$	7,284
2006	$	19,472	$	7,234
2007	$	18,897	$	7,614
2008	$	18,270	$	7,870
2009	$	17,667	$	8,195
2010-2014	$	83,008	$	45,059

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

	Target Range		2004		2003		2002
Pension Plans:
Equity securities	55% - 85	%	66	%	66	%	64	%
Debt securities	20% - 40	%	33	%	33	%	34	%
Other	0% - 10	%	1	%	1	%	2	%
Totals			100	%	100	%	100	%
Other Benefits:
Equity securities	—	%	—	%	—	%	—	%
Debt securities	100	%	100	%	100	%	100	%
	100	%	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

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undue exposure to any single economic sector, industry group or individual security.  The equity subsectors include, but are not limited to growth, value, small capitalization and international.

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

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

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

Contributions.  KU made discretionary contributions to the pension plan of $43.4 million in January 2004 and $10.2 million during 2003.  No discretionary contributions are planned for 2005.

FSP 106-2.  In May 2004, the FASB finalized FSP 106-2 with the guidance on accounting for subsidies provided under the Medicare Act which became law in December 2003.  FSP 106-2 was effective for the first interim or annual period beginning after June 15, 2004.  The following table reflects the impact of the subsidy:

(in thousands)
Reduction in accumulated postretirement benefit obligation (“APBO”)	$	3,268
Effect of the subsidy on the measurement of the net periodic postretirement benefit cost:
Amortization of the actuarial experience gain/(loss)	$	266
Reduction in service cost due to the subsidy	0
Resulting reduction in interest cost on the APBO	204
Total	$	470

Thrift Savings Plans.  KU has a thrift savings plan under section 401(k) of the Internal Revenue Code.  Under the plan, eligible employees may defer and contribute to the plan a portion of current compensation in order to provide future retirement benefits. KU makes contributions to the plan by matching a portion of the employee contributions. The costs of this matching were approximately $1.5 million for 2004, $1.9 million for 2003 and $1.5 million for 2002.

Note 7 - Income Taxes

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

(in thousands)			2004			2003			2002
Related to operating income:
Current	-	federal	$	39,821		$	31,079		$	38,524
	-	state	17,835			11,456			10,494
Deferred	-	federal – net	21,942			11,198			3,467
	-	state – net	(469		)	923			1,547
Total			79,129			54,656			54,032
Related to other income - net:
Current	-	federal	(530		)	(1,961		)	(685		)
	-	state	(137		)	(134		)	(195		)
Deferred	-	federal – net	46			180			15
	-	state – net	(34		)	(19		)	(88		)
Amortization of investment tax credit			(2,054		)	(2,641		)	(2,955		)
Total			(2,709		)	(4,575		)	(3,908		)
Total income tax expense			$	76,420		$	50,081		$	50,124

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

(in thousands)	2004		2003
Deferred tax liabilities:
Depreciation and other plant-related items	$	304,692	$	282,376
Regulatory assets and other	25,877		27,499
	330,569		309,875
Deferred tax assets:
Investment tax credit	1,536		2,365
Income taxes due to customers	7,781		9,710
Pensions and related benefits	21,164		16,154
Liabilities and other	17,453		20,388
	47,934		48,617
Net deferred income tax liability	$	282,635	$	261,258
Thereof non-current	$	282,436	$	259,402
Thereof current	199		1,856
	$	282,635	$	261,258

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

	2004		2003		2002
Statutory federal income tax rate	35.0	%	35.0	%	35.0	%
State income taxes, net of federal benefit	5.4		5.8		5.5
Amortization of investment tax credit	(1.2	)	(1.9	)	(2.4	)
Other differences – net	(2.8	)	(3.5	)	(3.2	)
Effective income tax rate	36.4	%	35.4	%	34.9	%

Other differences for 2004 include tax benefits related to a reserve adjustment (0.5%), excess deferred taxes which reflect the benefits of deferred taxes reversing at lower tax rates than what were provided (1.4%), and various other permanent differences (0.9%).

Other differences for 2003 include tax benefits related to prior year audit settlements (1.0%), excess deferred taxes which reflect the benefits of deferred taxes reversing at lower tax rates than what were provided (1.9%), and various other permanent differences (.6%).

Other differences for 2002 include tax benefits related to excess deferred taxes which reflect the benefits of deferred taxes reversing at lower tax rates than what were provided (1.8%), and various other permanent differences (1.4%).

H. R. 4520, known as the “American Jobs Creation Act of 2004” allows electric utilities to take a deduction of up to 3% of their generation taxable income in 2005. On a stand-alone basis, KU expects to generate a deduction in 2005 which will reduce KU’s effective tax rate by less than 1%.

Kentucky House Bill 272, also known as Kentucky’s Tax Modernization Plan, was signed into law in March 2005.  This bill contains a number of changes in Kentucky’s tax system, including the reduction of the Corporate income tax rate from 8.25% to 7% effective January 1, 2005, and a further reduction to 6% effective January 1, 2007.  The impact of these reduced rates is expected to decrease KU’s income tax expense in future periods.  Furthermore, these reduced rates will result in the reversal of accumulated temporary differences at lower rates than originally provided.  KU is presently evaluating the impact of this and other changes to the Kentucky tax system, however, no material adverse impacts on cash flows or results of operations are expected.

KU is subject to periodic changes in state tax law, regulation or interpretation, as well as enforcement proceedings.  KU is currently undergoing a routine Kentucky sales tax audit for the period January 1996 to July 2000.  The possible assessment or amount at issue is not known at this time, but is not expected to have a material adverse effect on cashflows or results of operations. 

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Note 8 - Other Income - Net

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

(in thousands)	2004			2003			2002
Equity in earnings - subsidiary company	$		2,559	$	3,644		$	6,967
Interest and dividend income	558			682			580
AFUDC	1,135			1,037			87
Gain on disposition of property	525			135			0
Terminated projects	0			(1,665		)	0
Benefit expense	0			0			(1,310		)
Other income (expense)	2,768			689			197
	$	7,545		$	4,522		$	6,521

Equity in earnings – subsidiary company refers to KU’s earnings related to EEI (see Note 1).

Note 9 - Long-Term Debt

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

As of December 31, 2004, 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.  Interest rates and maturities in the table below reflect the impact of interest rate swaps.

(in thousands)	Stated Interest Rates	Weighted Average Interest Rate	Maturities	Principal Amounts
Outstanding at December 31, 2004:
Noncurrent portion	Variable – 7.92%	3.68%	2006-2032	$	564,081
Current portion	Variable	2.23%	2005-2032	$	162,130
Outstanding at December 31, 2003 :
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 2004 was 1.37%.

Pollution control series bonds are first mortgage bonds that have been issued by KU in connection with tax-exempt pollution control revenue bonds issued by various governmental entities, principally counties in Kentucky.  A loan agreement obligates KU to make debt service payments to the county that equate to the debt service due from the county on the related pollution control revenue bonds.  The county’s debt is also secured by an equal amount of KU’s first mortgage bonds (the pollution control series bonds) that are pledged to the trustee for the pollution control revenue bonds, and that match the terms and conditions of the county’s debt, but require no payment of principal and interest unless KU defaults on the loan agreement.

Substantially all of KU’s assets are pledged as security for its first mortgage bonds.

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Interest rate swaps are used to hedge KU’s underlying debt obligations.  These swaps hedge specific debt issuances and, consistent with management’s designation, are accorded hedge accounting treatment.  The swaps effectively convert fixed rate obligations on KU’s first mortgage bonds Series P and R to variable-rate obligations.  As of December 31, 2004 and 2003, KU had swaps with a combined notional value of $103 million and $153 million, respectively.  See Note 4.

In October 2004, KU completed a refinancing transaction regarding $50 million in existing pollution control indebtedness.  The original indebtedness, 5.75% Pollution Control Bonds, Series 9, due December 1, 2023, was discharged in November 2004, with the proceeds from the replacement indebtedness, KU Pollution Control Bonds, Series 17, due October 1, 2034, which carries a variable, auction rate of interest.  The call premium and unamortized debt expense of the Series 9 bonds are deferred assets being amortized over the life of the Series 17 bonds.

In May 2004, KU redeemed $4.8 million of its Series 14 Pollution Control Bonds which were initially issued in the amount of $7.2 million.

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.

In January 2004, KU entered into one unsecured long-term loan from Fidelia 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 November 2003, KU called its first mortgage bond, Series P 8.55% of $33 million, due in 2027, and replaced it with a loan from Fidelia.

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

During 2003, KU entered into four long-term loans from Fidelia totaling $283 million.  Of this total, $100 million is unsecured with an interest rate of 4.55% and matures in April 2003.  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 collateralized by a pledge of substantially all assets of KU that is subordinated to the first mortgage bond lien.

See Note 11, Commitments and Contingencies for all long-term debt maturities.

Note 10 - Notes Payable and Other Short-Term Obligations

KU participates in an intercompany money pool agreement wherein LG&E Energy and/or 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.  The balance of the money pool loan from LG&E Energy (shown as “Notes payable to affiliated company”) was $34.8 million at an average rate of 2.22% and $43.2 million at an average rate of 1.00% at December 31, 2004 and 2003, respectively.  The amount available to KU under the money pool agreement at December 31, 2004 was $365.2 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, 2004 was $65.4 million, and availability of $84.6 million remained.   LG&E Energy increased the size of its revolving credit facility to $200 million effective January 24, 2005.

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Note 11 - Commitments and Contingencies

The following is provided to summarize KU’s contractual cash obligations for periods after December 31, 2004.  KU anticipates cash from operations and external financing will be sufficient to fund future obligations.  Future interest obligations cannot be quantified because most of KU's debt is variable rate (see KU's Consolidated Statements of Capitalization).

(in thousands)	Payments Due by Period
Contractual Cash Obligations	2005		2006		2007		2008		2009		Thereafter			Total
Short-term debt (a)	$	34,820	$	—	$	—	$	—	$	—	$	—		$	34,820
Long-term debt	162,130		36,000		58,088		—		—		469,993		(b)	726,211
Unconditional power purchase obligations (c)	40,098		41,141		42,625		43,690		45,138		655,720			868,412
Coal purchase obligations (d)	263,418		156,613		64,886		35,808		—		—			520,725
Retirement obligations (e)	6,564		6,915		7,236		7,479		7,757		—			35,951
Other long-term obligations (f)	14,771		—		—		—		—		—			14,771
Total contractual cash obligations	$	521,801	$	240,669	$	172,835	$	86,977	$	52,895	$	1,125,713		$	2,200,890

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

(b)Includes long-term debt of $87.1 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 2024 to 2032.  KU does not expect to pay these amounts in 2005.

(c)Represents future minimum payments under OVEC, OMU and EEI purchased power agreements through 2024.

(d)Represents contracts to purchase coal.

(e)Represents currently projected contributions to pension plans and other post-employment benefits obligations as calculated by the actuary.

(f)Represents construction commitments.

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 2004, 2003 and 2002, was $2.8 million, $2.2 million and $3.1 million, respectively.

Sale and Leaseback Transaction. KU is a participant in a sale and leaseback transaction involving its 62% interest in two jointly-owned CTs at KU’s E.W. Brown generating station (Units 6 and 7).  Commencing in December 1999, LG&E and KU entered into a tax-efficient, 18-year lease of the CTs. LG&E and KU have provided funds to fully defease the lease, and have executed an irrevocable notice to exercise an early purchase option contained in the lease after 15.5 years. The financial statement treatment of this transaction is no different than if KU had retained its ownership.  The transaction produced a pre-tax gain of approximately $1.9 million which was recorded in other income on the income statement in 2000, pursuant to a Kentucky Commission order.  The leasing transaction was entered into following receipt of required state and federal regulatory approvals.

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

At December 31, 2004, the maximum aggregate amount of default fees or amounts, which decrease over the term of the lease, was $9.5 million, of which KU would be responsible for $5.9 million (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.

Letter of Credit.  KU has provided a letter of credit totaling $0.8 million to support certain obligations related to self-insurance and workers compensation of longshore and harbor workers for barge unloading.

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Purchased Power.  KU has purchased 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 2005-2009, which is expected to be approximately 7% 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 agreement.  Included in the total costs is KU’s proportionate share of debt service requirements on $205.6 million of OMU bonds outstanding at December 31, 2004.  The debt service is allocated to KU based on its annual allocated share of capacity, which averaged approximately 45% in 2004.  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 on the cost method of accounting.  KU’s entitlement is 2.5% of OVEC’s generation capacity or approximately 55 Mw.

Construction Program.  KU had approximately $14.8 million of commitments in connection with its construction program at  December 31, 2004.  Construction expenditures for the years 2005 and 2006 are estimated to total approximately $448 million, although all of this is not currently committed, including future expenditures related to the construction of Trimble County Unit 2 and the installation of FGDs at Ghent.

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 and through the consumption of emission allowances granted under the Clean Air Act.  KU’s strategy for Phase II SO₂ reductions, which commenced January 1, 2000, has been to use accumulated emissions allowances to delay additional capital expenditures and will include fuel switching and the installation of additional FGDs as necessary. KU decided in December 2004 that additional FGDs will be necessary to maintain compliance with Phase II SO₂ reductions.  Those installations are currently scheduled for completion in 2007-2009.   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 the EPA on 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, the 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 the 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 31, 2004.  All KU generating units are in compliance with these NOx emissions reduction rules.

KU has added significant NOx controls to its generating units through the installation of SCR systems, advanced low-NOx burners and neural networks.  The NOx controls project commenced in late 2000 with the

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controls being placed into operation prior to the 2004 Summer Ozone Season. As of December 31, 2004, KU incurred total capital costs of approximately $219 million to reduce its NOx emissions below the 0.15 lb./MMBtu level on a company-wide basis.  In addition, KU will incur additional operating and maintenance costs in operating new NOx controls.  KU believes its costs in this regard to be comparable to those of similarly situated utilities with like generation assets. KU 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 Clean Air Mercury Rule which regulates mercury emissions from steam electric generating units and reductions in emissions of SO₂ and NOx required under the Clean Air Interstate Rule. KU has implemented a plan for adding significant additional SO₂ controls to its generating units. Installation of additional SO₂ controls will proceed on a phased basis, with construction of controls (i.e. FGD’s) commencing in mid 2005 and continuing through the final installation and operation in 2009.  KU estimates that it will incur $678 million in capital costs related to the reduction of its SO₂ emissions to achieve compliance with current emission limits on a company-wide basis.  In addition, KU will incur additional operating and maintenance costs in operating new SO₂ controls.  KU believes its costs in this regard to be comparable to those of similarly situated utilities with like generation assets.  KU anticipates that such capital and operating costs are the type of costs that are eligible for recovery from customers under its environmental surcharge mechanism and believes that a significant portion of such costs could be recovered.  In December 2004, KU filed an application seeking recovery of its costs. KU expects the Kentucky Commission to issue an Order granting recovery of these costs in June 2005.

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.  During August 2004, KU, the EPA, and the Department of Justice agreed in principle to settle outstanding matters concerning a 1999 oil discharge at KU’s E.W. Brown plant for approximately $0.6 million. The settlement is subject to completion of final definitive documents but is anticipated to be resolved by the construction of a separate environmental capital project and a cash payment of approximately $0.2 million. At December 31, 2004, KU has recorded an accrual and expense of $0.2 million.

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 parties, among a number of potentially responsible parties, and has entered into settlement discussions with the EPA and the Kentucky Division of Waste Management on this matter.

In January 2005, approximately 1,000 gallons of fuel oil leaked from a cracked weld in a storage tank at

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KU’s Green River Generating Station.  KU commenced immediate spill containment, recovery and remediation actions and has received satisfactory inspections from state regulators to date.  The cost related to the clean up of the oil spill is expected to be immaterial.

Note 12 – Jointly Owned Electric Utility Plant

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

(in thousands)		LG&E			KU			Total
Paddy’s Run 13	Ownership %	53		%	47		%	100		%
	Mw capacity	84			74			158
	Cost	$	34,033		$	30,038		$	64,071
	Depreciation	4,042			3,555			7,597
	Net book value	$	29,991		$	26,483		$	56,474
E.W. Brown 5	Ownership %	53		%	47		%	100		%
	Mw capacity	62			55			117
	Cost	$	23,978		$	20,221		$	44,199
	Depreciation	2,712			2,269			4,981
	Net book value	$	21,266		$	17,952		$	39,218
E.W. Brown 6	Ownership %	38		%	62		%	100		%
	Mw capacity	59			95			154
	Cost	$	25,353		$	38,935		$	64,288
	Depreciation	3,426			6,644			10,070
	Net book value	$	21,927		$	32,291		$	54,218
E.W. Brown 7	Ownership %	38		%	62		%	100		%
	Mw capacity	59			95			154
	Cost	$	22,718		$	36,137		$	58,855
	Depreciation	5,679			7,012			12,691
	Net book value	$	17,039		$	29,125		$	46,164
Trimble 5	Ownership %	29		%	71		%	100		%
	Mw capacity	46			114			160
	Cost	$	16,241		$	39,665		$	55,906
	Depreciation	1,363			3,327			4,690
	Net book value	$	14,878		$	36,338		$	51,216
Trimble 6	Ownership %	29		%	71		%	100		%
	Mw capacity	46			114			160
	Cost	$	16,205		$	39,703		$	55,908
	Depreciation	1,361			3,332			4,693
	Net book value	$	14,844		$	36,371		$	51,215
Trimble 7	Ownership %	37		%	63		%	100		%
	Mw capacity	59			101			160
	Cost	$	19,274		$	32,913		$	52,187
	Depreciation	355			606			961
	Net book value	$	18,919		$	32,307		$	51,226
Trimble 8	Ownership %	37		%	63		%	100		%
	Mw capacity	59			101			160
	Cost	$	19,161		$	32,762		$	51,923
	Depreciation	353			604			957
	Net book value	$	18,808		$	32,158		$	50,966
Trimble 9	Ownership %	37		%	63		%	100		%
	Mw capacity	59			101			160
	Cost	$	19,195		$	32,835		$	52,030
	Depreciation	299			512			811
	Net book value	$	18,896		$	32,323		$	51,219
Trimble 10	Ownership %	37		%	63		%	100		%
	Mw capacity	59			101			160
	Cost	$	19,141		$	32,802		$	51,943
	Depreciation	298			511			809
	Net book value	$	18,843		$	32,291		$	51,134
Trimble CT Pipeline	Ownership %	29		%	71		%	100		%
	Cost	$	1,978		$	4,813		$	6,791
	Depreciation	165			403			568
	Net book value	$	1,813		$	4,410		$	6,223
Trimble CT Substation	Ownership %	29		%	71		%	100		%
5 & 6	Cost	$	1,474		$	3,598		$	5,072
	Depreciation	76			196			272
	Net book value	$	1,398		$	3,402		$	4,800
Trimble CT Substation	Ownership %	37		%	63		%	100		%
7 - 10	Cost	$	2,856		$	4,711		$	7,567
	Depreciation	30			53			83
	Net book value	$	2,826		$	4,658		$	7,484

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In addition to these generating units, LG&E and KU share joint ownership in the Brown Inlet Air Cooling system. KU owns 90% of the system, attributable to Brown Unit 5 and Units 8-11, which provides an additional 88 Mw of capacity.

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 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 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, 2004, 2003 and 2002 were as follows:

(in thousands)	2004		2003		2002
Electric operating revenues from LG&E	$	61,743	$	46,690	$	33,249
Electric operating revenues from LEM	205		2,408		3,581
Purchased power from LG&E	58,687		53,747		41,480
Purchased power from LEM	—		—		913

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Interest Charges

KU participates in an intercompany money pool agreement wherein LG&E Energy and/or 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.  The balance of the money pool loan from LG&E Energy (shown as “Notes payable to affiliated company”) was $34.8 million at an average rate of 2.22% and $43.2 million at an average rate of 1.00% at December 31, 2004 and 2003, respectively.  The amount available to KU under the money pool agreement at December 31, 2004 was $365.2 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, 2004 was $65.4 million, and availability of $84.6 million remained. LG&E Energy increased the size of its revolving credit facility to $200 million, effective January 24, 2005.

In addition, in 2003 KU began borrowing long-term funds from Fidelia (see Note 9).

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 KU relates to LG&E’s receipt and payment of KU’s portion of off-system sales and purchases.

KU’s intercompany interest income and expense for the years ended December 31, 2004, 2003 and 2002 were as follows:

(in thousands)	2004		2003		2002
Interest on money pool loans	$	397	$	1,204	$	1,071
Interest on Fidelia loans	13,759		4,729		—
Interest expense paid to LG&E	2		6		5
Interest income received from LG&E	44		8		61

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, 2004, 2003 and 2002 were as follows:

(in thousands)	2004		2003		2002
LG&E Services billings to KU	$	170,234	$	201,283	$	176,254
KU billings to LG&E	7,188		16,636		11,921
LG&E billings to KU	59,513		77,166		71,127
KU billings to LG&E Services	5,019		16,138		18,573

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Note 14 – Accumulated Other Comprehensive Income

Accumulated other comprehensive income consisted of the following:

(in thousands)	Minimum Pension Liability Adjustment			Accumulated Derivative Gain or Loss			PreTax			Income Tax			Net
Balance at December 31, 2001	$	—		$	2,663		$	2,663		$	1,075		$	1,588
Minimum pension liability adjustment	(17,543		)	—			(17,543		)	(7,081		)	(10,462		)
Gains (losses) on derivative instruments designated and qualifying as cash flow hedging instruments	—			(2,663		)	(2,663		)	(1,075		)	(1,588		)
Balance at December 31, 2002	(17,543		)	—			(17,543		)	(7,081		)	(10,462		)
Minimum pension liability adjustment	7,676			—			7,676			3,098			4,578
Gains (losses) on derivative instruments designated and qualifying as cash flow hedging instruments	—			(246		)	(246		)	(99		)	(147		)
Balance at December 31, 2003	(9,867		)	(246		)	(10,113		)	(4,082		)	(6,031		)
Minimum pension liability adjustment	(12,363		)	—			(12,363		)	(4,990		)	(7,373		)
Gains (losses) on derivative instruments designated and qualifying as cash flow hedging instruments	—			246			246			100			146
Balance at December 31, 2004	$	(22,230	)	$	—		$	(22,230	)	$	(8,972	)	$	(13,258	)

Note 15 - Selected Quarterly Data (Unaudited)

Selected financial data for the four quarters of 2004 and 2003 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
2004
Operating revenues	$	247,386	$	232,369	$	252,669	$	262,938
Net operating income	56,355		50,282		57,951		63,259
Net income	32,444		27,565		34,818		38,644
2003
Operating revenues	$	224,983	$	197,174	$	235,426	$	234,195
Net operating income	21,261		26,622		50,972		63,355
Net income	11,861		14,159		30,310		35,072

Effective December 31, 2004, operating and non-operating income taxes are presented as “Federal and State Income Taxes” on KU’s Consolidated Statements of Income.  Prior to December 31, 2004, the component of income taxes associated with operating income was included in net operating income and the component of income taxes associated with non-operating income taxes was included in other income (expense) – net.  KU has applied this change in presentation to all prior periods.

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	Quarters Ended
(in thousands)	March		June		September		December
2004
Net operating income as previously reported	$	35,254	$	32,821	$	38,386
Plus income taxes reclassified from total operating expenses	21,101		17,461		19,565
Net operating income	$	56,355	$	50,282	$	57,951
2003
Net operating income as previously reported	$	14,660	$	19,155	$	32,776	$	40,963
Plus income taxes reclassified from total operating expenses	6,601		7,467		18,196		22,392
Net operating income	$	21,261	$	26,622	$	50,972	$	63,355

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).

(in thousands)	Quarter Ended March 30, 2003
Gross operating revenues as previously reported	$	234,147
Less costs reclassified from power purchased	9,164
Net operating revenues	$	224,983

Note 16 – Subsequent Events

In February 2005, Kentucky’s Governor signed an executive order directing the Kentucky Commission, in conjunction with the Commerce Cabinet and the Environmental and Public Protection Cabinet, to ‘develop a Strategic Blueprint for the continued use and development of electric energy.’ This Strategic Blueprint will be designed to promote future investment in electric infrastructure for the Commonwealth of Kentucky, to protect Kentucky’s low-cost electric advantage, to maintain affordable rates for all Kentuckians, and to preserve Kentucky’s commitment to environmental protection.  In March 2005, the Kentucky Commission established Administrative Case No. 2005-00090 to collect information from all jurisdictional utilities in Kentucky, including KU, pertaining to Kentucky electric generation, transmission and distribution systems.  The Kentucky Commission must provide its Strategic Blueprint to the Governor in early August 2005.  KU must respond to the Kentucky Commission’s first set of data requests by the end of March 2005.

Kentucky House Bill 272, also known as Kentucky’s Tax Modernization Plan, was signed into law in March  2005.  This bill contains a number of changes in Kentucky’s tax system, including the reduction of the Corporate income tax rate from 8.25% to 7% effective January 1, 2005, and a further reduction to 6% effective January 1, 2007.  The impact of these reduced rates is expected to decrease KU’s income tax expense in future periods.  Furthermore, these reduced rates will result in the reversal of accumulated temporary differences at lower rates than originally provided.  KU is presently evaluating the impact of this and other changes to the Kentucky tax system, however, no material adverse impacts on cash flows or results of operations are expected.

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Kentucky Utilities Company

REPORT OF MANAGEMENT

The management of Kentucky Utilities Company (“KU”) 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 financial statements for the three years ended December 31, 2004 have been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm.  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, 2004, did not identify any material weaknesses in the design and operation of KU’s internal control structure.

KU is not an accelerated filer under the Sarbanes-Oxley Act of 2002 and associated rules (the “Act”) and consequently anticipates issuing Management’s Certification on Internal Controls over Financial Reporting pursuant to Section 404 of the Act in its first periodic report covering the fiscal year ended December 31, 2006 as permitted by SEC rulemaking.

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 registered public accounting firm and the internal auditors have access to the Board of Directors at any time.

KU 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

Louisville, Kentucky

163

Kentucky Utilities Company and Subsidiary

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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 at December 31, 2004 and December 31, 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 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 each of the three years in the period ended December 31, 2004, listed in the index appearing under Item 15(a)(2), presents fairly in all material respects, the information set forth therein when read in conjunction with the related consolidatedfinancial statements.  These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.  We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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

Louisville, Kentucky

February 4, 2005

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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.

In preparation for required reporting under Section 404 of the Sarbanes-Oxley Act of 2002, the Companies are conducting a thorough review of their internal control over financial reporting, including disclosure controls and procedures. Based on this review, the Companies have made internal control enhancements and will continue to make future enhancements to their internal control over financial reporting. There has been no change in the Companies’ internal control over financial reporting that occurred during the fiscal quarter ended December 31, 2004, that has materially affected, or is reasonably likely to materially affect, the Companies’ internal control over financial reporting.

LG&E and KU are not accelerated filers under the Sarbanes-Oxley Act of 2002 and associated rules (the “Act”) and consequently anticipate issuing Management’s Report on Internal Controls over Financial Reporting pursuant to Section 404 of the Act in its first periodic report covering the fiscal year ended December 31, 2006 as permitted by SEC rulemaking.

PART III

ITEM 10. Directors and Executive Officers of LG&E and KU.

Information regarding directors of 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 five-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,

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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 5.05 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.

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 and Related Stockholder Matters.

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, which information is incorporated herein by reference.

PART IV

ITEM 15.  Exhibits and Financial Statement Schedules.

(a)        1.   Financial Statements (included in Item 8):

166

LG&E:

Consolidated Statements of Income for the three years ended December 31, 2004

Consolidated Statements of Retained Earnings for the three years ended December 31, 2004

Consolidated Statements of Comprehensive Income for the three years ended December 31, 2004

Consolidated Balance Sheets-December 31, 2004, and 2003

Consolidated Statements of Cash Flows for the three years ended December 31, 2004

Consolidated Statements of Capitalization-December 31, 2004, and 2003

Notes to Consolidated Financial Statements

Report of Management

Report of Independent Registered Public Accounting Firm

KU:

Consolidated Statements of Income for the three years ended December 31, 2004

Consolidated Statements of Retained Earnings for the three years ended December 31, 2004

Consolidated Statements of Comprehensive Income for the three years ended December 31, 2004

Consolidated Balance Sheets-December 31, 2004, and 2003

Consolidated Statements of Cash Flows for the three years ended December 31, 2004

Consolidated Statements of Capitalization-December 31, 2004, and 2003

Notes to Consolidated Financial Statements

2.Financial Statement Schedules (included in Part IV):

Schedule II Valuation and Qualifying Accounts for the three years ended December 31, 2004, for LG&E and KU.

All other schedules have been omitted as not applicable or not required or because the information required to be shown is included in the Financial Statements or the accompanying Notes to Financial Statements.

3.Exhibits:

Exhibit No.	Applicable to Form 10-K of
	LG&E	KU	Description
2.01	X	X	Copy of Agreement and Plan of Merger, dated as of February 27, 2000, by and among Powergen plc, LG&E Energy Corp., US Subholdco2 and Merger Sub, including certain exhibits thereto.  [Filed as Exhibit 1 to LG&E’s and KU’s Current Report on Form 8-K filed February 29, 2000 and incorporated by reference herein]
2.02	X	X	Amendment No. 1 to Agreement and Plan of Merger, dated as of December 8, 2000, among LG&E Energy Corp., Powergen plc, Powergen US Investments Corp. and Powergen Acquisition Corp. [Filed as Exhibit 2.01 to LG&E’s and KU’s Current Report on Form 8-K filed December 11, 2000 and incorporated by reference herein]
2.03	X	X	Copy of Agreement and Plan of Merger, dated as of May 20, 1997, by and between LG&E Energy and KU Energy, including certain exhibits thereto.  [Filed as Exhibit 2 to LG&E’s and KU’s Current Report on Form 8-K filed May 30, 1997 and incorporated by reference herein]
3.01	X		Copy of Restated Articles of Incorporation of LG&E, dated November 6, 1996. [Filed as Exhibit 3.06 to LG&E Quarterly Report on Form 10-Q for the quarter ended September 30, 1996, and incorporated by reference herein]
3.02	X		Copy of Amendment to Articles of Incorporation of LG&E, dated February 6, 2004. [Filed as Exhibit 3.02 to LG&E and KU’s Annual Report on Form 10-K for the year ended December 31, 2004, and incorporated by reference herein]

167

3.03	X		Copy of By-Laws of LG&E, as amended through December 16, 2003. [Filed as Exhibit 3.03 to LG&E and KU’s Annual Report on Form 10-K for the year ended December 31, 2004, and incorporated by reference herein]
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. [Filed as Exhibit 3.05 to LG&E’s and KU’s Annual Report on Form 10-K for the year ended December 31, 2004, and incorporated by reference herein]
3.06		X	Copy of By-Laws of KU, as amended through December 16, 2003. [Filed as Exhibit 3.06 to LG&E and KU’s Annual Report on Form 10-K for the year ended December 31, 2004, and incorporated by reference herein]
4.01	X		Copy of Trust Indenture dated November 1, 1949, from LG&E to Harris Trust and Savings Bank, Trustee.  [Filed as Exhibit 7.01 to LG&E’s Registration Statement 2-8283 and incorporated by reference herein]
4.02	X		Copy of Supplemental Indenture dated 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 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]
4.05	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]
4.06	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]

168

4.07	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]
4.08	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.)
4.09	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.)
4.10	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.)
4.11		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

169

			(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]
4.12		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]
4.13		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]
4.14		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]
4.15		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]
4.16		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]
4.17	X		Copy of Supplemental Indenture dated October 1, 2003, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.22 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2004, and incorporated by reference herein]
4.18		X	Copy of Loan Agreement between KU and Fidelia Corporation, dated April 30, 2003.
			[Filed as Exhibit 4.23 to KU’s Annual Report on Form 10-K for the year ended December 31, 2004, and incorporated by reference herein]
4.19	X		Copy of Loan Agreement between LG&E and Fidelia Corporation, dated April 30, 2003. [Filed as Exhibit 4.24 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2004, and incorporated by reference herein]
4.20		X	Copy of Loan Agreement between KU and Fidelia Corporation, dated January 15, 2004.  [Filed as Exhibit 4.25 to KU’s Annual Report on Form 10-K for the year ended December 31, 2004, and incorporated by reference herein]
4.21		X	Copy of Loan and Security Agreement between KU and Fidelia Corporation, dated as of August 15, 2003. [Filed as Exhibit 4.26 to KU’s Annual Report on Form 10-K for

170

			the year ended December 31, 2004, and incorporated by reference herein]
4.22	X	X	Copy of Loan and Security Agreement between LG&E and Fidelia Corporation, dated as of August 15, 2003.  [Filed as Exhibit 4.27 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2004, and incorporated by reference herein]
4.23		X	Copy of Promissory Note from KU to Fidelia Corporation, dated as of November 24, 2003, in the amount of $33 million.
4.24		X	Copy of Promissory Note from KU to Fidelia Corporation, dated as of December 18, 2003, in the amount of $75 million.
4.25		X	Copy of Loan Agreement between KU and Fidelia Corporation, dated as of January 15, 2004
4.26		X	Supplemental Indenture dated as of October 1, 2004 from Kentucky Utilities Company to U.S. Bank National Association and Richard Prokosch, as Trustees  [Filed as Exhibit 4.1 to KU’s Form 8-K filed on October 22, 2004, and incorporated by reference herein].
4.27	X		Copy of Promissory Note from LG&E to Fidelia Corporation, dated as of January 15, 2004, in the amount of $25 million.
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]
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]

171

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]
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	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]
10.15	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]
10.16	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

172

			December 31, 1995, and incorporated by reference herein]
10.17	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]
10.18	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]
10.19	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]
10.20	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]
10.21	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.]
10.22	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]
10.23	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]
10.24	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]
10.25	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]
10.26	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]
10.27	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]

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10.28	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]
10.29	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]
10.30	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]
10.31	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]
10.32	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]
10.33	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]
10.34	X	X	*Copy of LG&E Energy Corp. Long-Term Performance Unit Plan, adopted April 25, 2003, effective January 1, 2003. [Filed as Exhibit 10.65 to LG&E and KU’s Annual Report on Form 10-K for the year ended December 31, 2004, and incorporated by reference herein]
10.35	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. [Filed as Exhibit 10.69 to LG&E and KU’s Annual Report on Form 10-K for the year ended December 31, 2004, and incorporated by reference herein]
10.36	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. [Filed as Exhibit 10.70 to LG&E and KU’s Annual Report on Form 10-K for the year ended December 31, 2004, and incorporated by reference herein]
10.37	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. [Filed as Exhibit 10.71 to LG&E and KU’s Annual Report on Form 10-K for the year ended December 31, 2004, and incorporated by reference

174

			herein]
10.38		X	Loan Agreement dated October 1, 2004 between Kentucky Utilities Company and the County of Carroll, Kentucky [Filed as Exhibit 10.1 to KU’s Form 8-K filed on October 22, 2004 and incorporated by reference herein]
10.39	X	X	Copy of Amended and Restated Inter-company Power Agreement dated as of March 13, 2006, among Ohio Valley Electric Corporation and sponsoring companies, including LG&E and KU [Filed as Exhibit 10.1 to LG&E and KU’s Form 10-Q for the period ended June 30, 2004 and incorporated by reference herein]
10.40	X	X	*Copy of Fourth Amendment dated as of February 1, 2004 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 10.02 to LG&E and KU’s Form 10-Q for the period ended June 30, 2004 and incorporated by reference herein]
10.41	X	X	Copy of Modification No. 15, dated as of April 30, 2004, to Inter-Company Power Agreement dated July 10, 1953 among Ohio Valley Electric Corporation and Sponsoring Companies [Filed as Exhibit 10.03 to LG&E and KU’s Form 10-Q for the period ended June 30, 2004 and incorporated by reference herein]
10.42	X		Participation Agreement between LG&E and Illinois Municipal Electric Agency, dated as of September 24, 1990.
10.43	X		Participation Agreement between LG&E and Indiana Municipal Power Agency, dated as of February 1, 1993.
10.44	X	X	Participation Agreement by and among LG&E and KU and Indiana Municipal Electric Agency and Indiana Municipal Power Agency, dated as of February 9, 2004.
10.45	X	X	Copy of Barge Transportation Agreement  between LG&E, effective January 1, 2002, and KU, effective July 1, 2002, and Crounse Corporation.
10.46	X	X	* Executive Officer Salary Information.
10.47	X	X	* Form of Specimen Award under LG&E Energy Long-Term Performance Unit Plan
10.48	X	X	* Form of Specimen Award under E.ON Group Stock Option Program
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.

175

31.1	X			Certification of Chief Executive Officer, Pursuant to Section 302 of Sarbanes-Oxley Act of 2002.
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.

Executive Compensation Plans and Arrangements:

Exhibits preceded by an asterisk (“*”) above are management contracts, compensation plans or arrangements required to be identified pursuant to Item 15(a)(3) of Form 10-K.

Certain Available Instruments

        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 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.

176

Louisville Gas and Electric Company	Schedule II
Schedule II - Valuation and Qualifying Accounts
For the Three Years Ended December 31, 2004
(Thousands of $)

	Other Property and Investments		Accounts Receivable (Uncollectible Accounts)
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
Additions:
Charged to costs and expenses	—		1,908
Deductions:
Net charges of nature for which reserves were created	—		4,638
Balance December 31, 2004	$	63	$	785

177

Kentucky Utilities Company	Schedule II
Schedule II - Valuation and Qualifying Accounts
For the Three Years Ended December 31, 2004
(Thousands of $)

	Other Property and Investments		Accounts Receivable (Uncollectible Accounts)
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
Additions:
Charged to costs and expenses	1		1,247
Deductions:
Net charges of nature for which reserves were created	—		1,296
Balance December 31, 2004	$	131	$	623

178

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 30, 2005	/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
Chris Hermann	Director and Senior Vice President, Energy Delivery
Paul W. Thompson	Director and Senior Vice President, Energy Services

By	/s/ S. Bradford Rives	March 30, 2005
	(Attorney-In-Fact)

179

SIGNATURES – KENTUCKY UTILITIES COMPANY

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

	KENTUCKY UTILITIES COMPANY
	Registrant
March 30, 2005	/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
Chris Hermann	Director and Senior Vice President, Energy Delivery
Paul W. Thompson	Director and Senior Vice President, Energy Services

By	/s/ S. Bradford Rives	March 30, 2005
	(Attorney-In-Fact)

180

EX-4.23

Exhibit 4.23

NOTE

$33,000,000.00 Date: November 24, 2003

FOR VALUE RECEIVED, on November 24, 2010 (the “Maturity Date”) the undersigned, KENTUCKY UTILITIES COMPANY, a Kentucky and Virginia corporation (the “Borrower”), unconditionally promises to pay to FIDELIA CORPORATION (the “Lender”), at the Lender’s office at 919 North Market Street, Suite 504, Wilmington, Delaware  19801, or at such other place as the holder of this Note may from time to time designate in writing, in lawful money of the United States of America and immediately available funds, the principal sum of $33,000,000.  This Note is referred to in and was executed and delivered under the Loan and Security Agreement dated as of August 15, 2003 (the “Loan Agreement”) between the Borrower and the Lender, to which reference is made for a more complete statement of the terms and conditions under which the loan evidenced by this Note was made and is to be repaid.  Capitalized terms used in this Note and not otherwise defined have the meanings assigned to such terms in the Loan Agreement.

Unless otherwise paid sooner under the provisions of Section 2.6(c) or 7.1 of the Loan Agreement, the principal indebtedness represented by this Note is payable on the Maturity Date.  The Borrower further promises to pay interest on the outstanding principal amount of the indebtedness represented by this Note from the date of this Note until payment in full at the applicable rates determined in accordance with Section 2.3(A) of the Loan Agreement.  Except as otherwise provided in the Loan Agreement, interest is payable at the fixed rate of 4.24% semi-annually in arrears not later than the last Business Day of each six months period and is computed on the basis of a 360-day year consisting of twelve 30-day months.  Interest payment dates are or around May 24^th and November 24^th during the term of the Note.

If payment under this Note becomes due and payable on a Business Day, the due date of such payment is extended to the next succeeding Business Day.  In no contingency or event whatsoever will interest charged under this Note, however such interest may be characterized or computed, exceed the highest rate permissible under any law which a court of competent jurisdiction, in a final determination, deems applicable to this Note.  In the event that such a court determines that the Lender has received interest under this Note in excess of the highest rate applicable to this Note, any such excess interest collected by the Lender is deemed to have been a repayment of principal and be so applied.

The obligations of the Borrower under this Note is secured by certain collateral as and to the extent set forth in the Loan Agreement.  This Note is subject to prepayment at the option of the Borrower as provided in the Loan Agreement.

DEMAND, PRESENTMENT, PROTEST AND NOTICE OF NONPAYMENT AND PROTEST ARE WAIVED BY THE BORROWER.

This Note has been delivered and is deemed to have been made, at Wilmington, Delaware and will be interpreted in accordance with the internal law as (as opposed to conflicts of law provisions) and decisions of the State of Delaware.  Whenever possible each provision of this Note will be interpreted in such manner as to be effective and valid under applicable law, but if any provision of this Note is prohibited by or invalid under applicable law, such provision will be ineffective to the extent of such prohibition or invalidity, without invalidating the remainder of such provision or the remaining provisions of this Note.  Whenever in this Note reference is made to the Lender or the Borrower, such reference is deemed to include, as applicable, a reference to their respective successors and assigns.  The provisions of this Note are binding upon and inure to the benefit of said successors and assigns.  The Borrower’s successors and assigns include, without limitation, a receiver, trustee or debtor-in-possession of or for the Borrower.

KENTUCKY UTILITIES COMPANY
By:
	Title:

EX-4.24

Exhibit 4.24

NOTE

$75,000,000 Date: December 18, 2003

FOR VALUE RECEIVED, on December 19, 2005 (the “Maturity Date”) the undersigned, KENTUCKY UTILITIES COMPANY, a Kentucky and Virginia corporation (the “Borrower”), unconditionally promises to pay to FIDELIA CORPORATION (the “Lender”), at the Lender’s office at 919 North Market Street, Suite 504, Wilmington, Delaware  19801, or at such other place as the holder of this Note may from time to time designate in writing, in lawful money of the United States of America and immediately available funds, the principal sum of $75,000,000.  This Note is referred to in and was executed and delivered under the Loan and Security Agreement dated as of August 15, 2003 (the “Loan Agreement”) between the Borrower and the Lender, to which reference is made for a more complete statement of the terms and conditions under which the loan evidenced by this Note was made and is to be repaid.  Capitalized terms used in this Note and not otherwise defined have the meanings assigned to such terms in the Loan Agreement.

Unless otherwise paid sooner under the provisions of Section 2.6(c) or 7.1 of the Loan Agreement, the principal indebtedness represented by this Note is payable on the Maturity Date.  The Borrower further promises to pay interest on the outstanding principal amount of the indebtedness represented by this Note from the date of this Note until payment in full at the applicable rates determined in accordance with Section 2.3(A) of the Loan Agreement.  Except as otherwise provided in the Loan Agreement, interest is payable at the fixed rate of 2.29% semi-annually in arrears and is computed on the basis of a 360-day year consisting of twelve 30-day months.  Interest payment dates are June 18^th and December 18^th during the term of the Note.

If payment under this Note becomes due and payable on a day that is not a Business Day, the due date of such payment is extended to the next succeeding Business Day.  In no contingency or event whatsoever will interest charged under this Note, however such interest may be characterized or computed, exceed the highest rate permissible under any law which a court of competent jurisdiction, in a final determination, deems applicable to this Note.  In the event that such a court determines that the Lender has received interest under this Note in excess of the highest rate applicable to this Note, any such excess interest collected by the Lender is deemed to have been a repayment of principal and be so applied.

The obligations of the Borrower under this Note is secured by certain collateral as and to the extent set forth in the Loan Agreement.  This Note is subject to prepayment at the option of the Borrower as provided in the Loan Agreement.

DEMAND, PRESENTMENT, PROTEST AND NOTICE OF NONPAYMENT AND PROTEST ARE WAIVED BY THE BORROWER.

This Note has been delivered and is deemed to have been made, at Wilmington, Delaware and will be interpreted in accordance with the internal law as (as opposed to conflicts of law provisions) and decisions of the State of Delaware.  Whenever possible each provision of this Note will be interpreted in such manner as to be effective and valid under applicable law, but if any provision of this Note is prohibited by or invalid under applicable law, such provision will be ineffective to the extent of such prohibition or invalidity, without invalidating the remainder of such provision or the remaining provisions of this Note.  Whenever in this Note reference is made to the Lender or the Borrower, such reference is deemed to include, as applicable, a reference to their respective successors and assigns.  The provisions of this Note are binding upon and inure to the benefit of said successors and assigns.  The Borrower’s successors and assigns include, without limitation, a receiver, trustee or debtor-in-possession of or for the Borrower.

KENTUCKY UTILITIES COMPANY
By:
	Title:

EX-4.25

Exhibit 4.25

January 15, 2004

Kentucky Utilities Company
            (as Borrower)

Fidelia Corporation
          (as Lender)

LOAN AGREEMENT

Contents

Clause

1.	DEFINITIONS
2.	TERM LOAN
3.	AVAILABILITY OF REQUESTS
4.	INTEREST
5.	REPAYMENT AND PREPAYMENT
6.	PAYMENTS
7.	TERMINATION EVENTS
8.	OPERATIONAL BREAKDOWN
9.	NOTICES
10.	ASSIGNMENT
11.	SEVERABILITY
12.	COUNTERPARTS
13.	LAW

THIS AGREEMENT made on January 15, 2004

Between

KENTUCKY UTILITIES COMPANY, a Kentucky corporation, as borrower (the Borrower); and

FIDELIA CORPORATION, a Delaware corporation, as lender (the Lender).

Whereas

(A)The Lender and the Borrower hereby enter into an agreement for the provision by the Lender to the Borrower of a loan in the amount of  $50,000,000 (the Loan Amount).

Now it is hereby agreed as follows:

1.Definitions

1.1In this Agreement

Business Day means a day on which banks in New York are generally open

Default Interest Rate means: the rate, as determined by the Lender, applying to the principal element of an overdue amount under Clause 6.3, calculated as the sum of the interest rate in effect immediately before the due date of such amount, plus 1%;

Effective Date shall have the meaning given to it in Clause 2.1;

Final Repayment Date means January 16, 2012;

Interest Payment Date means January 15th and July 15th of each year during the term of this agreement, provided, that:

any Interest Payment Date which  is not a Business Day shall be extended to the next succeeding Business Day;

Loan Amount means $50,000,000;

Maturity Date means the Final Repayment Date;

1

Request means a request for the Loan Amount from the Borrower to the Lender under the terms of clause 3.1;

Termination Event means an event specified as such in Clause 7;

Value Date means the date upon which cleared funds are made available to the Borrower by the Lender pursuant to a Request made in accordance with Clause 3.1. Such date shall be a Business Day as defined herein.

2.Term Loan

2.1This Agreement shall come into effect on January 15, 2004 (the “Effective Date”).

2.2The Lender grants to the Borrower upon the terms and conditions of this Agreement a term loan in an amount of $50,000,000.

2.3The new indebtedness shall be evidenced by a note in substantially the form of Exhibit “A” attached hereto.

3.Availability of Requests

3.1On the Effective Date, the Borrower will submit a request (the “Request”) to the Lender for the Loan Amount, such Request specifying the Value Date, the Maturity Date and the bank account to which payment is to be made. The Request shall be submitted to the Lender by the Borrower and delivered in accordance with Clause 9.3.

4.Interest

4.1The rate of interest on the Loan Amount is 4.39%.

4.2Interest shall accrue on the basis of a 360-day year consisting of twelve 30 day months upon the Loan Amount.

4.3Interest shall be payable in arrears on each Interest Payment Date.

2

5.Repayment and Prepayment

5.1The Borrower shall repay the Loan Amount together with all interest accrued thereon and all other amounts due from the Borrower hereunder on the Final Repayment Date, whereupon this Agreement shall be terminated.

5.2On any Interest Payment Date, and with at least three business day’s prior written notice, the Borrower shall be entitled to prepay any amount of the loan outstanding, provided such payment is not less than $1,000,000 and, provided further, the Borrower shall pay a prepayment charge equal to the present value of the difference between (i) the interest payable provided in this loan agreement and (ii) the interest payable at the prevailing interest rate at the time of prepayment, for the period from the date of prepayment through the Maturity Date, which difference, if negative, shall be deemed to be zero. The present value will be determined using the prevailing interest rate at the time of the prepayment as the discount rate.

5.3A certificate from the Lender as to the amount due at any time from the Borrower to the Lender under this Agreement shall, in the absence of manifest error, be conclusive.

6.Payments

6.1All payments of principal to be made to the Lender by the Borrower shall be made on the Final Repayment Date, or on an Interest Payment Date under Clause (5.2) to such account as the Lender shall have specified.

6.2Interest shall be payable in arrears on each Interest Payment Date.

6.3If and to the extent that full payment of any amount due hereunder is not made by the Borrower on the due date then, interest shall be charged at the Default Interest Rate on such overdue amount from the date of such default to the date payment is received by the Lender.

3

7.Termination Events

7.1The Borrower shall notify the Lender of any Event of Default (and the steps, if any, being taken to remedy it) promptly upon becoming aware of it.

7.2The following shall constitute an Event of Default hereunder:

7.2.1Default is made by the Borrower in the payment of any sum due under this Agreement and such default continues for a period of 10 Business Days;

7.2.2Bankruptcy proceedings are initiated against the Borrower;

7.2.3The Borrower leaves the E.ON Group (i.e. the companies consolidated in EON AG’s balance sheet);

7.2.4Securities and Exchange Commission or Public Utility Holding Company Act (PUHCA) requirements prohibit the transactions hereunder.

If a Termination Event occurs under Clause (7.2.2) of this section, the Loan Amount outstanding together with interest will become due and payable immediately.

If a Termination Event occurs according to Clauses (7.2.1) or (7.2.3) or (7.2.4) of this Section, Lender shall at its discretion grant Borrower a reasonable grace period unless such grace period shall be detrimental to the Lender. If the Termination Event is uncured at the expiration of such period, the Loan Amount outstanding together with interest will become due and payable immediately.

8. Operational Breakdown

8.1The Borrower is not liable for any damages incurred by the Lender and the Lender is not liable for any damages incurred by the Borrower caused by Acts of God or other circumstances incurred by one party for which the other party cannot be held responsible (i.e. power outages, strikes, lock-outs, domestic and foreign acts of government and the like).

4

9.Notices

9.1Each communication to be made in respect of this Agreement shall be made in writing but, unless otherwise stated, may be made by facsimile transmission or letter.

9.2Communications to the Borrower shall be addressed to: Kentucky Utilities Company, 220 W. Main St., Louisville, KY 40202, Attn: Treasurer fax# (502) 627-4742 except for confirmations which should be sent to the attention of Mimi Kelly.

9.3Communications to the Lender shall be addressed to: Fidelia Corporation, 919 N. Market Street, Suite 504, Wilmington, Delaware 19801, fax# (302) 778-5014, Attn: President.

10.Assignment

10.1The Lender may at any time assign, novate or otherwise transfer all or any part of its rights and obligations under this Agreement to any affiliate of the Lender.

11.Severability

11.1If any of the provisions of this Agreement becomes invalid, illegal or unenforceable in any respect under any law, the validity, legality and enforceability of the remaining provisions shall not in any way be affected or impaired.

12.Counterparts

12.1This Agreement may be executed in any number of counterparts that shall together constitute one Agreement. Any party may enter into an Agreement by signing any such counterpart.

5

13.Law

13.1This Agreement shall be governed by and construed for all purposes in accordance with the laws of Delaware.

IN WITNESS whereof the parties have executed this Agreement the day and year first above written.

SIGNED by				)
	for and on behalf of			)
	Kentucky Utilities			)
SIGNED by			)
		Udo Koch, President	)
		Fidelia Corporation	)

6

EX-4.27

Exhibit 4.27

NOTE

$25,000,000 Date: January 15, 2004

FOR VALUE RECEIVED, on January 16, 2012 (the “Maturity Date”) the undersigned, LOUISVILLE GAS AND ELECTRIC COMPANY, a Kentucky corporation (the “Borrower”), unconditionally promises to pay to FIDELIA CORPORATION (the “Lender”), at the Lender’s office at 919 North Market Street, Suite 504, Wilmington, Delaware  19801, or at such other place as the holder of this Note may from time to time designate in writing, in lawful money of the United States of America and immediately available funds, the principal sum of $25,000,000.  This Note is referred to in and was executed and delivered under the Loan and Security Agreement dated as of August 15, 2003 (the “Loan Agreement”) between the Borrower and the Lender, to which reference is made for a more complete statement of the terms and conditions under which the loan evidenced by this Note was made and is to be repaid.  Capitalized terms used in this Note and not otherwise defined have the meanings assigned to such terms in the Loan Agreement.

Unless otherwise paid sooner under the provisions of Section 2.6(c) or 7.1 of the Loan Agreement, the principal indebtedness represented by this Note is payable on the Maturity Date.  The Borrower further promises to pay interest on the outstanding principal amount of the indebtedness represented by this Note from the date of this Note until payment in full at the applicable rates determined in accordance with Section 2.3(A) of the Loan Agreement.  Except as otherwise provided in the Loan Agreement, interest is payable at the fixed rate of 4.33% semi-annually in arrears and is computed on the basis of a 360-day year consisting of twelve 30-day months.  Interest payment dates are January 15th and July 15th during the term of the Note.

If payment under this Note becomes due and payable on a day that is not a Business Day, the due date of such payment is extended to the next succeeding Business Day.  In no contingency or event whatsoever will interest charged under this Note, however such interest may be characterized or computed, exceed the highest rate permissible under any law which a court of competent jurisdiction, in a final determination, deems applicable to this Note.  In the event that such a court determines that the Lender has received interest under this Note in excess of the highest rate applicable to this Note, any such excess interest collected by the Lender is deemed to have been a repayment of principal and be so applied.

The obligations of the Borrower under this Note are secured by certain collateral as and to the extent set forth in the Loan Agreement.  This Note is subject to prepayment at the option of the Borrower as provided in the Loan Agreement.

DEMAND, PRESENTMENT, PROTEST AND NOTICE OF NONPAYMENT AND PROTEST ARE WAIVED BY THE BORROWER.

This Note has been delivered and is deemed to have been made, at Wilmington, Delaware and will be interpreted in accordance with the internal law as (as opposed to conflicts of law provisions) and decisions of the State of Delaware.  Whenever possible each provision of this Note will be interpreted in such manner as to be effective and valid under applicable law, but if any provision of this Note is prohibited by or invalid under applicable law, such provision will be ineffective to the extent of such prohibition or invalidity, without invalidating the remainder of such provision or the remaining provisions of this Note.  Whenever in this Note reference is made to the Lender or the Borrower, such reference is deemed to include, as applicable, a reference to their respective successors and assigns.  The provisions of this Note are binding upon and inure to the benefit of said successors and assigns.  The Borrower’s successors and assigns include, without limitation, a receiver, trustee or debtor-in-possession of or for the Borrower.

LOUISVILLE GAS AND ELECTRIC COMPANY
By:
	Title: Treasurer

EX-10.42

EXHIBIT 10.42

PARTICIPATION AGREEMENT

BETWEEN

LOUISVILLE GAS AND ELECTRIC

AND

ILLINOIS MUNICIPAL ELECTRIC AGENCY

SEPTEMBER 24, 1990

CONFORMED COPY ISSUED MARCH 8, 1993

BY THE

LOUISVILLE GAS AND ELECTRIC CO.

RESOURCE AND ELECTRIC SYSTEM PLANNING DEPARTMENT

502 627-2300

PARTICIPATION AGREEMENT

BY AND BETWEEN

LOUISVILLE GAS AND ELECTRIC COMPANY

220 West Main Street

Post Office Box 32010 (40232)

Louisville, Kentucky 40202

AND

ILLINOIS MUNICIPAL ELECTRIC AGENCY

919 South Spring Street

Springfield, Illinois 62704

September 24, 1990

as amended January 22, 1991

CONFORMED COPY

AGREEMENT

This Agreement, dated September 24, 1990, as amended by Amendment to Participation Agreement, dated January 22, 1991, between Louisville Gas and Electric Company (“Louisville” or a “Party”), a Kentucky corporation, and Illinois Municipal Electric Agency (“IMEA” or a “Party”), an Illinois municipal corporation, collectively (the “Parties”).

WHEREAS, IMEA is an agency composed of numerous municipally-owned electric systems, and is empowered, among other things, to plan, finance, develop, own, and operate projects to supply electric power and energy on a collective basis for the present and future needs of its members; and

WHEREAS, Louisville is a regulated public utility and owns and operates facilities for the generation, transmission, and distribution of electric power and. energy in the Commonwealth of Kentucky; and

WHEREAS, IMEA owns and operates facilities for the generation and transmission of electric power and energy in the State of Illinois; and

WHEREAS, Louisville is the owner of the Trimble County Plant; and

WHEREAS, Louisville and IMEA are entering into this Agreement to establish (a) the respective ownership interests of the Parties in Trimble County Unit 1, and (b) the respective obligations and rights of the Parties with respect to the operation and maintenance of Trimble County Unit 1.

NOW, THEREFORE, in consideration of the premises and of the mutual covenants herein set forth, and subject to the terms and conditions herein set forth, the Parties agree as follows:

TABLE OF CONTENTS

ARTICLE  1 DEFINITIONS
1.1	Agreed Rate.
1.2	Agreement
1.3	Capacity Factor.
1.4	Closing.
1.5	Commercial Operation Date.
1.6	Construction Work.
1.7	Coordination Committee.
1.8	Delivery Points.
1.9	Effective Date.
1.10	Electric Capability.
1.11	Electric Energy.
1.12	Electric Capability And Energy.
1.13	Electric Capability And Energy Entitlement.
1.14	Execution Date.
1.15	Fixed Operation and Maintenance Expenses.
1.16	Force Majeure.
1.17	Fuel/Reactant Operation Expenses.
1.18	Good Utility Practice.
1.19	Incremental Capital Assets.
1.20	Insurance.
1.21	Interchange Agreement.
1.22	Internal Load.
1.23	Louisville’s Cost of Capital.
1.24	Municipal System.
1.25	Net Electric Generating Capability And Associated Electric Energy.
1.26	Net Seasonal Capability.
1.27	Operating Work.
1.28	Participant.
1.29	Representative.
1.30	Trimble County General Plant Facilities.
1.31	Trimble County Plant.
1.32	Trimble County Site.
1.33	Trimble County Unit 1.
1.34	Uniform System Of Accounts.
ARTICLE  2 OWNERSHIP INTEREST AND SALE
2.1	Ownership Interests.
2.2	Sale Of Property Included In Trimble County Unit 1.
2.3	Release From Lien Of Louisville’s Indenture.
2.4	Closing.
2.5	Additional Generating Units.
2.6	Modification Of Existing Property.
ARTICLE  3 PURCHASE, PAYMENT, AND CLOSING
3.1	Purchase Price.

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3.2	Deposit.
3.3	Final Payment.
3.4	Closing.
3.5	Date And Place.
3.6	Delivery Of Documents. Certificates. And Funds.
3.7	Extension Of Time For Closing.
3.8	Special Conditions.
3.9	Liquidated Damages.
3.10	Continued Marketing By Louisville.
3.11	Termination If Closing Does Not Occur.
ARTICLE  4 REPRESENTATIONS, WARRANTIES, AND MUTUAL COVENANTS
4.1	IMEA Representations.
4.2	IMEA Organization.
4.3	Authority Relative To This Agreement.
4.4	Approvals And Consents.
4.5	Legal Proceedings.
4.6	Louisville Representations.
4.7	Louisville Organization.
4.8	Authority Relative To This Agreement.
4.9	Approvals And Consents.
4.10	Legal Title.
4.11	Condition of Plant and Equipment.
4.12	Legal Proceedings.
ARTICLE  5 OPERATING ARRANGEMENTS
5.1	Authority For Operation And Management.
5.2	Scheduling And Dispatching Of Electric Generation.
5.3	Economic Replacement of Trimble County Unit 1 Energy.
5.4	Electric Capability And Energy Entitlements.
5.5	Precommercial Energy.
5.6	Operations Management.
	5.6.1	Administration Of Operating Work And Incremental Capital Assets.
	5.6.2	Purchasing Necessary Goods And Services.
	5.6.3	Procurement of Fuel.
	5.6.4	Expenditure Of Funds.
	5.6.5	Insurance.
	5.6.6	Enforcement Of Claims Against Third Parties.
	5.6.7	Processing Claims By Third Parties.
	5.6.8	Delivery Of Operating Data.
5.7	Environmental Laws and Regulations.
5.8	Limited Re-Opener:  Environmental Legislation.
5.9	Indemnification of Environmental Fines and Penalties.
ARTICLE  6 INCREMENTAL CAPITAL ASSETS
6.1	Determination Of Need.
6.2	Estimate Of Costs.
6.3	Responsibility For Costs.

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ARTICLE  7 COMPENSATION
7.1	Monthly Charges.
	7.1.1	Fuel/Reactant Operation Expense.
	7.1.2	Fixed Operation And Maintenance Expenses.
	7.1.3	Non-Fuel Operating Component.
	7.1.4	Working Capital Component.
	7.1.5	Transmission Charge.
	7.1.6	Service Fee.
ARTICLE  8 BILLING, PAYMENTS, AND RECORDS
8.1	Billings By Louisville.
8.2	Payments By IMEA or Louisville.
8.3	Records.
ARTICLE  9 TRANSMISSION SERVICE
ARTICLE 10 BACKUP POWER AND ENERGY
10.1	From Louisville.
10.2	From Third Parties.
10.3	Effective Date of Backup Power Provision.
ARTICLE 11 GENERAL CONDITIONS
11.1	Cooperation.
11.2	Approvals.
11.3	Access.
11.4	Conditions Precedent To Louisville’s Obligations Hereunder.
	11.4.1	Accuracy Of IMEA’s Representations And Warranties.
	11.4.2	Capability Of Performance By IMEA.
	11.4.3	Opinion Of Counsel For IMEA.
	11.4.4	Payment Of Funds By IMEA.
11.5	Conditions Precedent To IMEA’s Obligations Hereunder.
	11.5.1	Accuracy Of Louisville’s Representations And Warranties.
	11.5.2	Capability Of Performance By Louisville.
	11.5.3	Opinion Of Counsel-For-Louisville.
11.6	Conditions Precedent To The Respective Obligations Of The Parties.
11.7	Release From Louisville’s Indenture(s).
11.8	Amendments.
11.9	LIMITED WARRANTY.
11.10	No Agency Or Third Party Beneficiary.
ARTICLE 12 TAXES
12.1	Management Of Tax Matters.
12.2	Sharing or Taxes And Related Payments.
12.3	Payment Of Title Taxes And Fees.
12.4	Exclusion Of Income Taxes.
12.5	Non-creation Of Taxable Entity.
ARTICLE 13 INSURANCE
13.1	Procurement Of Insurance.

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	13.1.1	Sharing-Of Insurance Costs.
	13.1.2	IMEA Named As Insured.
	13.1.3	Procurement Of Additional Insurance For IMEA.
	13.1.4	Sharing Of Refunds From Insurance Premiums.
	13.1.5	Sharing Of Insurance Proceeds.
13.2	Destruction.
	13.2.1	Damage Or Destruction Fully Covered By Insurance.
	13.2.2	Damage Or Destruction Not Fully Covered By Insurance.
ARTICLE 14 PARTITION OF OR TRANSFER OF INTEREST IN THIMBLE COUNTY UNIT
14.1	Special Nature Of Trimble County Unit 1 – Waiver of Right of Partition.
14.2	Transfer Of Ownership Interests To Third Parties.
	14.2.1	Conditions Of Transfer.
	14.2.2	Further Conditions Of Transfer.
	14.2.3	Non-applicability Of Certain Provisions.
14.3	Transfer of Associated Rights and Interests.
ARTICLE 15 RIGHT OF FIRST REFUSAL
ARTICLE 16 ASSIGNMENT
16.1	Limitation Of Assignability.
16.2	Successors And Assigns.
ARTICLE 17 LIABILITY AND DEFAULT
17.1	Liability To Third Parties.
17.2	Liability Between The Parties.
17.3	Indemnification.
17.4	Nature And Survival Of Representations And Warranties.
17.5	Default.
	17.5.1	Events Of Default.
	17.5.2	Curing Default in Regard To Paring Money.
	17.5.3	Curing Default For Other Than Failure To Pay Money.
	17.5.4	Non-Applicability of Cure Provisions.
	17.5.5	Appointment Of A Receiver.
	17.5.6	Additional Obligations.
	17.5.7	Waivers.
	17.5.8	Legal And Other Costs.
17.6	Force Majeure.
ARTICLE 18 ADMINISTRATION
18.1	Coordination Committee.
18.2	Membership.
18.3	Meetings.
18.4	Functions.
18.5	Records.
18.6	Expenses.
18.7	Conduct.
ARTICLE 19 DISAGREEMENT

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19.1	Consultation.
19.2	Disagreement After Commercial Operation.
19.3	Arbitration.
19.4	Obligations To Make Payments.
ARTICLE 20 REMEDIES
20.1	All Remedies - Setoff.
20.2	Injunctive Relief.
20.3	No Remedy Exclusive.
20.4	20.4
ARTICLE 21 MISCELLANEOUS
21.1	Governing Law.
21.2	Notice To Parties.
21.3	Article Headings Not To Affect Meaning.
21.4	Counterparts.
21.5	Time.
21.6	Severability.
21.7	Integration.
21.8	Computation Of Time.
21.9	Waiver.
21.10	Equal Opportunity Clause.
21.11	Non-Segregated Facilities.
21.12	Condemnation.
ARTICLE 22 TERM AND TERMINATION
22.1	Termination.
22.2	Retirement Of Property.
22.3	Retirement Costs.

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ARTICLE 1

DEFINITIONS

1.1Agreed Rate.

Two (2) percent per annum above the published prime commercial lending rate established from time to time by Chase Manhattan Bank, New York, New York.

1.2Agreement

This Participation Agreement between Louisville and IMEA dated as of September 24, 1990.

1.3Capacity Factor.

The ratio of the actual net electric energy generated by Trimble County Unit I in a period of time to the maximum net electric energy that could be generated by the same unit in the same period of time if such unit operated uninterrupted at its Net Seasonal Capability rating.

1.4Closing.

The delivery of documents and certificates and the payment of money as provided in Article 3a

1.5Commercial Operation Date.

The date on which Trimble County Unit 1 is determined by Louisville to be reliable as a source of electric capacity and energy. In the absence of a Force Majeure condition, the Commercial Operation Date shall be no later than December 31, 1990. Such determination shall be made by Louisville in the same manner as is customary for Louisville in determining the commercial operation date of any of its other fossil fuel-fired steam electric generating units.

1.6Construction Work.

All engineering, design, contract preparation, purchasing (of equipment, materials, and supplies), construction, supervision, expediting, inspection, accounting, testing and start-up for the Trimble County Plant and preparation of operating and equipment manuals, quality assurance manuals, emergency action plans, all reports required by regulatory authorities and the conduct of hearings and all other activities incidental to obtaining requisite permits, licenses, and certificates for the construction and operation of the Trimble County Plant prior to the Commercial Operation Date of Trimble County Unit 1 in accordance with Electric Plant Instruction No. 3, Components of Construction Cost. Uniform System of Accounts. Construction Work, as used in Article 15 hereof, shall refer to the categories of costs and expenses set forth above, which relate to the unit to be constructed referenced in Article 15.

1.7Coordination Committee.

The committee established pursuant to Article 18 hereof.

1.8Delivery Points.

The interconnection points of Louisville’s system with the utility or utilities with which IMEA has contracted for transmission service to transmit power from Louisville to IMEA.

1.9Effective Date.

See definition for Execution Date.

1.10Electric Capability.

Megawatts (MW) of electric demand.

1.11Electric Energy.

Megawatt-hours (MWH) of electric energy.

1.12Electric Capability And Energy.

Electric Capability and associated Electric Energy.

1.13Electric Capability And Energy Entitlement.

The percentage of the Net Electric Generating Capability and Associated Electric Energy of Trimble County Unit 1 to which Louisville or IMEA, as the case may be, is entitled under Article 54 of this Agreement.

1.14Execution Date.

The date upon which the Parties entered into this Agreement, which appears at the beginning of this Agreement. Unless otherwise specified, the Effective Date shall be the Execution Date.

1.15Fixed Operation and Maintenance Expenses.

The Fixed Operation and Maintenance Expenses are calculated as the sum of the following expenses as they relate to the operation and maintenance of Trimble County Unit 1, Trimble County General Plant Facilities (as such pertain to Trimble County Unit 1), and the Trimble County Site (as such pertain to Trimble County Unit 1), as recorded in Louisville’s accounting records under the Uniform System of Accounts:

(a)Operation supervision and engineering (Account 500).

(b)Steam expenses (Account 502 except for scrubber reactant).

(c)Electric expenses (Account 505)

(d)Miscellaneous steam power expenses (Account 506).

(e)Rents (Account 507).

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(f)Maintenance of electric plant (Account 513).

(g)Maintenance of miscellaneous steam plant (Account 514).

1.16Force Majeure.

Any cause beyond the reasonable control of a Party, and which by reasonable efforts the Party is unable to overcome, including without limitation, the following:  acts of God; strikes, lockouts, or other industrial disturbances; acts of public enemies; acts, orders, or absence of necessary orders and permits of any kind, from the government of the United States, or from the government of one of its sovereign states, or any of their departments, agencies, or officials, or from any civil or military authority; insurrections; riots; delay in transportation; unforeseen soil conditions; equipment, material, supplies, labor or machinery shortages; epidemics; landslides; lightning; earthquakes; fire; hurricanes; tornadoes; storms; floods; washouts; droughts; arrest; war; civil disturbances; explosions; breakage or accident to machinery, equipment, transmission lines, pipes, or canals; partial or entire failure of utility service; breach of contract by any supplier, contractor, subcontractor, laborer, or materialman; sabotage; injunction; blight; famine; blockage; quarantine; or any other similar or dissimilar cause or event not reasonably with the control of the Party.  Force Majeure does not include financial inability to pay, and shall not, in any event, excuse payment for obligations already incurred hereunder at the time such claim is made.

1.17Fuel/Reactant Operation Expenses.

The fuel/reactant operation expenses are calculated as the sum of the following expenses as recorded in Louisville’s accounting records under the Uniform System of Accounts:

(a)Fuel (Account 501).

(b)Scrubber reactant expenses in Steam Expenses (Account 502).

1.18Good Utility Practice.

At a particular time, any of the practices, methods, and acts, which, in the exercise of reasonable judgement in the light of the facts known at the time the decision was made, would have been expected to accomplish the desired result or further the possibility of achieving such result, at a reasonable cost consistent with reliability and safety and all applicable laws and governmental rules, regulations, and orders pertaining to Trimble County Plant Such practices, methods, and acts shall include, but shall not be limited to, any of the practices, methods, and acts engaged in or approved by other members of the electric utility industry at, prior to, or subsequent to the time the decision was made Good Utility Practice is not intended to be limited to the optimum practice, method, or act to the exclusion of all others, but rather to be a number of possible practices, methods, or acts.

1.19Incremental Capital Assets.

All assets of the Trimble County Plant pertaining to the use of Trimble County Unit 1 which are not included in Accounts 101, 106, or 107 of the Uniform System of Accounts on the Commercial Operation Date, or such later date as is necessary to complete the original construction of Trimble County Unit 1 and the Trimble County General Plant Facilities and the Trimble County Site as they pertain to the Trimble County Unit l.

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1.20Insurance.

Policies of insurance of any type procured and maintained, including any self-insurance maintained by Louisville or jointly by the Parties, relating to Trimble County Unit 1 on and after its Commercial Operation Date, in accordance with Article 13 hereof.

1.21Interchange Agreement.

The agreement between Louisville and IMEA, as such agreement may be amended from time to time, providing for purchases and sales of electric capacity and energy between the Parties, and specifying the rates to be charged for such transactions as filed with the Federal Energy Regulatory Commission (“FERC”).

1.22Internal Load.

Aggregate electric demand of all retail consumers served, including those served under non-firm (interruptible) rate schedules, and associated transmission and distribution losses.

1.23Louisville’s Cost of Capital.

An amount determined by the weighted average cost of capital based on Louisville’s capital structure at the end of the prior month, including short-term debt, long-term debt, preferred stock, and common equity. The cost rates for short-term debt, long-term debt, and preferred stock shall be determined based on the average embedded cost at the end of the prior month.  The cost of common equity shall be based upon the rate of return on common equity allowed by the Kentucky Public Service Commission, or its successor, by its Order in Louisville’s last general rate case.

1.24Municipal System.

A municipality in Illinois which now or hereafter is a member of IMEA.

1.25Net Electric Generating Capability And Associated Electric Energy.

The maximum continuous ability of Trimble County Unit 1 to produce power which can be available at any particular time, less any power required for operation of the unit, taking into account all relevant conditions and factors affecting or limiting the capability of the unit to produce power at such time, including, without limitation, availability and quality of fuel, any mechanical or other defects, breakdowns, malfunctions, or environmental and permit limitations then existing.

1.26Net Seasonal Capability.

The steady hourly output, less auxiliary usage, which generating equipment is expected to produce under ideal conditions, and adjusted due to seasonal variations in ambient temperature, condensing water availability and/or temperature, reservoir levels, scheduled reservoir discharge, river flow head, etc. Such output shall be declared on a monthly basis and determined according to testing criteria defined in the East Central Area Reliability Coordination Agreement’s Document No. 4 entitled, ~Criteria and Method For the Uniform Rating of Generating Equipment.

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1.27Operating Work.

All engineering, contract preparation, purchasing, repair, supervision, recruitment, training, expediting, inspection, accounting, testing, protection, operating, management, maintenance, and all other work and activities associated with operating Trimble County Unit 1 which are not included in Construction Work, but excluding all work on any Incremental Capital Assets.

1.28Participant.

A Municipal System which has a power sales contract with IMEA.

1.29Representative.

A Party’s member of the Coordination Committee as set forth in Article 18 of this Agreement.

1.30Trimble County General Plant Facilities.

Facilities on the Trimble County Site, excluding those in which an interest is conveyed as identified in Appendix B, which are necessary for use by IMEA with respect to its proportional ownership of Trimble County Unit I, for which IMEA shall have a non-exclusive license, substantially in the form shown in Appendix C, to use consistent with its ownership interests. Ownership in such facilities is not conveyed to IMEA hereunder. Such facilities are identified in Appendix C hereto, and in the absence of other units at the Trimble County Site, all such facilities shall be considered to pertain to the use of Trimble County Unit I.

1.31Trimble County Plant.

The generating plant at a site along the Ohio River at Wises Landing in Trimble County, Kentucky, which plant currently consists of a single coal-fired steam electric generating unit of 495,000 kilowatts nearing completion, and includes Trimble County Unit 1, the Trimble County General Plant Facilities, and the Trimble County Site.

1.32Trimble County Site.

Certain land, consisting of approximately 2,200 acres, and certain rights in land owned by Louisville, including the land on which Trimble County Unit 1 is constructed and including that portion of the land underlying Trimble County Unit 1 which is conveyed to IMEA under Article 22 hereof. In the absence of other units at the Trimble County Site, all such land shall be considered to pertain to the use of Trimble County Unit 1.

1.33Trimble County Unit 1.

The 495,000 kilowatt unit currently nearing completion at the Trimble County Site, consisting of the property set forth in Appendix B hereto.

1.34Uniform System Of Accounts.

The FERC’s ‘Uniform System of Accounts Prescribed for Public Utilities and Licensees (Class A and Class B)’, in effect as of the date of this Agreement, as such Uniform System of

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Accounts may be modified from time to time. References in this Agreement to any specific account number shall mean the account number in effect as of the Execution Date of this Agreement or any successor account.

ARTICLE 2

OWNERSHIP INTEREST AND SALE

2.1Ownership Interests.

Trimble County Unit 1 shall be owned by the Parties as tenants in common. The undivided ownership interest of each Party in Trimble County Unit 1 shall be free and clear of the lien of any indenture of mortgage, deed of trust, bond resolution, or other instrument (hereinafter called ‘indenture’) establishing a lien upon some or all of the property of the other Party. The undivided ownership interests of Louisville and IMEA in Trimble County Unit 1 shall be 87.88 and 12a12 percent, respectively. Trimble County Unit 1 is more specifically described in Appendix B attached hereto which may be revised from time to time in accordance with this Agreement. Louisville shall retain full ownership of the Trimble County General Plant Facilities as described in Appendix C attached hereto, subject to the non-exclusive license granted to IMEA hereunder Louisville shall retain full ownership of the Trimble County Site except for that portion of the Trimble County Site conveyed to IMEA pursuant to Article 2.2, and subject to the reciprocal easements over the Trimble County Site conveyed to and by Louisville and IMEA.

It is recognized by the Parties, however, that various items of property included in Trimble County Unit 1 may be leased from others in lieu of purchasing such items of property. Nothing in this Agreement shall preclude the Parties from leasing such items of property.  Such leased property shall be held by the Parties in an undivided ownership as tenants in common.

2.2Sale Of Property Included In Trimble County Unit 1.

At the Closing Louisville shall sell and convey to IMEA, and IMEA shall purchase from Louisville, a 12a12 percent undivided ownership interest as a tenant in common in Trimble County Unit 1 as set forth in Appendix B Such conveyance shall be by Bill of Sale substantially in the form shown in Appendix A attached hereto and made a part hereof.

Louisville shall further convey to IMEA by general warranty deed, substantially in the form shown in Appendix E, an undivided ownership interest in 12.12 percent of that portion of the real estate constituting the Trimble County Site underlying Trimble County Unit 1 to be held as tenants in common.

Louisville shall further grant to IMEA a non-exclusive license, substantially in the form shown in Appendix C, to use the Trimble County General Plant Facilities and a non-exclusive easement, substantially In the form shown in Appendix F, over that portion of the Trimble County Site owned by Louisville, as the Trimble County General Plant Facilities and the Trimble County Site pertain to IMEA’s use of Trimble County Unit 1. IMEA shall grant to Louisville an easement, substantially in the form shown in Appendix G, over IMEA’s interest in the Trimble County Site.

Further, after the Closing, the Parties shall execute such other instruments, if any, as may be necessary or appropriate to confirm the respective rights and interests of the Parties hereunder and to maintain their respective ownership interests.

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2.3Release From Lien Of Louisville’s Indenture.

At the Closing, Louisville shall furnish to IMEA a properly executed release of that portion of the property being conveyed to IMEA at the Closing from the lien of any and all indentures.

2.4Closing.

The Closing shall be held in accordance with the provisions of Article 3.

2.5Additional Generating Units.

Subject to Article 15 hereof, Louisville shall have the sole and exclusive right to own, install, enlarge, modify, and operate any generating unit or units other than Trimble County Unit 1, as well as any other facility, including necessary appurtenances thereto, on the Trimble County Site, provided that such other units or facilities shall net be so installed enlarged, modified, ad operated as the case may be, as to unreasonably impair (economically or operationally) the operation of Trimble County Unit 1.

2.6Modification Of Existing Property.

Subject to the approval of the Coordination Committee, and in accordance with the terms of this Agreement, Louisville shall have the right to use, enlarge, modify, or relocate any facilities installed as ‘a part of Trimble County Unit 1 or Trimble County General Plant Facilities in connection with the Installation, enlargement, modification, or operation, as the case may be, of such other unit or units or facilities provided that:

(a)such use, enlargement, modification, or relocation of Trimble County Unit 1 facilities or Trimble County General Plant Facilities shall not unreasonably impair (economically or operationally) the operation of Trimble County Unit I; and

(b)the cost of such use, enlargement, modification, or relocation of Trimble County Unit 1 facilities or Trimble County General Plant Facilities, in connection with such other unit or units or facilities, shall be borne by Louisville (except that if such use, enlargement, modification, or relocation of Trimble County Unit 1 facilities or Trimble County General Plant Facilities is in connection with the installation, enlargement, modification, or operation of any additional unit or units or facilities which are owned or to be owned by the Parties in common, then the cost of such use, enlargement, modification, or relocation of said Trimble County Unit 1 facilities or Trimble County General Plant Facilities shall be shared by the Parties in proportion to their respective ownership Interests In such additional unit or units or facilities); and

(c)such action shall not enlarge or diminish the respective ownership interests of the Parties In any part of Trimble County Unit I; and

(d)such action shall not enlarge or diminish their respective obligations to share In the costs of any part of Trimble County Unit 1; and.

(e)further, when modification of existing property and rights requires revisions to existing documents setting forth the respective rights and interests of the Parties, or where new

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conveyances are required to properly effectuate the modifications to property and rights made hereunder, the Parties apse to cooperate to promptly execute and deliver such documents.

ARTICLE 3

PURCHASE, PAYMENT, AND CLOSING

3.1Purchase Price.

The purchase price for IMEA’s 12.12 percent undivided ownership interest in Trimble County Unit 1 shall be $94,164,428.00 (‘Purchase Price’), paid as follows:

3.2Deposit.

IMEA shall deposit $250,000 in the form of a cashier’s check (“Escrow”) with Escrow Holder (an independent financial institution selected by Louisville) immediately upon execution of this Agreement (“Deposit No. 1”)

3.3Final Payment.

At Closing IMEA will pay, in immediately available funds, the balance due on the Purchase Price after application of all cash deposits previously made (‘Final Payment’). Interest which has accrued on all cash deposits shall be applied in favor of IMEA at Closing toward the balance due on the Purchase Price

3.4Closing.

3.5Date And Place.

Provided that the conditions in Article 3.4 hereof have been fulfilled, Closing shall occur on or before the Commercial Operation Date (except as otherwise provided in Article 3.3 hereof), at such location as may be selected by the Parties, on a mutually acceptable date to be determined by the Parties. Not less than ten (10) days prior to the date on which the Commercial Operation Date is scheduled to occur, Louisville shall give IMEA notice thereof.

3.6Delivery Of Documents. Certificates. And Funds.

At the Closing, Louisville shall deliver to IMEA the Bill of Sale, deed, easement, license, the release of any and all indentures of the ownership interest in Trimble County Unit 1 to be conveyed to IMEA hereunder at the Closing from the lien of such indenture(s), and all certificates and evidences of authorizations, approvals, and documents as provided for herein. IMEA shall deliver to Louisville the Final Payment, to be paid at the Closing, in immediately available funds and all certificates, easements, and evidences of authorizations, approvals, and documents as provided for herein.

3.7Extension Of Time For Closing.

IMEA may extend the date for Closing (as set forth in Article 3.2.1    above) a maximum of ninety (90) additional days, if and only if IMEA deposits with Escrow Holder an additional $500,000

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in the form of a cashier’s check (‘Deposit No. 2’), which shall be held in Escrow along with Deposit No. 1. Upon the Closing, Deposit No. 2, including interest accrued thereon, shall be applied toward the Final Payment.

3.8Special Conditions.

IMEA’s obligation to complete the transaction as contemplated in this Article shall be subject to the fulfillment, prior to Closing, of each of the following special conditions:

(a)IMEA shall have obtained entitlement or contractual ~ authority and any required regulatory approval for the use of such transmission system or systems as are necessary to transmit power and energy from the Delivery Points to IMEA.

(b)IMEA shall have issued and sold tax-exempt bonds sufficient in amount to pay for any and all sums due to be paid by IMEA to Louisville at Closing.

(c)The Parties shall have executed the Interchange Agreement.

IMEA shall endeavor in good faith to fulfill each of these special conditions as soon as reasonably practicable. IMEA shall regularly report on its progress to Louisville. Louisville shall endeavor in good faith to conclude and execute the Interchange Agreement.

Should IMEA fail or be unable to close by Closing, or by such time as Closing may be extended pursuant to Article 3.3 hereof, due to Its inability to meet these special conditions, the Agreement shall terminate without penalty to either Party.

3.9Liquidated Damages.

The Parties agree that in the event the Escrow is terminated by reason of any default of IMEA, then Louisville shall be released from any and all obligations to IMEA under this Agreement. Furthermore, IMEA and Louisville agree that in such event, the amount of damages that Louisville will suffer will be impractical or extremely difficult to determine, and that, therefore, (1) in the event default occurs and IMEA has not extended the time for Closing pursuant to Article 3.3 above, Louisville shall receive Deposit No. I and the interest which is accrued thereon, as liquidated damages, which shall be its sole and exclusive remedy; or (2) in the event default occurs and IMEA has. extended the time for Closing pursuant to Article 3.3 above, Louisville shall receive Deposit No. I and the interest which has accrued thereon ~ and Deposit No. 2 and the interest which has accrued thereon as liquidated damages, the total of which shall be its sole and exclusive remedy. Furthermore, in the event of such default, Escrow Holder is irrevocably authorized and instructed to release and pay said deposit or deposits, including all interest accrued thereon, to Louisville.

3.10Continued Marketing By Louisville.

IMEA understands and acknowledges that Louisville may be subject to certain risks and opportunity costs should Closing not occur. IMEA shall undertake to keep Louisville promptly and adequately informed of its efforts and progress toward satisfying the conditions set forth in Article 3.4 above, as well as any event, situation, or occurrence which could adversely affect IMEA’s ability or decision to close as scheduled. In this regard, IMEA shall regularly, no less frequently than monthly, report on its efforts and progress, and shall declare its intention to close as scheduled.

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Except as otherwise specifically provided in this Agreement, IMEA also understands and acknowledges that Louisville, in its sole discretion, reserves the right to sell prior to and subsequent to the Closing, all or any portion of Trimble County Unit 1 or the output thereof, including the Trimble County General Plant Facilities and the Trimble County Site, other than the portion to be conveyed to IMEA hereunder.

3.11Termination If Closing Does Not Occur.

Should Closing not occur at the time set for Closing under Articles 3.2.1 or 3.3, as the case may be, due to any default or failure to satisfy any condition or contingency by IMEA, this Agreement shall immediately terminate with Louisville having no further obligation or liability hereunder.  In such event, IMEA shall remain pursuant to Article 3.5.

ARTICLE 4

REPRESENTATIONS, WARRANTIES, AND MUTUAL COVENANTS

4.1IMEA Representations.

IMEA hereby represents and warrants to Louisville as follows:

4.2IMEA Organization.

IMEA is a body politic and corporate duly organized, validly existing and in good standing under the laws of the State of Illinois, has the full power, legal capacity, and authority to enter into this Agreement and related agreements, and to carry out the transactions contemplated by this Agreement, and to carry on its business as it is now being conducted and as it is contemplated to be conducted after the Closing. IMEA has delivered to Louisville on or before the Closing a true and complete copy of its Agency Agreement and By-Laws as amended to date.

4.3Authority Relative To This Agreement.

The execution, delivery, and performance by IMEA of this Agreement have been duly authorized by all necessary corporate action on the part of IMEA, and the execution, delivery, and performance by IMEA of the Interchange Agreement will have been duly authorized by all necessary corporate action on the part of IMEA prior to Closing. The execution, delivery, and performance by IMEA of this Agreement and the Interchange Agreement do not contravene any law, or any governmental rule, regulation, or order, applicable to IMEA or its properties, or the Agency Agreement or By-Laws of IMEA and do not and will not contravene the provisions of, or constitute a default under, any indenture, mortgage, contract, or other instrument to which IMEA is a party or by which IMEA is bound, and this Agreement constitutes a legal, valid; and binding obligation of IMEA, enforceable in accordance with its terms, except as limited by applicable bankruptcy, insolvency, reorganization, or similar laws at the time in effect.

4.4Approvals And Consents.

Any consent or approval of, giving of notice to, registration with, or taking of any other action by any state, federal, or other governmental commission, agency, or regulatory authority including, without limitation, the Illinois Commerce Commission, the Federal Energy Regulatory Commission, and the Securities and Exchange Commission, in connection with the execution,

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delivery, and performance of this Agreement and the Interchange Agreement required to be obtained by IMEA on or before the Closing will have been obtained by the Closing.

4.5Legal Proceedings.

There is no materially adverse legal action, suit, arbitration, governmental investigation, or other legal or administrative proceeding, or any order, decree, or judgement in progress, pending or in effect, or to the knowledge of IMEA threatened against or relating to IMEA in connection with or relating to the transactions contemplated by this Agreement, and IMEA does not know or have any reason to be aware of any basis for the same.

4.6Louisville Representations.

Louisville hereby represents and warrants to IMEA as follows:

4.7Louisville Organization.

Louisville is a corporation duly organized and validly existing under the laws of the Commonwealth of Kentucky, and has corporate power to carry on its business as it is now being conducted and as it is contemplated to be conducted after the Closing. Louisville has delivered to IMEA on or before the Closing a true and complete copy of its Articles of Incorporation and By-Laws as amended to date.

4.8Authority Relative To This Agreement.

The execution, delivery, and performance by Louisville of this Agreement and the Interchange Agreement have been duly authorized, or by Closing, will be ratified by all necessary corporate action on the part of Louisville, do not contravene any law, or any governmental rule, regulation, or order, applicable to Louisville or its properties, or the Articles of Incorporation or By-Laws of Louisville and do not and will not contravene the provisions of, or constitute a default under, any indenture, mortgage, contract, or other instrument to which Louisville is a party or by which Louisville is bound, and this Agreement constitutes a legal, valid, and binding obligation of Louisville, enforceable in accordance with its terms, except as limited by applicable bankruptcy, insolvency, reorganization, or similar laws at the time in effect.

4.9Approvals And Consents.

Any consent or approval of~, giving of notice to, registration with, or taking of any other action by any state, federal, or other governmental commission, agency, or regulatory authority including, without limitation, the Kentucky Public Service Commission, the Federal Energy Regulatory Commission, and the Securities and Exchange Commission, in connection with the execution, delivery, and performance of this Agreement and the Interchange Agreement required to be obtained by Louisville on or before the Closing will have been obtained by the Closing.

4.10Legal Title.

Louisville has good and marketable title to the assets conveyed to IMEA free and clear of all liens, except easements, restrictions, and stipulations of record, and the lien of current real property taxes not delinquent. Within two weeks of the Execution Date, Louisville shall provide to IMEA a

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list of all easements, restrictions, and stipulations of record. Within thirty days thereafter, IMEA shall consent to such easements, restrictions, and stipulations of record, which consent shall not unreasonably be withheld, if it reasonably determines that the easements, restrictions, and stipulations of record will not adversely affect the marketability of said title. Should IMEA reasonably refuse to consent to any such easement, restriction, or stipulation of record, Louisville, at its option and at its expense, may (i) remove such easement, restriction, or stipulation of record from the property, or (ii) remove the limiting language ‘except easements, restrictions, or stipulations of record’ from the representation of good and marketable title in this Article, and convey good and marketable title subject only to current taxes not delinquent, or (iii) purchase standard form title insurance with respect to the real estate to be conveyed herein in favor of IMEA, which title insurance, if obtainable, will insure over any easement, restriction, or stipulation of record adversely affecting marketability of said title, reasonably objected to by IMEA. If title insurance is obtained under this provision in favor of IMEA, Louisville shall be responsible for the cost of such title insurance covering the real estate conveyed to IMEA, up to a maximum of $5000.00, with IMEA being responsible for the cost of such Insurance above $5000.00.

4.11Condition of Plant and Equipment.

As of the Commercial Operation Date, the portions of the Trimble County Plant pertaining to Trimble County Unit 1 are capable of full operation, according to their design and specifications, and all applicable performance tests for Trimble County Unit 1 and the Trimble County General Plant Facilities have been completed satisfactorily, except as set forth in a certificate in the form attached as Appendix H hereto, which certificate shall be delivered by Louisville to IMEA at Closing. Louisville shall act with reasonable dispatch to satisfactorily complete, at its expense, all uncompleted work and performance tests set forth in the certificate.

4.12Legal Proceedings.

There is no materially adverse legal action, suit, arbitration, governmental investigation, or other legal or administrative proceeding, or any order, decree, or judgement in progress, pending or in effect, or to the knowledge of Louisville threatened against or relating to• Louisville in connection with or relating to the transactions contemplated by this Agreement, and Louisville does not know or have any reason to be aware of any basis for the same.

ARTICLE 5

OPERATING ARRANGEMENTS

5.1Authority For Operation And Management.

Subject to any directions from the Coordination Committee, Louisville shall have sole authority to manage, control, maintain, and operate (including dispatch) Trimble County Unit I for the benefit of each Party’s respective interest and Louisville shall take all steps which it deems necessary or appropriate for that purpose. Louisville shall discharge such authority in accordance with Good Utility Practice and the other provisions. of this Agreement.

5.2Scheduling And Dispatching Of Electric Generation.

When Trimble County Unit I is in operational service, IMEA shall have the right to schedule, subject to the scheduling provisions herein, all, or any part that is five (5) megawatts or greater, of its

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Electric Capability and Energy Entitlement in Trimble County Unit I (or as such Electric Capability and Energy Entitlement may be modified herein); provided, that during periods when Trimble County Unit 1 is being operated at minimum generation, IMEA, unless otherwise agreed to by Louisville, shall not schedule less than what its Electric Capability and Energy Entitlement in Trimble County Unit 1 would have been had the Net Electric Generating Capability and Associated Electric Energy of Trimble County Unit 1 been restricted to such minimum generation. Louisville shall promptly notify IMEA of any significant change in the Net Electric Generating Capability of Trimble County Unit 1. As used in this paragraph, the term ‘minimum generation’ means the Net Electric Generating Capability level below which Trimble County Unit 1 cannot operate in a stable manner and must be shut down.

Louisville and IMEA shall each be entitled to dispose of their respective Electric Capability and Energy Entitlement through scheduled transactions with other electric utilities in a manner consistent with Good Utility Practice.

IMEA shall schedule Electric Energy to be delivered pursuant to this Agreement prior to 12:00 noon E.S.T. of the day prior to delivery; provided that, for Saturdays, Sundays, Mondays, and holidays recognized by Louisville, IMEA shall schedule the Electric Energy prior to 12:00 noon E.S.T. on the last normal work day prior to the weekend or holiday. Schedules shall be subject to change after 12:00 noon E.S.T. of the applicable day on which the schedule is submitted only upon the mutual consent of the Parties, but Louisville shall make every reasonable effort to accommodate changes in the schedules. Prior to each calendar year, Louisville shall notify IMEA of the holidays to be recognized by Louisville for that year. In the event Louisville fails to provide such notice, the said holidays shall be the same as for the prior year.

Louisville will provide to IMEA, by 9:00 A.M. each day, the Net Electric Generating Capability expected for the next day; provided that, for Saturdays, Sundays, Mondays, and holidays recognized by Louisville, Louisville will provide this information on the last normal work day prior to the weekend or holiday. \t all times, Louisville will Immediately Inform IMEA of any increase or decrease in unit Net Electric Generating Capability that will or may occur, or any suspected conditions that could cause such change.

At any time IMEA is not requesting, for any reason, including a claim by IMEA of Force Majeure, the maximum amount of Net Electric Generating Capability available to it from Trimble County Unit 1, Louisville shall have the right to utilize, for its own use, all or any part of the Electric Energy associated with such unused Net Electric Generating Capability. When so utilized, the energy consumed by Louisville shall be referred to as ‘Banked Energy.’ At a future date, IMEA shall be entitled to request, in accordance with the scheduling provisions of Article 5.2, Electric Energy associated with the Net Electric Generating Capability from Louisville’s portion of Trimble County Unit 1 in an amount equal to all or any portion of the then-current balance of Banked Energy due to IMEA. Louisville shall be obligated to supply the requested amount of IMEA’s Banked Energy unless, pursuant to guidelines established by the Coordination Committee, conditions are unsuitable to do so. Pursuant to procedures and guidelines established by the Coordination Committee, the balance of Banked Energy owed to IMEA shall be periodically returned to zero. When Banked Energy is used by Louisville or returned to IMEA, the Fuel/Reactant Operation Expenses for the Electric Energy associated therewith shall be assumed by the Party using such Electric Energy. Louisville shall maintain records adequate to determine the transactions related to, and balances of, Banked Energy.

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Louisville shall submit to IMEA, as far in advance as practicable, schedules showing the expected time and duration for maintenance and repair outages of Trimble County Unit 1. Louisville will adjust such. schedules to accommodate IMEA’s operating needs, where, in Louisville’s sole judgement, it is practicable to do so, consistent with Good Utility Practice. Should IMEA desire a schedule for maintenance and repair outages which Louisville believes is impracticable, IMEA shall be entitled to raise the scheduling issue with the Coordination Committee.

5.3Economic Replacement of Trimble County Unit 1 Energy.

In the event, and only in the event, Louisville voluntarily ceases to operate Trimble County Unit I solely because of the availability of Electric Energy to Louisville from other sources, the cost of which is projected to be lower than what the cost of Fuel/Reactant Operation Expenses of Electric Energy generated by Trimble County Unit 1 would be during the period of such cessation in operation, Louisville shall make available to IMEA replacement Electric Energy from such other sources during the period of such cessation in operation. The amount of such replacement Electric Energy to be made available to IMEA during such period shall be the amount of Electric Energy requested by IMEA during such period, but not in excess of the. amount to which IMEA would have been entitled during such period had the operation of Trimble County Unit 1 not ceased.  The per kilowatt-hour cost of such replacement Electric Energy shall be the per kilowatt-hour cost incurred by Louisville for such replacement Electric Energy obtained from such other sources during such period.

5.4Electric Capability And Energy Entitlements.

Louisville and IMEA shall be entitled to the Net Electric Generating Capability and Associated Electric Energy of Trimble County Unit 1 in proportion to their respective ownership interests in Trimble County Unit 1; however, the Net Electric Generating Capability of Trimble County Unit 1 shall not exceed the applicable Net Seasonal Capability of Trimble County Unit 1, except under criteria as may be established by the Coordination Committee..  These entitlements shall being with the Commercial Operation Date of Trimble County Unit 1 (or Closing, if later) and continue until Trimble County Unit 2 ceases to be used for the generation of Electric Energy

5.5Precommercial Energy.

Any net Electric Energy output from Trimble County Unit 1 prior to the Commercial Operation Date of Trimble County Unit 1 shall be classified as precommercial energy.  Louisville shall be entitled to 100 percent of such precommercial energy.

5.6Operations Management.

5.6.1Administration Of Operating Work And Incremental Capital Assets.

Louisville shall perform all work, or execute, and enforce (including any renegotiation and settlement) all contracts, contractual obligations and arrangements for Operating Work and Incremental Capital Assets, including, without limitation, any and all warranties on equipment, facilities, materials, and services furnished pursuant to any such contracts. Warranties and claims arising under this Article shall be administered in accordance with the provisions of Article 5.6.6 of this Agreement.

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5.6.2Purchasing Necessary Goods And Services.

Louisville shall purchase and procure, through and from any source it may select, the equipment, apparatus, machinery, tools, services, materials and supplies, and emergency spare parts necessary for the performance of Operating Work and Incremental Capital Assets.

5.6.3Procurement of Fuel.

At all times, Louisville shall make necessary and reasonable efforts to maintain an adequate supply of fuel. At IMEA’s request, Louisville will receive bids or proposals from suppliers of Illinois coal who wish to be considered for purchases of coal supplies for Trimble County Unit 1. Louisville shall have no obligation to consider any particular bid or proposal, which in Louisville’s sole judgement, is not In the best interest of the Parties when considering price, reliability, quality, and other relevant terms, conditions, and considerations.

5.6.4Expenditure Of Funds.

Louisville shall expend funds in accordance with the terms and conditions of this Agreement.

5.6.5Insurance.

Louisville shall arrange for the placement and maintenance of Insurance, as provided herein in Article 13.

5.6.6Enforcement Of Claims Against Third Parties.

Louisville shall present and prosecute known claims against third parties, including but not limited to claims against insurers and indemnitors providing Insurance or indemnities with respect to any loss of or damage to any property of Trimble County Unit 1, or the Trimble

County General Plant Facilities or the Trimble County Site as they pertain to Trimble County Unit 1, or any interest of the Parties pertaining thereto, and with respect to any liability of Louisville or IMEA to third parties covered by Insurance or indemnity agreement. To the extent that such loss, damage, or liability is not covered by Insurance or by any indemnity agreement, Louisville shall present and prosecute claims therefor against any parties who may be liable therefor. Nothing herein shall require Louisville to initiate, present, or prosecute any claim which, in Its sole judgement, Is without sufficient merit to warrant such enforcement, or otherwise is Inconsistent with the Parties’ general business interests. Nothing herein shall require Louisville to-invoke any certain type of enforcement procedure, or to seek, or to continue to seek, enforcement of any claim, when in Louisville’s sole judgement, the Parties’ general business interests are better served by settling or withdrawing such claim.

In the event that Louisville should fail or refuse to diligently prosecute any claim, nothing herein contained shall prevent IMEA from prosecuting such claim or demand in its own name, to the extent of, and as such claim or demand affects, its interest. IMEA may intervene in any suit on a claim pursuant to this Article as an additional plaintiff or defendant to assert or defend as to its respective ownership interest and rights. Cost and monies net of reasonable expenses recovered are to be shared by the Parties in proportion to their respective ownership interests in Trimble County Unit 1.

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5.6.7Processing Claims By Third Parties.

Louisville shall investigate, adjust, defend, and settle claims by third parties against IMEA and Louisville, arising out of or attributable to Operating Work or Incremental Capital Assets, or the past or future performance or nonperformance of the obligations and duties of either IMEA or Louisville under or pursuant to this Agreement, including but not limited to any claim resulting from death or injury to persons or damage to property, when such claims are not covered by valid and collectible Insurance carried by Louisville or IMEA; and, whenever and to the extent reasonable, present and prosecute claims against any third party, including insurers, for any costs, losses, and damages incurred in connection with such claims. If any such claim against IMEA and Louisville is in excess of $50,000 in amount and is not covered by valid and collectible Insurance carried by Louisville or IMEA, Louisville shall notify IMEA of the existence and nature of such claim and shall also notify IMEA if and when any settlement of such claim is accomplished by Louisville. Settlement of claims in excess of $1,000,000 shall be reported to and approved by the Coordination Committee.

In the event that Louisville should fail or refuse to diligently defend any claim, nothing herein contained shall prevent IMEA from defending such claim or demand in its own name, to the extent of, and as such claim or demand affects, its interest. IMEA may intervene in any suit on a claim pursuant to this Article as an additional party to defend as to its respective ownership interests and rights in Trimble County Unit 1.

5.6.8Delivery Of Operating Data.

As promptly as practicable after the end of each month, Louisville shall render to IMEA a statement setting forth appropriate operating data as may be needed for reports and records.

5.7Environmental Laws and Regulations.

Each Party shall be responsible for its own share of any obligations, costs, or burdens of any kind, resulting from any federal, state, or local environmental law, regulation, or requirement, as amended from time to time. Similarly, each Party shall be entitled to its share, on a pro rata ownership basis, of any rights, credits, or entitlements associated with such law, regulation, or requirement.

Louisville’s obligation to produce generation from IMEA’s share of Trimble County Unit 1, as well as Louisville’s obligation to produce backup power and energy as set forth in Article 10 hereof, shall be conditioned upon IMEA’s compliance with such laws, regulations, or requirements as set forth in this Article, and IMEA’s possession of required environmental allowances needed for such generation. In the event IMEA’s rights, credits, or entitlements are not sufficient to allow the desired level of generation from IMEA’s share of Trimble County Unit I or the production of backup power and energy, Louisville shall provide such rights, credits, or entitlements to IMEA upon IMEA’s request and after consultation between the Parties concerning the availability and cost of such rights, credits, or entitlements. Louisville shall have no obligation, however, to provide such rights, credits, or entitlements where such rights, credits, or entitlements are required for use by Louisville to serve its Internal Load plus any firm off-system sales. Louisville may satisfy this obligation, at its option, by supplying such rights, credits, or entitlements from its own system, or by purchasing from other sources. Such obligation shall be limited to the rights, credits, or entitlements necessary to operate IMEA’s portion of Trimble County Unit 1 at the lower of an 80 percent

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Capacity Factor or IMEA’s actual Capacity Factor, and shall apply only to the excess requirements above the rights, credits, or entitlements obtained by IMEA as a result of its ownership interest in Trimble County Unit 1 or from other sources.

IMEA shall compensate Louisville for providing such allowances for IMEA’s Trimble County Unit 1 generation, as well as for allowances for backup power and energy sold by Louisville to IMEA under Article 10 hereof, at a price equal to the fair market value of such allowances, as such value may change from time to time. Fair market value and procedures for billing and payment will be determined according to criteria set forth by the Coordination Committee; provided that, fair market value shall not be less than Louisville’s. actual cost of providing or obtaining such allowances.

5.8Limited Re-Opener:  Environmental Legislation.

It is recognized by the Parties that this Agreement will be executed prior to the disposition of the proposed Clean Air Act Amendments of 1990 legislation pending in Congress. For the period between the Execution Date and Closing, each Party shall have the right to re-open negotiations on matters related to environmental issues, should the result of such legislation enacted by Congress result in either Party receiving required environmental allowances less than those provided by Senate Bill No. 1630, as passed by the Senate on April 3, 1990.

5.9Indemnification of Environmental Fines and Penalties.

Louisville will indemnify IMEA against administrative fines and civil penalties arising out of the operation of the Trimble County Plant imposed for violations of applicable environmental laws and regulations, resulting from acts of Louisville as plant operator. Exclusions from this special indemnification shall include operation and maintenance costs which might be incurred as a result of environmental laws and regulations, Incremental Capital Assets incurred in environmental compliance, occurrences from acts of third parties or from equipment failure or malfunction, remedial measures imposed by administrative agencies for environmental purposes, or reimbursement of response costs under Comprehensive Environmental Response Compensation And Liability Act (CERCLA) and K.R.S. Chapter 224, or to any claims of personal injury or property damage.

ARTICLE 6

INCREMENTAL CAPITAL ASSETS

6.1Determination Of Need.

The Coordination Committee shall approve Incremental Capital Assets expected to cost over $250,000. Louisville shall have the authority to make all decisions with respect to Incremental Capital Assets expected to cost $250,000 or less. Emergency expenditures for Incremental Capital Assets which total in excess of $250,000 in any calendar year shall be submitted to the Coordination Committee for ratification.

6.2Estimate Of Costs.

Prior to beginning of work on any Incremental Capital Asset which Louisville expects to cost more than $1,000,000, such estimate shall be furnished by Louisville in reasonable detail to IMEA

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for use by it in anticipating its financial requirements. Such estimate shall be subject to revision periodically to reflect more current information on such Incremental Capital Asset.

6.3Responsibility For Costs.

Subsequent to the Closing, the costs of each Incremental Capital Asset shall be borne by Louisville and IMEA in proportion to their respective percentage ownership interests in Trimble County Unit 1. IMEA’s share of the Incremental Capital Assets shall be subject to the Service Fee as set forth In Article 7.1.6 herein. The amount incurred for Incremental Capital Assets during each month shall be included in the monthly billings provided for in Article 8.1.

ARTICLE 7

COMPENSATION

7.1Monthly Charges.

Louisville and IMEA will share all costs associated with Trimble County Unit 1, and with the Trimble County General Plant Facilities and the Trimble County Site as they pertain to Trimble County Unit 1. These costs are set forth below in six components for billing and accounting purposes. The Parties intend that these components incorporate all costs which are or could be associated with Trimble County Unit 1, and with the Trimble County General Plant Facilities and the Trimble County Site as they pertain to Trimble County Unit 1. Should, however, any item or category of costs not fall within the technical definitions of any of the six components, the Parties agree to adjust the billing components so as to Include such item or category.

Starting at the Closing or Commercial Operation Date, if later, IMEA shall pay a monthly amount equal to the sum of the six components delineated in Articles 7.1.1, 7.1.2, 7.1.3, 7.1.4, 7.1.5, and 7.1.6, as provided for in Article 8.1.

7.1.1Fuel/Reactant Operation Expense.

All Fuel/Reactant Operation Expenses. of Trimble County Unit 1 will be prorated to the Parties, according to the net Electric Energy consumed by each Party as compared to the total net energy generated by Trimble County Unit 1.

For purposes of this Article, Fuel/Reactant Operation Expenses shall be allocated to IMEA on the basis of its loss-adjusted net Electric Energy during the applicable month. This loss-adjusted net Electric Energy shall be calculated by multiplying IMEA’s actual Trimble County Unit 1 net Electric Energy during the month by a loss factor (currently 1.0038), which, at the request of either Party, but not more frequently than once every two years, shall be reviewed based on load flow studies or other mutually acceptable analyses, and shall be adjusted as appropriate.

7.1.2Fixed Operation And Maintenance Expenses.

A Fixed Operation and Maintenance Expenses component shall be shared by the Parties in proportion to their respective percentage ownership interest in Trimble County Unit 1.

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7.1.3Non-Fuel Operating Component.

A non-fuel operating component shall be shared by the Parties in proportion to their respective percentage ownership interest in Trimble County Unit 1, calculated monthly as the sum of the following four

Items as they relate to Trimble County Unit 1, and the Trimble County

General Plant Facilities and the Trimble County Site as they pertain to Trimble County Unit 1:

(a)Taxes other than federal and state income taxes (Account 408.1), except that those categories of taxes, or payments in lieu thereof, that are directly billed to IMEA by the taxing authority and paid by IMEA, shall not be included in this item.

(b)Administrative and general expenses (Accounts 920.935) as recorded in Louisville’s accounting records under the Uniform System of Accounts.

(c)Lease payments which result from a third-party financed Incremental Capital Asset.

(d)Penalties (Account 426.3), except for those environmental penalties against which Louisville is indemnifying IMEA under Article 5.7 hereof.

7.1.4Working Capital Component.

Beginning with the billing covering the period January, 1996, and for each month thereafter, a working capital component shall be shared by the Parties in proportion to their respective percentage ownership interests in Trimble County Unit 1. This component is comprised of the items listed below, to the extent that each of these items relates to Trimble County Unit 1, the Trimble County General Plant Facilities (as they pertain to Trimble County Unit 1), and the Trimble County Site (as it pertains to Trimble County Unit 1).  This component shall be calculated by multiplying the beginning monthly balances of the items by Louisville’s Cost of Capital as “grossed up” for federal and state income taxes.

(a)Fuel stocks (Account 151).

(b)Fuel stock expenses undistributed (Account 152).

(c)Plant materials and operating supplies (Account 154).

(d)Stores expense undistributed (Account 163).

(e)Prepayments (Account 165).

(f)Miscellaneous deferred debits (Account 186).

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7.1.5Transmission Charge.

A transmission charge to cover transmission of the Electric Energy from Trimble County Unit 1 to the Delivery Points shall be assessed according to the Trimble County schedule contained in the Interchange Agreement.  Such schedule may be changed by Louisville from time to time based on revised cost information, but shall continue to be calculated throughout the duration of this Agreement according to the same cost of service methodology as was used to support the initial schedule.  Should FERC at any time decline to accept a rate based on such methodology, a new rate shall be calculated using approved methodology as close as possible to the Initial methodology such that the original intent of the Parties in pricing this service shall be maintained.

7.1.6Service Fee.

After Closing, a service fee, equal to five (5) percent of all payments by IMEA, other than the initial payment as set forth in Article 3 or the monthly transmission charge in Article 7.1.5, shall be assessed; except that for billings related to the calendar years in the following table, the service fee shall be calculated using the percentage indicated for the respective year.

Year	Service Fee (%)
1991	0.00
1992	1.25
1993	2.50
1994	3.75
On and after Jan. 1, 1995	5.00

ARTICLE 8

BILLING, PAYMENTS, AND RECORDS

8.1Billings By Louisville.

As promptly as practicable, but not more than twelve working days, after the end of each calendar month during the term of this Agreement, Louisville shall prepare and send to IMEA a statement, in such detail and with such segregations as may be needed for operating and accounting records, to indicate monthly amounts due under the provisions of this Agreement.

8.2Payments By IMEA or Louisville.

All bills under Article 8.1 for amounts owed by IMEA to Louisville shall be due and payable on the tenth calendar day following the invoice date.  Amounts owing by either Party to the other under the Interchange Agreement or under the provisions of this Agreement, other than under Article 8.1, shall be settled in accordance with the procedures set forth in such provisions as give rise to the obligations.  Interest on unpaid amounts shall accrue at the Agreed Rate from the date due until the date upon which payment is made.  Unless otherwise agreed upon, a calendar month shall be the standard monthly period for the purpose of settlements under this Agreement.

Should either Party withhold payment of any contested amount, the procedure for resolution of disputes under Article 19 shall be invoked automatically.  Non-payment of any amount contested

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in good faith by either Party shall not constitute a default under Article 17 prior to completion of the disagreement procedures under Article 19.  The unpaid Party may contend a default exists under Article 17, if payment continues to be withheld following completion of the disagreement procedures under Article 19 including arbitration if both Parties have elected to arbitrate.

8.3Records.

Louisville will record its accounting information in accordance with generally accepted accounting principles, as modified by the requirements or permitted practices of applicable regulatory authorities.  For the purpose of this Agreement, all account references are to the Uniform System of Accounts.  in the event of any changes in FERC’s accounting procedures which might result in different charges than those contemplated by the Agreement, the Parties will agree upon the appropriate changes to the Agreement to achieve the original intent of the Parties, unless otherwise mutually agreed by the Parties.

The Parties shall keep and maintain such records as may be necessary or useful in carrying out this Agreement.  Each Party shall keep such records as may be needed to afford a clear history of all transactions under this Agreement and make copies of such records available to the other Party upon request.  Each Party shall have the right during normal business hours, but no more often than once each calendar year, at its own expense, to audit, or cause independent certified public accountants of its choice to audit, the accounting and other records relating to transactions under this Agreement and shall have the right to make copies of records as necessary.  All such records shall be considered confidential and proprietary business records of the Party that generated the particular record in question.  Neither Party shall make use of records of the other Party without the express written consent of such Party, except for disclosure or use which is permitted by this Agreement or where required by lawful authority.

ARTICLE 9

TRANSMISSION SERVICE

All Electric Energy delivered under this Agreement shall be of the character commonly known as three-phase sixty-hertz energy, and shall be considered as being delivered at Louisville’s Delivery Points.

Obtaining transmission service for transmitting power under this Agreement from Louisville’s Delivery Points shall be the sole responsibility of IMEA.  If an electric system or systems, which is not part of the electric systems owned by either of the Parties, is used to transmit the Net Electric Energy from Louisville’s Delivery Points to IMEA, the cost of such transmission service shall be paid by IMEA.  Losses which are incurred through such third party transmission(s) shall be assumed by IMEA.  in the event Louisville and IMEA establish a direct electrical interconnection during the term of this Agreement, the Parties can mutually agree to use such direct electrical interconnection to transmit all or part of the energy from Louisville to IMEA for the remainder of this Agreement.

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ARTICLE 10

BACKUP POWER AND ENERGY

10.1From Louisville.

In any hour of any month that the Net Electric Generating Capability of Trimble County Unit 1 is less than the Net Seasonal Capability, IMEA shall have the option to request from Louisville backup power and energy from Louisville’s other generating resources.  For IMEA to receive this backup power and energy, both of the following conditions must be met:

The amount of backup power and energy shall not exceed an amount equal to IMEA’s share (based on its percentage ownership interest in Trimble County Unit 1) of such reduction from Net Seasonal Capability.

The amount of backup power and energy requested, as limited by (a) above, is available from Louisville’s other generating resources and is not required to serve Louisville’s Internal Load or to honor any firm commitments made by Louisville for off-system sales, existing prior to any particular request for backup power and energy.

Compensation for backup power and energy will correspond to the demand and energy rate provisions of the Backup Power service schedule contained in the Interchange Agreement in effect at the time backup energy is delivered.

10.2From Third Parties.

In the event Louisville is unable to provide backup power and energy from its own system, Louisville will, at the request of IMEA, make its best effort to purchase backup power and energy from another party for resale to IMEA.  Louisville will bill IMEA for such purchased backup power and energy according to the terms for such third party transactions contained in the Backup Power service schedule contained in the Interchange Agreement in effect at the time backup energy is delivered.

10.3Effective Date of Backup Power Provision.

The provisions of this Article 10 will become effective on the earlier of January 1, 1991 or the Commercial Operation Date of Trimble County Unit 1.

ARTICLE 11

GENERAL CONDITIONS

11.1Cooperation.

Louisville and IMEA shall cooperate with each other and provide information as may be necessary to facilitate, among other things, the filing of applications for authorizations, permits, licenses, or financings and the execution of such other documents as may be reasonably necessary to carry out the provisions of this Agreement, subject to reasonable protections necessary to preserve each Party’s confidential or proprietary information.

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11.2Approvals.

The Parties shall use their best efforts to obtain as quickly as possible all requisite governmental and regulatory approvals of the consummation of-the transactions contemplated herein.

11.3Access.

Official representatives of IMEA and their designees, including IMEA’s bond trustee, shall have the right, upon sufficient advance notice to Louisville, to enter upon the Trimble County Site subject to all safety, insurance, and industrial security requirements and the need for efficient operation of Trimble County Unit 1.

11.4Conditions Precedent To Louisville’s Obligations Hereunder.

All obligations of Louisville under this Agreement are subject to the fulfillment, prior to or at the Closing, of each of the conditions (or the waiver in writing of such conditions by Louisville) that are delineated in Articles 11.4.1 through 11.4.4 and IMEA shall exert its best efforts to cause each such condition to be fulfilled.

11.4.1Accuracy Of IMEA’s Representations And Warranties.

Louisville and IMEA shall not have discovered any material error, misstatement, or omission in the representations and warranties made by IMEA in this Agreement.

11.4.2Capability Of Performance By IMEA.

IMEA’s representations and warranties contained in this Agreement shall be deemed to have been made again at and as of the time of the Closing and shall then be true in all material respects; IMEA shall have performed and complied with all agreements, covenants, and conditions required by this Agreement to be performed or complied with by it prior to or at the Closing; Louisville shall have been furnished with certificates signed by the principal officer of IMEA, dated the date of the Closing, certifying in form and substance satisfactory to Louisville to the fulfillment of the foregoing conditions and to the further effect that there are no actions, suits, or proceedings pending or, to such officer’s knowledge, threatened against or affecting IMEA before any court or administrative body or agency which would materially adversely affect the ability of IMEA to perform its obligations under this Agreement.

11.4.3Opinion Of Counsel For IMEA.

Louisville shall have been furnished with an opinion of counsel for IMEA, which counsel shall be satisfactory to Louisville, in form and substance satisfactory to Louisville, dated the date of the Closing, to the effect that:

IMEA is a public body corporate and politic organized as a joint agency by its member municipalities in Illinois in accordance with Illinois law, duly organized and validly existing in good standing under the laws of the State of Illinois and has the corporate power, legal capacity, and authority to carry on its business as presently conducted and to enter into and perform its obligations under this Agreement.

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The execution, delivery, and performance by IMEA of this Agreement have been duly authorized by all necessary corporate action on the part of IMEA, do not contravene any law, or any governmental rule, regulation, or order, applicable to IMEA or its properties, or the Agency Agreement or By-Laws of IMEA and do not and will not contravene the provisions of, or constitute a default under, any indenture, mortgage, contract, or other instrument to which IMEA is a party or by which IMEA is bound;

This Agreement has been duly executed and delivered by IMEA and constitutes the legal, valid, and binding obligations of IMEA enforceable in accordance with its respective terms, except as limited by applicable bankruptcy, insolvency, reorganization, or similar laws at the time in effect;

There are no actions, suits, or proceedings pending or, to such counsel’s knowledge, threatened against or affecting IMEA before any court or administrative body or agency which might materially adversely affect the ability of IMEA to perform its obligations under this Agreement; and

Any consent or approval of, giving of notice to, registration with, or taking of any other action by, any state, federal, or other governmental commission, agency, or regulatory authority, including, without limitation, the Illinois Commerce Commission, the Federal Energy Regulatory Commission, and the Securities and Exchange Commission, in connection with the execution, delivery, and performance of this Agreement required to be obtained by IMEA on or before the Closing has been obtained.

11.4.4Payment Of Funds By IMEA.

The portion of the Purchase Price required to be paid by IMEA to Louisville at the Closing shall be paid in Immediately available funds.

11.5Conditions Precedent To IMEA’s Obligations Hereunder.

All obligations of IMEA under this Agreement are subject to the fulfillment, prior to or at the Closing, of each of the following conditions (or the waiver in writing of such conditions by IMEA):

11.5.1Accuracy Of Louisville’s Representations And Warranties.

IMEA and Louisville shall not have discovered any material error, misstatement, or omission in the representations and warranties made by Louisville in this Agreement.

11.5.2Capability Of Performance By Louisville.

Louisville’s representations and warranties contained in this Agreement shall be deemed to have been made again at and as of the time of the Closing and shall then be true in all material respects.  Louisville shall have performed and complied with all agreements, covenants, and conditions required by this Agreement to be performed or complied with by it prior to or at the Closing and IMEA shall have been furnished with a certificate of the President or a Vice President of Louisville, dated the date of the Closing, certifying in form and substance satisfactory to IMEA, to the fulfillment of the foregoing conditions and to the further effect that there are no actions, suits, or proceedings pending or, to such officer’s knowledge, threatened against or affecting Louisville before any court or administrative body or agency which would adversely affect the ability of Louisville to perform its obligations under this agreement.

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11.5.3Opinion Of Counsel-For-Louisville.

IMEA shall have been furnished with an opinion of counsel for Louisville, which may include counsel employed directly by Louisville as well as Louisville’s outside counsel, which counsel shall be satisfactory to IMEA, in form and substance satisfactory to IMEA, dated the date of the Closing, to the effect that:

Louisville is a corporation duly organized and validly existing under the laws of the Commonwealth of Kentucky and has the corporate power and authority to carry on its business as presently conducted and to enter into and perform its obligations under this Agreement; and

The execution, delivery, and performance by Louisville of this Agreement has been duly authorized by all necessary corporate action on the part of Louisville, does not contravene any law, or any governmental rule, regulation, or order applicable to Louisville or its properties, or the Articles of Incorporation or By-Laws of Louisville, and do not and will not contravene the provisions of, or constitute a default under, any indenture, mortgage, contract, or other instrument to which Louisville is a party or by which Louisville is bound; and

The documents executed by Louisville in connection with the Closing have been duly authorized, executed, and delivered by Louisville; and

There are no actions, suits, or proceedings pending or, to such counsel’s knowledge, threatened against or affecting Louisville before any court or administrative body or agency which would materially adversely affect the ability of Louisville to perform its obligations under this Agreement; and

Any consent or approval of, giving of notice to, registration with or taking of any other action by, any state, federal, or other governmental commission, agency, or regulatory authority, including, without limitation, the Kentucky Public Service Commission, the Federal Energy Regulatory Commission, and the Securities and Exchange Commission, in connection with the execution, delivery, and performance of this Agreement required to be obtained by Louisville on or before the Closing has been obtained.

Louisville’ conveyance to IMEA in fee simple with covenant of general warranty of a 12.12 percent undivided ownership interest as tenants in common in the real estate set forth in Appendix E, is free and clear from all encumbrances, except easements, restrictions, and stipulations of record, taxes assessed and payable in the year 1990 and thereafter, but such opinion will be inapplicable to matters not of record.

Prior to commercial operation of Trimble County Unit 1, Louisville has obtained all permits and licenses required to be obtained in order to commence commercial operation of Trimble County Unit 1.

Louisville has paid all property taxes (other than sales or use or other transfer taxes, if applicable) which are assessed on the interests conveyed to IMEA hereunder, except for property taxes assessed and payable in the year 1990.

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11.6Conditions Precedent To The Respective Obligations Of The Parties.

The respective obligations of Louisville and IMEA hereunder are, unless waived in writing by Louisville and IMEA prior to or at the Closing, subject to the special conditions in Article 3.4 hereof and the additional condition that all governmental and regulatory approvals of the execution, delivery, and performance of this Agreement required to be obtained by Louisville and IMEA on or before the Closing shall have been obtained, including all governmental and regulatory approvals necessary for the issuance of IMEA’s tax-exempt revenue bonds in an aggregate principal amount sufficient to pay for any and all sums due to be paid by IMEA to Louisville at Closing.

11.7Release From Louisville’s Indenture(s).

Louisville shall have obtained the releases from any and all indentures of the ownership interest in Trimble County Unit 1 to be conveyed to IMEA hereunder at the Closing from the lien of such indenture.

11.8Amendments.

This Agreement may be amended only by a written instrument duly executed by the Parties.  When so amended, the Parties shall execute a conformed copy of the Agreement, which conformed copy shall contain all amendments to the Agreement and shall thereafter govern the Parties.

11.9LIMITED WARRANTY.

Louisville warrants that as of the Execution Date hereof, although the Trimble County Plant is still under construction, except as set forth in Appendix D, there are no known defects in the design or construction of Trimble County Unit 1 or the Trimble County General Plant Facilities, and that such facilities were designed for the generation and production of electric power and energy.  Louisville shall act with reasonable dispatch to remedy the defects set forth in Appendix D hereof.

Louisville also warrants that for a period of ninety (90) days from the Commercial Operation Date, Trimble County Unit 1 and the Trimble County General Plant Facilities shall be free of defects in materials or workmanship in the design and construction of such facilities.  This ninety day period shall be extended by one additional week for any week during the ninety day period in which Trimble County Unit 1 does not operate at a Capacity Factor of thirty-three percent or greater.  For this purpose, the first week shall be the seven-day period beginning on the Commercial Operation Date.  Defects that are discovered during this ninety-day period, as it may be extended as set forth above, shall be repaired at Louisville’s expense, and such repairs shall be warranted by Louisville to be free of defects in materials or workmanship in design and construction for a period of any additional ninety days from the completion of such repairs.  OTHER THAN FOR THIS EXPRESS WARRANTY, IMEA’S OWNERSHIP INTEREST IN TRIMBLE COUNTY UNIT 1 IS TO BE SOLD “AS IS” AND “WHERE IS”.  LOUISVILLE MAKES NO OTHER REPRESENTATION OR WARRANTY WHATSOEVER IN THIS AGREEMENT, EXPRESSED, IMPLIED, OR STATUTORY, INCLUDING, WITHOUT LIMITATION, ANY REPRESENTATION OR WARRANTY AS TO THE VALUE, QUANTITY, CONDITION, SALABILITY, OBSOLESCENCE, MERCHANTABILITY, FITNESS, OR SUITABILITY FOR USE OR WORKING ORDER OF ANY OF TRIMBLE COUNTY UNIT 1 INCLUDING THE TRIMBLE COUNTY GENERAL PLANT FACILITIES, NOR DOES LOUISVILLE REPRESENT OR WARRANT THAT THE USE OR OPERATION OF ANY SUCH FACILITIES WILL NOT

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VIOLATE PATENT, TRADEMARK, OR SERVICE MARK RIGHTS OF ANY THIRD PARTIES.  THE PROVISIONS OF THIS ARTICLE 11.9 SHALL GOVERN OVER ANY CONFLICTING PROVISIONS OF THIS AGREEMENT.  Notwithstanding the foregoing, IMEA shall have the benefit, in proportion to its percentage ownership interest in Trimble County Unit 1, of all manufacturers’ and vendors’ warranties and all patent, trademark, and service mark rights running to Louisville in connection with Trimble County Unit 1 and the Trimble County General Plant Facilities as they pertain to Trimble County Unit 1; provided that Louisville shall have sole authority in decisions regarding the enforcement (including any renegotiation and settlement) of such warranties and patent, trademark, and service mark rights, subject to the rights of IMEA as set forth in Article 5.6.6 hereof.

11.10No Agency Or Third Party Beneficiary.

Nothing herein is intended to or shall create an agency whereby IMEA becomes an agent for Louisville in any relationship with any third party.  This Agreement is solely between Louisville and IMEA and shall not be construed to create any third party beneficiary relationship with any other person or entity.

ARTICLE 12

TAXES

12.1Management Of Tax Matters.

Except for IMEA’s payments of property taxes or payments in lieu thereof that are directly billed to IMEA by any taxing authority and which IMEA shall pay directly, and except for any rulings IMEA might require in connection with the issuance of tax-exempt bonds, Louisville shall have the authority and responsibility for administering, coordinating, filing returns, making property tax declarations, paying, seeking official tax rulings or determinations, and other related functions pertaining to all other taxes, payments in lieu of taxes, assessments, impositions, charges, and related costs of every kind and nature, ordinary or extraordinary, general or special, foreseen or unforeseen, settled or pending settlement, including, but not limited to, property, sales, use, and payroll taxes, connected with or arising out of the construction, ownership, operation, maintenance, alteration, repair, rebuilding, use, or retirement of Trimble County Unit 1 or any part thereof, which are or may be imposed by any federal, Kentucky, local, municipal of Kentucky, interregional, or quasi-governmental authority; provided, however, unless specifically authorized in writing by IMEA, such authority and responsibility shall not extend to any act or action affecting any exemption or special tax treatment to which IMEA may be entitled.  IMEA does hereby make and appoint Louisville to be its attorney-in-fact, to act in its name, place, and stead for the purpose of filing returns, making property tax declarations, negotiating, seeking adjustments or revisions, protesting, seeking official tax rulings or determinations, contesting, making application for and claiming any and all exclusions, exemptions, deductions, credits, and ejections pertaining to all such other taxes, payments in lieu of taxes, assessments, impositions, charges, and related costs, but unless specifically authorized in writing to act on its behalf by IMEA, such appointment shall not extend to any act or action affecting any exemption or special tax treatment to which IMEA may be entitled or to any tax or payments in lieu thereof for which IMEA has responsibility for direct payment.  IMEA, its agents, or assigns shall promptly join in any action reasonably required which is consistent with the exercise by Louisville of the tax authority and responsibility described herein and the status of IMEA as a governmental or quasi-governmental entity.

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12.2Sharing or Taxes And Related Payments.

All such taxes, payments in lieu of taxes, assessments, impositions, charges and related costs of Trimble County Unit 1, or the Trimble County General Plant Facilities or the Trimble County Site as they pertain to Trimble County Unit 1, shall be shared and borne by Louisville and IMEA in proportion to their respective percentage ownership interests in Trimble County Unit 1; provided, however, IMEA shall be entitled to the entire benefit to the extent of actual realization, of all exemptions from and reductions of taxes, including but not limited to property, sales, use, and payroll taxes, connected with or arising out of the ownership, operation, maintenance, alteration, repair, rebuilding, use, or retirement of Trimble County Unit 1 or any part thereof, which may be realized because of the provisions, if any, of the Constitutions (of the Commonwealth of Kentucky, the State of Illinois, and the United States of America), statutes, ordinances, rules, regulations, and laws applicable to IMEA and not Louisville.

The portion of such taxes, payments in lieu of taxes, assessments, impositions, charges and related costs that are to be borne by IMEA as set forth above in this Article 12.2 shall be billed to and paid by IMEA in accordance with Articles 7 and 8, as applicable, except for those taxes which are paid by IMEA directly to the taxing authority.

12.3Payment Of Title Taxes And Fees.

Except as may be otherwise provided in this Article 12.3, IMEA shall be responsible for all sales taxes, recording fees, and other taxes related to transfer of property, if any, incurred in connection with the conveyance(s) to IMEA by Louisville at Closing.  It is understood by the Parties that Louisville expects to receive, prior to Closing, a ruling from the Revenue Cabinet of the Commonwealth of Kentucky concerning the applicability of, or exemption from, sales and use taxes of the conveyance to be made at Closing by Louisville to IMEA.  Should the ruling Indicate a position by the Revenue Cabinet that such conveyance is subject to sales and use tax, each Party shall have the right to re-open negotiations on the responsibility of the Parties for such taxes.

12.4Exclusion Of Income Taxes.

Notwithstanding the generality of Article 12.1 above, Louisville and IMEA agree that the foregoing provisions of this Article 12 shall not apply to any tax on or measured by income.

12.5Non-creation Of Taxable Entity.

Notwithstanding any other provision of this Agreement, Louisville and IMEA do not intend to create hereby at law any joint venture, partnership, association taxable as a corporation, or other entity for the conduct of any business for profit.  Louisville and IMEA agree to elect under Section 761(a) of the Internal Revenue Code of 1986, as amended, to exclude the transactions created by this Agreement from the application of Subchapter K, Chapter 1 of the Code, and both Parties agree to revise the terms of this Agreement to the extent and in a manner necessary to permit such election.

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ARTICLE 13

INSURANCE

13.1Procurement Of Insurance.

Except with regard to directors and officers liability insurance, Louisville shall maintain in force, for the benefit of Louisville and IMEA as their interests in Trimble County Unit 1, Trimble County General Plant Facilities, and the Trimble County Site shall appear, such available insurance and self-insurance as the Coordination Committee shall determine to be appropriate.

13.1.1Sharing-Of Insurance Costs.

The costs of such insurance policies discussed in Article 13.1 above shall be shared by the Parties in proportion to their respective percentage ownership interests in Trimble County Unit 1.  IMEA shall also pay any additional premium that results from IMEA being named as an additional insured party on Louisville’s existing policies.  IMEA shall bear responsibility for costs of and any losses incurred within the limits of any deductibles on policies of insurance.  If IMEA elects to participate in self-insurance, as discussed in the following paragraph, the costs of claims and expenses for such self-insurance shall also be shared in proportion to the respective ownership interests in Trimble County Unit 1.  IMEA’s share of such insurance and self-insurance costs shall be paid in accordance with Articles 7 and 8, as applicable.

With regard to the portion of any self-insurance for which IMEA is responsible, IMEA shall be entitled, at its option, to separately fund and administer a reserve account to fund all claims and expenses for which it is maintaining self-insurance.  Any such separately maintained and administered fund shall be established, maintained, and administered according to policies and procedures approved by the Coordination Committee.  Such fund will be a financial device for funding IMEA’s self-insurance obligation and will play no role in administering claims.  Where IMEA establishes and maintains such an account, the Coordination Committee will determine appropriate procedures and methodology for regularly billing for and recovering amounts due to be paid by IMEA to Louisville for such claims and expenses.  Such procedures and methodology may include making adjustments to the billing and payment practices set forth in Article 7 and 8, as such Articles relate to IMEA’s self-insurance.

13.1.2IMEA Named As Insured.

IMEA shall be named as an additional insured in such insurance policies.  Louisville shall use its reasonable best efforts to have the insurance underwriters furnish IMEA with a Certificate of Insurance of each such insurance policy.  in addition, Louisville shall use its reasonable best efforts to have each of such policies endorsed so as to provide that IMEA shall be given the same advance notice of cancellation or material change as is required to be given to Louisville.  Loss or claim, if any, under such insurance policies shall be adjusted and settled by Louisville with the insurance underwriters.

13.1.3Procurement Of Additional Insurance For IMEA.

IMEA may obtain additional insurance beyond that provided for in this Article 13 to insure its ownership interest in Trimble County Unit 1 and the Trimble County Site and its rights with

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respect to the Trimble County General Plant Facilities at its cost.  With respect to such additional insurance:

the proceeds from any claim arising through such additional insurance shall be disbursed to IMEA; and

loss or claim, if any, under such additional insurance shall be adjusted and settled by IMEA with the insurance underwriters.

13.1.4Sharing Of Refunds From Insurance Premiums.

Any refunds of insurance premiums shall be allocated among the Parties on the same basis as the premium payment allocation from which such refund was derived.

13.1.5Sharing Of Insurance Proceeds.

In the event of damage to property insured under this Article, it is agreed that the proceeds from insurance obtained by Louisville on behalf of both Parties shall be shared by the Parties to this Agreement on a pro rata basis based on their relative payments of insurance premiums covering the damaged property.

13.2Destruction.

13.2.1Damage Or Destruction Fully Covered By Insurance.

If property insured under this Article or any portion thereof should be damaged or destroyed to the extent that the cost of repairs or reconstruction is estimated to be covered by the aggregate amount of insurance coverage (including any deductible) carried by Louisville for the benefit of Louisville and IMEA pursuant to Article 13 hereof, then Louisville shall cause such repairs or reconstruction to be made so that such property shall be restored to substantially the same general condition, character, or use as existed prior to such damage or destruction; provided however, if the estimate is wrong, and the insurance proceeds are insufficient to pay the cost of repair or reconstruction, Louisville and IMEA shall share the cost not reimbursed by such insurance in proportion to their percentage ownership interests in Trimble County Unit 1.

13.2.2Damage Or Destruction Not Fully Covered By Insurance.

If Trimble County Unit 1, the Trimble County General Plant Facilities or any portion thereof as they pertain to Trimble County Unit 1, should be damaged or destroyed to the extent that the cost of repairs or reconstruction is estimated to be more than the aggregate amount of insurance coverage (including any deductible) carried by Louisville for the benefit of Louisville and IMEA pursuant to Article 13 hereof and covering the cost of such repairs or reconstruction, then, if Louisville elects to repair and reconstruct such property and upon agreement of Louisville and IMEA, Louisville shall cause such repairs or reconstruction to be made and Louisville and IMEA shall share the costs of such repairs or reconstruction not reimbursed by such insurance, in proportion to their percentage ownership interests in Trimble County Unit 1; provided, however, that:

If IMEA elects not to join Louisville in repairing and reconstructing such property, then, at Louisville’s election, the Parties shall determine the monetary amount to be paid by Louisville to

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IMEA or by IMEA to Louisville, as provided for in paragraph (b) of this Article 13.2.2.  Upon payment of such monetary amount by Louisville to IMEA or by IMEA to Louisville, as the case may require as set forth in said paragraph (b), IMEA shall transfer its ownership interest in Trimble County Unit 1 and the Trimble County Site, and its license to use the Trimble County General Plant Facilities, and its easement to the Trimble County Site, to Louisville, free and clear of all liens and encumbrances, and this Agreement shall be deemed to have expired.

The monetary amount to be paid to or received from IMEA pursuant to the provisions of paragraph (a) of this Article 13.2.2, shall be determined in accordance with the following equation:

P = W * X

Where:

P	=	the monetary amount to be paid to or received from IMEA.  If P is positive, the monetary amount shall be paid to IMEA; and if P is negative, the monetary amount shall be received from IMEA.
W	=	IMEA’s percentage ownership interest in Trimble County Unit 1 before transfer of IMEA’s ownership interest in such property.
X	=	the fair market value (as determined by an independent appraiser selected jointly by the Parties) of (i) Trimble County Unit 1 and (ii) the Trimble County Site and the Trimble County General Plant Facilities as they pertain to IMEA’s use of Trimble County Unit 1, at the time IMEA elects not to join Louisville in repairing and reconstructing Trimble County Unit 1 or the Trimble County General Plant Facilities.  Fair market value shall be determined after taking into account all applicable costs of dismantling, demolishing, and removal of equipment, facilities, and structures; security; maintenance; disposing of debris; and any site work necessary to remove the effects of such damage or destruction.  Fair market value may be a negative figure where appropriate.

ARTICLE 14

PARTITION OF OR TRANSFER OF INTEREST IN THIMBLE COUNTY UNIT 1

14.1Special Nature Of Trimble County Unit 1 – Waiver of Right of Partition.

The Parties recognize that when Trimble County Unit 1 shall have been placed in service, it will be an integral part of the facilities required to provide adequate service in their respective service territories and the service territories of other co-owners of Trimble County Unit 1, if any, and that the physical partition of Trimble County Unit 1 or any material part thereof would be impossible and impractical and wholly inconsistent with the purposes for which this Agreement is made.

Each of the Parties agrees that it will not take any action, by judicial proceedings or otherwise, to partition Trimble County Unit 1, or that portion of the Trimble County Site conveyed by Louisville to IMEA pursuant to Article 2.2 hereof, or any part thereof, in any way, whether by partition in kind or by sale and division of the proceeds thereof.  Each of the Parties further waives the right of partition and the benefit of all statutory or common law that may now or hereafter authorize such partition of Trimble County Unit 1 or any part thereof, or that portion of the Trimble

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County Site conveyed by Louisville to IMEA pursuant to Article 2.2 hereof.  in the event any such right of partition shall hereafter accrue, each Party shall from time to time upon the written request of the other Party execute and deliver such further instruments as may be necessary to confirm the foregoing waiver and release of its right to partition.  The foregoing provisions of this Article 14.1 shall be binding upon and inure to the benefit of the Parties, their respective successors and assigns, including mortgagees, receivers, trustees, or other representatives and their respective successors and assigns, and shall run with the land.  Louisville agrees to insert a similar covenant in any contract with another party which acquires an ownership interest in Trimble County Unit 1, which covenant will be enforceable by IMEA.

14.2Transfer Of Ownership Interests To Third Parties.

If either Party (“Transferring Party”) shall desire to transfer (whether by sale, conveyance, assignment, lease, or otherwise) all or any portion of.  its ownership interest in Trimble County Unit 1 in a bona fide arms length transaction to any unaffiliated third party or parties, the Transferring Party shall give the other Party written notice thereof, and any such transaction with such unaffiliated third party or parties shall not be consummated until the other Party has determined not to exercise its right of first refusal, as set forth in this paragraph.  Such written notice shall fully disclose the nature and terms of the proposed transaction and the identity of the third party or parties involved.  Upon receipt of such written notice, the other Party shall have the first right to acquire the Transferring Party’s ownership Interest in Trimble County Unit 1 that the Transferring Party proposes to transfer to the third party or parties, upon the same terms and conditions which the Transferring Party proposes to make with the third party or parties.  Within 90 days following receipt of such notice, the other Party shall give written notice to the Transferring Party stating whether or not it elects to acquire the Transferring Party’s undivided ownership interest in Trimble County Unit 1 which the Transferring Party proposes to dispose of to the third party or parties.  If the Party elects to exercise its rights to acquire such interest, the Transferring Party, as soon as practicable, shall execute such instruments as may be necessary and appropriate to effectuate such sale, conveyance, transfer, assignment, lease, or other disposition, as the case may be, to the other Party, free and clear of all liens, charges, and encumbrances for which the Transferring Party, as between the Parties, is responsible, including the indenture(s) of the Transferring Party.

14.2.1Conditions Of Transfer.

If the other Party elects not to acquire the Transferring Party’s ownership interest in Trimble County Unit 1, as provided in the first paragraph of Article 14.2, the Transferring Party may consummate its proposed transaction with the third party or parties and dispose of such ownership interest to the third party or parties, provided, that such transaction is consummated within 240 days following receipt by the other Party of the written notice first referred to in the first paragraph of Article 14.2; and provided further, that the other Party has approved the prospective purchaser as suitable and desirable as a joint owner of Trimble County Unit 1, although such approval may not unreasonably be withheld and grounds for withholding such approval shall be limited to such factors as will materially, adversely affect the other Party’s interests hereunder; provided, however, that where Louisville is the Transferring Party, IMEA’s right to approve the prospective purchaser as suitable and desirable shall be limited to situations in which the proposed transfer reduces Louisville’s ownership interest in Trimble County Unit 1 to less than fifty (50) percent, or where such proposed transfer conveys, in whole or part, Louisville’s rights and obligations for operation of Trimble County Unit 1 under this Agreement to such third party or parties; and provided, further, that IMEA shall require (as a condition of or in connection with the sale, conveyance, transfer,

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assignment, lease, or other disposition, and for the benefit of the other Party) the third party or parties acquiring such ownership interest to assume and agree to be bound by the provisions of this Agreement and any amendments thereto, and in furtherance thereof the provisions of this Agreement shall be amended appropriately to reflect:

the addition of such third party or parties as a party or parties to this Agreement; and

the ownership Interest in Trimble County Unit 1 acquired by such third party or parties and the decreased ownership Interest in Trimble County Unit 1 of the Transferring Party; and

the rights, duties, and obligations of the Transferring Party and such third party or parties under this Agreement.  Further, the Transferring Party hereby agrees to save the other Party harmless from and against all loss or liability which the other Party may incur as a result of any failure by such third party or parties to fulfill its or their duties and obligations under this Agreement and any amendments thereto.  in addition, the consummation of any transaction by the Transferring Party with a third party or parties shall not release the Transferring Party from any of its debts or liabilities to the other Party which, at the time of the consummation of the transaction, have accrued under this Agreement, and any amendments thereto, unless the Parties shall agree in writing to the contrary.

14.2.2Further Conditions Of Transfer.

The right of the Transferring Party to dispose of such ownership interest to a third party or parties, as set forth in the first paragraph of Article 14.2, is subject to the further condition that the other Party shall be given written notice thereof and shall have the further right of first refusal, to the same extent and by the same procedure described in the first paragraph of Article 14.2:

if the Transferring Party shall undertake to consummate its proposed transaction at a time subsequent to 240 days following receipt of the written notice first referred to in the first paragraph of Article 14.2; or

if the Transferring Party shall undertake to dispose of such ownership interest to a third party or parties other than those whose identity was disclosed in said notice; or

if the Transferring Party shall undertake to dispose of such ownership interest upon different terms and conditions than were disclosed in said notice.

14.2.3Non-applicability Of Certain Provisions.

The provision of the foregoing Articles 14.2, 14.2.1, and 14.2.2 shall continue for the duration of this Agreement and shall be applicable to each and every occasion and whenever either Party desires to dispose of (whether by sale, conveyance, transfer, assignment, lease, or otherwise) all or any portion of its ownership interest in Trimble County Unit 1 to any third party or parties; provided, that such provisions shall not be applicable to, and each of the Parties hereby consents to, the following:

the transfer, sale, or assignment to a financially responsible subsidiary, affiliate, or successor of Louisville; or

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the transfer, sale, or assignment to a financially responsible successor joint agency to IMEA; provided that if IMEA is dissolved or liquidated by operation of law or otherwise, and IMEA’s interest herein is not assumed by a financially responsible successor agency operating as a single entity, Louisville shall have the immediate option to purchase all of IMEA’s interest herein at fair market value.  For this purpose, fair market value shall be determined by an independent appraiser selected jointly by the Parties; or

the transfer, assignment, pledge, hypothecation, mortgage, or grant (by indenture of mortgage, deed of trust, or otherwise) by either Party of its ownership interest in Trimble County Unit 1, together with all or substantially all of its other electric utility property, for the purpose of securing bonds or other obligations for borrowed money issued or to be issued by it, including the effect of any after acquired property clause of any such indenture of mortgage, deed of trust, or other instrument now existing or hereafter created by such Party, or the realization on or enforcement of such security or the exercise by the trustee or the mortgagee, or as the case may be, or the beneficiaries of such security of any of the rights, powers, or privileges provided for with respect thereto; or

the transferring by either Party to a third party of its undivided ownership interest in Trimble County Unit 1, together with all or substantially all of its other electric utility property, whether by sale or pursuant to or as a result of a merger, consolidation, or corporate reorganization.

the transferring by Louisville of any interest in Trimble County Unit 1 which transfer would not reduce Louisville’s interest in Trimble County Unit 1 to a level below seventy-five (75) percent.

All transfers of interest set forth in this Article 14 shall be conditioned upon the transferee, by written agreement or by operation of law, assuming the obligations of this Agreement, and any amendments thereto, of the Party so transferring; except that transfer under (c) above shall not be subject to this condition prior to any exercise of ownership, control, or possession by the transferee over the interest transferred.

14.3Transfer of Associated Rights and Interests.

No transfer (whether by sale, conveyance, assignment, lease, or otherwise) by IMEA of any interests under this Agreement shall be permitted, or shall become effective, unless the interest transferred includes a corresponding and equivalent transfer of IMEA’s associated rights and interests in Trimble County Unit 1, the Trimble County General Plant Facilities, and the Trimble County Site, and unless such transfer is made in full compliance with this Article 14.

ARTICLE 15

RIGHT OF FIRST REFUSAL

If at any time within twenty years from the Execution Date hereof, Louisville shall apply to the Kentucky Public Service Commission for a certificate of public convenience and necessity for the installation at the Trimble County Site of a coal-fired generating unit for use by its system as a base load plant, IMEA shall have a right of first refusal to participate in the ownership of said unit by electing to own 12.12 percent of such unit on the terms set forth herein.  in the event such a certificate is not legally required, Louisville shall use its best efforts to give notice to IMEA

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equivalent in time and content to that which would be given where a certificate is required.  At least ninety days prior to applying for such certificate, Louisville shall provide written notice to IMEA of its intention to make such application, and shall provide IMEA with technical and economic information available at that time which pertains to the planned unit, and the estimated cost thereof.  IMEA shall have 180 days to elect to participate in such unit.  IMEA’s right to participate in such unit shall lapse and expire unless IMEA provides written notice to Louisville of its acceptance of such participation within 180 days after the date of Louisville’s earlier notice to IMEA.  Within 180 days of Louisville’s receipt of IMEA’s notice of acceptance, the Parties shall negotiate in good faith and execute a separate contract incorporating the terms and conditions of this Article, as well as other appropriate terms and conditions, covering the installation and operation of such new unit.

Should IMEA elect to participate, it shall pay its pro rats share of all actual expenditures made for Construction Work in connection with such unit and shall make quarterly progress payments to Louisville as said expenditures are incurred and billed by Louisville to IMEA.  in addition to such actual expenditures, IMEA shall pay Louisville a consulting and construction management fee equal to ten percent of such actual expenditures.  IMEA’s participation in the unit shall be subject to all terms and conditions set forth in this Agreement unless waived in writing by Louisville, or otherwise mutually agreed by the Parties.  Payment of the above amounts shall entitle IMEA, in addition to its ownership interest in such unit, to a license to use the Trimble County General Plant Facilities and the Trimble County Site as they pertain to such unit.  Subject to IMEA’s right to elect to participate in 12.12 percent of such unit, nothing herein shall prevent Louisville from selling or offering to sell to any other Party, an ownership or other interest in the remainder of such unit, or in the Trimble County General Plant Facilities or Trimble County Site as they pertain to such unit.  The right of first refusal shall apply only to the next coal-fired generating unit built at the Trimble County Site for use by Louisville as a base load plant, and shall not extend to any subsequently built unit.

ARTICLE 16

ASSIGNMENT

16.1Limitation Of Assignability.

This Agreement shall not be assignable by either Party without the written consent of the other Party, except that no such consent shall be required for IMEA to assign this Agreement (a) as an incident to the disposition of all of its ownership interest in accordance with Articles 14.2, 14.2.1, and 14.2.2 hereof or (b) to the trustee for the tax-exempt revenue bonds issued by IMEA to pay the costs of the acquisition of the IMEA ownership interest in Trimble County Unit 1 hereunder; and, further, each of the Parties hereby consents to the assignment of this Agreement as an incident to the disposition of a Party’s ownership interest, as permitted by Article 14.2.3.

16.2Successors And Assigns.

This Agreement shall inure to the benefit of and be binding upon Louisville and IMEA and their respective successors.  This Agreement shall inure to the benefit of and be binding upon the assigns of Louisville and IMEA when such assignment is made in accordance with the provisions of Article 16.1.

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ARTICLE 17

LIABILITY AND DEFAULT

17.1Liability To Third Parties.

Notwithstanding any provision to the contrary in this Agreement, any liability or any payment, cost, expense, or obligation arising from a claim of liability (after application thereto of any insurance coverage or proceeds) to a third party or parties against one or both of the Parties and arising from the acquisition, planning, engineering, design, licensing, procurement, construction, installation, completion, operation, use, management, control, maintenance, replacement, alteration, modification, renewal, rebuilding or repair, retirement, disposal, or salvaging of Trimble County Unit 1 or any part thereof and the Trimble County General Plant Facilities and the Trimble County Site as they pertain to Trimble County Unit 1; or from any other action or failure to act by either Party (or its employees, agents, or contractors) in carrying out any of the provisions of this Agreement in regard to Trimble County Unit 1 or any part thereof and the Trimble County General Plant Facilities and the Trimble County Site as they pertain to Trimble County Unit 1, shall be shared by the Parties in proportion to their respective percentage ownership interests in Trimble County 1 in all circumstances except where such liability or claim of liability is the result of gross negligence or intentional wrongdoing on the part of Louisville or IMEA.  If, by reason of any such liability or claim of liability (after application thereto of any insurance coverage or proceeds) to a third party or parties, either Party shall be called upon to make any payment or to incur any cost, expense, or obligation in excess of that for which it is responsible under the provisions of the preceding sentence, then the other Party shall reimburse the Party making such excess payment or incurring any such excess cost, expense, or obligation to the full extent of the excess.  Louisville shall be solely responsible for third-party claims arising prior to Closing and shall fully indemnify IMEA against any such claim.

17.2Liability Between The Parties.

Except as set forth in this Article 17.2, Louisville shall not be liable to IMEA for any loss, cost, damage, or expense incurred by IMEA as a result of any action or failure to act, under any circumstances, by Louisville (or its employees, agents, or contractors) in carrying out any of the provisions of this Agreement, except that Louisville will be liable to IMEA for (a) any such loss, cost, damage, or expense which is the result of gross negligence or intentional wrongdoing on the part of Louisville, and (b) any damage to IMEA caused by Louisville’s negligence, but only if such damage results from Louisville’s failure to follow Good Utility Practice in operating Trimble County Unit 1; provided, that no liability for failure to follow Good Utility Practice shall exceed, in any one contract year, the amount paid by IMEA to Louisville for service fees in that same contract year under Article 7.1.6 hereof.

In no event, however, shall Louisville be liable to IMEA with respect to any claim, whether based on contract, tort (including negligence), patent, trademark or service mark, or otherwise, for any indirect, special, incidental, or consequential damages, including, but not limited to, loss of profits or revenues, loss of use of Trimble County Unit 1 or any part thereof and the Trimble County General Plant Facilities and the Trimble County Site as they pertain to Trimble County Unit 1, cost of capital, cost of purchased or replacement power, claims of the Participants or other customers of IMEA for service interruptions, or claims of customers of the Participants for service interruption.

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Provided, however, that in no event shall Louisville be excused from liability for its fraudulent acts.

17.3Indemnification.

Subject to Article 17.2 hereof, each Party (“breaching Party”) hereby agrees to indemnify and hold the other Party (“non-breaching Party”) harmless from, against, and in respect of and shall on demand reimburse the none breaching Party for:

any and all loss, liability, or damage resulting from any untrue representation, breach of warranty, or non-fulfillment of any covenant or agreement by the breaching Party contained herein or in any certificate, document, or instrument delivered to the non-breaching Party hereunder; and

any and all loss suffered by the non-breaching Party due to the breaching Party’s failure to perform or satisfy any obligation assumed pursuant to this Agreement; and

any and all loss resulting from actions, suits, proceedings, claims, demands, assessments, judgments, costs, and expenses, including, without limitation, legal fees and expenses, incident to any of the foregoing or incurred in investigating or attempting to avoid the same or to oppose the imposition thereof, or in enforcing this indemnity.

17.4Nature And Survival Of Representations And Warranties.

Each representation, warranty, indemnity, covenant, and agreement made by the Parties in this Agreement or in any document, certificate, or other instrument delivered by or on behalf of the Parties pursuant to this Agreement or in connection herewith, shall survive the Closing.

17.5Default.

17.5.1Events Of Default.

The following shall be Events of Default under this Agreement:

17.5.1.1Failure To Make Payment.

Failure by either Party to make any payment to the other Party required under this Agreement within sixty (60) days after the date on which such payment becomes due, or failure by either Party to give any credit to the other Party required under this Agreement for a period of sixty (60) days after the date on which such credit becomes due, or failure by either Party to make payment for a period of sixty (60) days after the date on which such payment becomes due to any third party, when failure to do so could result in a lien on any of the property included under this Agreement or otherwise adversely affects the interests of the other Party; provided, however, that no Party shall be in default if the amount it owes hereunder can be offset in whole within sixty (60) days after the date on which such amount became due and payable, by the Party to whom that sum is owed under this Agreement.

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17.5.1.2Failure to Perform.

Failure by either Party to perform any material obligation, duty, or responsibility in accordance with the provisions of this Agreement.

17.5.2Curing Default in Regard To Paring Money.

As to any default resulting from the failure to pay money, the defaulting Party may remedy its default (when its default is the failure to pay money) by paying to the non-defaulting Party on or before ninety (90) days from the date the payment becomes due:

(a)the sums due; and

(b)interest on the sums due at the Agreed Rate from the date of default until paid; and

(c)any other costs incurred by the non-defaulting Party as a result of such default.

17.5.3Curing Default For Other Than Failure To Pay Money.

A Party in default for reasons other than the failure to pay money may cure such default by performing such act as is necessary to cure the default and by paying the non-defaulting Party on or before ninety (90) days from the date such default occurred, any sums due under Article 17.3 hereof.

17.5.4Non-Applicability of Cure Provisions.

Articles 17.5.2 and 17.5.3 hereof shall not be applicable to any event of default relating to pre-Closing or Closing activities set forth in this Agreement.  Cure periods under Articles 17.5.2 and 17.5.3 will not operate to extend the time specified in any other Article of this Agreement for the performance or occurrence of any act or event, unless otherwise specified.

17.5.5Appointment Of A Receiver.

In the event the default continues for a period of 180 days, then the non-defaulting Party may have a receiver appointed by a state or federal court sitting in Louisville, Kentucky to take control of and operate the defaulting Party’s interest in the facilities and perform in accordance with the terms of this Agreement.

17.5.6Additional Obligations.

With respect to any Party as to which an Event of Default has occurred, such Party shall use its best efforts to take any and all such further actions and shall execute and file where appropriate any and all such further legal documents and papers as may be reasonable under the circumstances in order to facilitate the carrying out of this Agreement or otherwise effectuate its purpose, including but not limited to action to seek any required governmental or regulatory approval and to obtain any other required consent, release, amendment, or other similar document.

17.5.7Waivers.

No waiver of any default or Event of Default hereunder shall extend to or affect any subsequent default or Event of Default or shall impair any rights or remedies consequent thereon.  No

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delay or omission to exercise any remedy available upon any Event of Default shall impair any Party’s right to exercise such remedy or shall be construed to be a waiver thereof, but any such remedy may be exercised from time to time and as often as may be deemed expedient.  In order to entitle each Party hereto to exercise any remedy conferred upon or reserved by it in this Article 18, notice shall be provided in accordance with Article 21.2 hereof.

17.5.8Legal And Other Costs.

In the event that any Party (the “Defaulting Party”) defaults in its obligations under this Agreement and, as a result thereof, the other Party (the “Non-Defaulting Party”) seeks to legally enforce its rights hereunder against the Defaulting Party, then, in addition to all damages and other remedies to which the Non-Defaulting Party is entitled by reason of such default, the Defaulting Party shall promptly pay to the Non-Defaulting Party an amount equal to all costs and expenses (including reasonable attorneys’ fees) paid or incurred by the Non-Defaulting Party in connection with such enforcement.

17.6Force Majeure.

In no event shall either Party be liable to the other Party for failure by such Party to perform any of its obligations under this Agreement because of Force Majeure.  Nothing contained herein shall be construed to require a Party to settle any strike, lockout, work stoppage, or other industrial disturbance or dispute in which it may be involved or to take an appeal from any judicial, regulatory, or administrative action.  Any Party rendered unable to fulfill any of its obligations under this Agreement by reason of Force Majeure shall exercise due diligence to remove such inability with all reasonable dispatch.  In the event either Party is unable, in whole or in part, to perform any of its obligations by reason of Force Majeure, other than obligations to make payments hereunder, the obligations of the Party relying thereon, insofar as such obligations are affected by such Force Majeure, shall be suspended during the continuance thereof but no longer.  The obligation of IMEA to make payments as set forth in Articles 7 and 8 shall be unconditional and absolute, and shall not be subject to reduction, setoff, or claim of Force Majeure.  The Party invoking the Force Majeure shall specifically state the full particulars of the Force Majeure and the time and date when the Force Majeure occurred.  Notices given by telephone under the provision of this Article shall be confirmed in writing as soon as reasonably possible.  When the Force Majeure ceases, the Party relying thereon shall give immediate notice thereof to the other Party.  This Agreement shall not be terminated by reason of Force Majeure but shall remain in full force and effect.

ARTICLE 18

ADMINISTRATION

18.1Coordination Committee.

From time to time various administrative, financial, and technical matters may arise in connection with the terms and conditions of this Agreement which will require the cooperation and consultation of the Parties and interchange of information. As a means of providing for such consultation, interchange, decision making, or ratification, a Coordination Committee is hereby established with functions as described in Article 18.4 below. However, such Committee shall not diminish in any manner the authority of Louisville as set forth in the various sections of this Agreement.

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18.2Membership.

The Coordination Committee shall have one member from each Party that has an ownership interest in Trimble County Unit 1. Within 60 days after execution of this Agreement, each Party shall designate in writing its Representative and at least one alternate on the Coordination Committee and shall promptly give written notice thereof to the other Party. Thereafter, each Party shall promptly give written notice to the other Party of any change in the designation of its Representative on the Coordination Committee. The Chairman of the Coordination Committee shall be the Louisville Representative, who shall be responsible for calling meetings and establishing agenda. Each Party, however, shall have the right to have an item included on the agenda. All actions taken by the Coordination Committee must be by majority vote, with each Party entitled to vote in shares equal to its ownership interest. The Coordination Committee may also act without a meeting by telephone conference or notational voting by correspondence. Majority vote shall not be required for either Party to invoke the procedure under Article 19.2 for handling disagreements after the Commercial Operation Date.

18.3Meetings.

The Coordination Committee shall meet annually on a date and at a location to be announced by the Chairman at least thirty (30) days in advance. Such other meetings as are reasonably required may be called by either member with as much advance notice as is practical. Meetings may be attended by other representatives of the Parties.

18.4Functions.

The Coordination Committee shall have the following functions:

(a)Provide liaison between the Parties at the management level and exchange information with respect to significant matters of licensing, design, construction, operation, and maintenance of Trimble County Unit 1 and the Trimble County General Plant Facilities and the Trimble County Site as they pertain to Trimble County Unit 1.

(b)Appoint Ad Hoc Committees, the members of which need not be members of the Coordination Committee, as necessary to perform detailed work and conduct studies regarding matters requiring investigation.

(c)Review and discuss disputes arising under this Agreement.

(d)Provide llama between the Fifties with respect to the . financial and accounting aspects of Incremental Capital Assets and operation of Trimble County Unit 1 and perform those functions set forth in Article 6.1 hereof.

(e)Provide a liaison between the Parties with respect to the financial ad accounting aspects of the ownership of the property.

(f)Review and approve budgets for operation, maintenance, and Incremental Capital Assets, including retirement of facilities, which affect Trimble County Unit I and the Trimble County General Plant Facilities ad the Trimble County Site as they pertain to Trimble County Unit 1.

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(g)Perform such other duties as set forth pursuant to the other Articles of this Agreement.

18.5Records.

The Coordination Committee shall keep written records of all meetings.

18.6Expenses.

Each Party shall be responsible for the personal expenses of its Representative and its other attendees. All other expenses incurred in connection with the performance by the Coordination Committee of its functions shall be allocated and paid as determined by the Coordination Committee.

18.7Conduct.

Members of the Coordination Committee shall use their reasonable best efforts to perform Committee functions by taking into account Good Utility Practice.

ARTICLE 19

DISAGREEMENT

19.1Consultation.

In accordance with the provisions of Article 18, the members of the Coordination Committee will consult in connection with any major matter arising under this Agreement.

19.2Disagreement After Commercial Operation.

If, after the Commercial Operation Date of Trimble County Unit 1, any disagreement arises on major operation and maintenance matters pertaining to Trimble County Unit 1, major capital matters pertaining to Trimble Unit 1, or major retirement matters, or other matters arising under this Agreement, pertaining to Trimble County Unit 1 (“plant subjects”), such matters shall be discussed by the Coordination Committee and timely mutual agreement sought in regard thereto. if each of the members of the Coordination Committee agrees to the resolution of any plant subject, such agreement shall be reported in writing to and shall be binding upon the Parties — within the authority of the Coordination Committee as stated in Article 18.  In the unlikely event that each of the members of the Coordination Committee Is unable to reach agreement within a reasonable time (giving due cognizance to the operating and maintenance schedules of Trimble County Unit 1 and all other pertinent circumstances) with respect to any plant subject under consideration, the President of Louisville or the General Manager of IMEA can, by written notice to ~’~e members of the Coordination Committee, withdraw the matter from consideration by the Coordination Committee and submit the same for resolution to the President of Louisville and the General Manager of IMEA. If these senior representatives of the Parties agree to a resolution of the matter, such agreement shall be reported in writing to and shall be binding upon the Parties; but if said senior representatives fail to resolve the matter within seven days after its submission to them, then the matter may proceed to arbitration as provided in Article 19.3.

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19.3Arbitration.

If a disagreement should arise with respect to any plant subject which is not resolved by the Coordination Committee or the senior representatives of the Parties as provided in Article 192 or any other disagreement concerning this Agreement, then such disagreement may be settled by an Arbitration Board, which shall consist of three arbitrators as hereinafter provided, in accordance with the provision of this Article 19.3. If, after the procedure for resolving such disagreement by the Coordination Committee or the senior representatives of the Parties as provided in Article 192 has been exhausted, either Party desires that such disagreement shall be settled by arbitration, it shall serve written notice upon the other Party setting forth in detail such disagreement with respect to which arbitration is desired.  Such disagreement shall be settled by arbitration if, after receipt of such written notice, both of the Parties shall agree in writing that such disagreement shall be settled by arbitration.  Within a period of thirty (30) days from the date of such agreement in writing to settle such disagreement by arbitration, each Party shall select one arbitrator.  Within a period of sixty (60) days from the date of such agreement in writing to settle such disagreement by arbitration, the two arbitrators so selected shall meet and select one additional arbitrator.  If either or both of the two arbitrators to be selected by the Parties, as herein provided, are not so selected within the specified 30-day period, or if the two arbitrators selected by the Parties shall fail to agree upon the selection of the additional arbitrator within the specified 60-day period, either Party may, upon written notice to the other Party, apply to the American Arbitration Association for the appointment of the arbitrator or arbitrators who have not been so selected and such Association shall thereupon be empowered to select such arbitrator or arbitrators.

The arbitration proceedings shall be conducted In Louisville, Kentucky unless otherwise mutually agreed.  The Arbitration Board shall afford adequate opportunity to both of the Parties to present information with respect to the disagreement submitted to arbitration and may request further information from either Party.  Except as provided in the preceding sentence, the Parties may, by mutual agreement, specify the rules which are to govern any proceeding before the Arbitration Board and limit the matters to be considered by the Arbitration Board, In which event the Arbitration Board shall be governed by the terms and conditions of such agreement. In the absence of any such agreement respecting the rules which are to govern any proceeding, the then current rules of the American Arbitration Association for the conduct of commercial arbitration shall govern the proceedings, except that if such rules shall conflict with the then current provisions of the laws of Kentucky relating to arbitration, such conflict shall be governed by the then current provisions of the laws of Kentucky relating to arbitration.

Procedural matters pertaining to the conduct of the arbitration and the award of the Arbitration Board shall be made upon a determination of a majority of the arbitrators. The Parties shall, however, be entitled to all discovery provided for by the Kentucky Rules of Civil Procedure.  The findings and award of the Arbitration Board, so made upon a determination of a majority of the arbitrators, shall be final and conclusive with respect to the disagreement submitted for arbitration and shall be binding upon the Parties, except as otherwise provided by law.  Each Party shall pay the fee and expenses of the arbitrator selected by or for it, together with the costs and expenses incurred by it in the preparation of its case to the arbitrators.  The fee and expenses of the third arbitrator selected in accordance with this Article 19.3 shall be assigned in equal parts to the Parties, and each Party shall assume and pay the portion of such fee and costs so assigned to it.  Judgment upon the award may be entered in any court having jurisdiction.  In the event the Parties do not agree to arbitrate, each shall have the right to take appropriate judicial action.

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19.4Obligations To Make Payments.

If a disagreement should arise from any plant subject which is not resolved by the Coordination Committee or the senior representatives of the Parties as provided in Article 19.2, then, pending the resolution of the disagreement by arbitration and/or litigation, Louisville shall continue to operate Trimble County Unit 1 and make necessary Incremental Capital Assets in a manner consistent with this Agreement, and IMEA shall continue to make all payments required in accordance with the applicable provisions of this Agreement.

ARTICLE 20

REMEDIES

20.1All Remedies - Setoff.

In the event either Party (the “Defaulting Party”) fails to pay when due any amount owing by it to the other Party (the “Non-Defau1ting Party”) under this Agreement or the Interchange Agreement or fails to perform or observe any covenant, condition, or agreement to be performed or observed under this Agreement or the Interchange Agreement, the Non-Defaulting Party shall have available to it all remedies, legal and equitable, including, without limitation those available in order to enforce payment of any such amount or performance or observance of any such covenant, condition, or agreement, subject to the defaulting Party’s rights to cure default under Article 17.5.  All overdue payments, whether occurring before or after the Commercial Operation Date of Trimble County Unit 1, shall bear interest at the Agreed Rate.  Further, the Non-Defaulting Party shall have the right to setoff against any amount owed to it by the Defaulting Party the amount of any payment which such Party has failed to pay when due under this Agreement or the Interchange Agreement.  In addition, the Non-Defaulting Party shall have the other rights and remedies available to it under this Article 20.

20.2Injunctive Relief.

The Parties hereto agree and acknowledge that the failure to perform any of their obligations under this Agreement, including the execution of legal documents which may be reasonably requested as set forth in this Article, would cause irreparable injury to the other Party and that the remedy at law for any violation or threatened violation thereof would be inadequate, and agree that the other Party shall be entitled to a temporary or permanent injunction or other equitable relief specifically to enforce such obligation without the necessity of proving the inadequacy of its legal remedies.

20.3No Remedy Exclusive.

No remedy conferred upon or reserved to the Parties hereto in this Agreement is intended to be exclusive of any other remedy or remedies available hereunder or now or hereafter existing at law, in equity, or by statute or otherwise, but each and every such remedy shall be cumulative and shall be in addition to every other such remedy. The pursuit by any Party of any specific remedy shall not be deemed to be an election of that remedy to the exclusion of any other or others, whether provided hereunder or by law, equity, or statute.

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20.420.4

If IMEA fails to make any payment of its share of the cost of Incremental Capital Assets after the Closing, Louisville shall have the right, at its election, to give written notice of such failure to IMEA. If such overdue payment and all other overdue payments, if any, of IMEA’s share of the cost of the Incremental Capital Assets after the Closing, together with interest on such overdue payment or payments, are not paid within ninety (90) days after the giving of the written notice first referred to in this paragraph, then (a) IMEA’s rights to make any further payments of its share of the cost of the Incremental Capital Asset shall thereupon terminate, and (b) the respective percentage ownership interests in Trimble County Unit 1 shall be adjusted in accordance with the following formula:

ADD = ALGE*IPCT/(IMEA+ALGE)

where:

ADD    =Additional percentage ownership interest accruing to Louisville as a result of making its additional investment to complete construction of Incremental Capital Assets (there shall be a corresponding reduction in the percentage ownership interest of IMEA in Trimble County Unit 1 and the Trimble County Site).

IMEA   =Investment made by IMEA for its respective percentage ownership interest in Trimble County Unit 1, the Trimble County Site and its nonexclusive license with respect to the Trimble County General Plant Facilities to the time of the written notice first referred to in this Article 20.4.

ALGE   =Additional investment made by Louisville to complete construction of Incremental Capital Assets as aforesaid.

IPCT    =IMEA's percentage ownership interest in Trimble County Unit 1 at the time of the written notice first referred to in this Article 20.4.

ARTICLE 21

MISCELLANEOUS

21.1Governing Law.

The validity, interpretation, and performance of this Agreement and each of its provisions shall be governed by the laws of the Commonwealth of Kentucky, except that the power and authority of IMEA to enter into this Agreement shall be governed by the laws of the State of Illinois.

21.2Notice To Parties.

Unless otherwise specifically provided by other provisions of this Agreement, any notice, consent, or other communication required to be made under this Agreement shall be addressed to or made by such officer, agent, representative, or employee of each Party as such Party may, from time to time, designate in writing, provided that any written notice required to be made pursuant to Articles 14, 18, and 19.3 hereof shall be delivered in person, by prepaid telegram, or by registered or certified mail, to the named officer of the Party at the address listed below; provided, that either Party may, from time to time, change such designated officer or the address thereof by giving written

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notice of such change to the other Party. Any requirement for notice in writing may be met by telex, telecopy, or other electronic means of communicating written or printed material, if promptly confirmed in writing.

TO Louisville: .

President

Louisville Gas and Electric Company

220 West Main Street (40202)

Post Office Box 32010

Louisville, Kentucky 40232

TO IMEA:

General Manager

Illinois Municipal Electric Agency

919 South Spring Street

Springfield, Illinois 62704

21.3Article Headings Not To Affect Meaning.

The descriptive headings of the various Articles of this Agreement have been inserted for convenience of reference only and shall in no way modify or restrict any of the terms or provisions hereof.

21.4Counterparts.

This Agreement may be executed simultaneously in two or more counterparts, each of which shall be deemed an original, but all of which together shall constitute one and the same instrument.

21.5Time.

Louisville and IMEA agree that time is of the essence in this Agreement.

21.6Severability.

In the event that any provision of this Agreement, or the application of any such provision to any person or circumstance, shall be held Invalid or unenforceable, the remainder of this Agreement, or the application of such provision to persons or circumstances other than those as to which it is held invalid or unenforceable, shall not be affected thereby.

21.7Integration.

The terms and provisions contained in this Agreement and the Interchange Agreement constitute the entire agreement between Louisville and IMEA in regard to the respective matters of said Agreement, and shall supersede all previous communications, representations, or agreements, either oral or written, between Louisville and IMEA with respect to the respective subject matters of said Agreements.

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21.8Computation Of Time.

In computing any period of time prescribed or allowed by this Agreement, the day of the act, event, or default from which the designated period of time begins to run shall not be included. The last day of this period so computed shall be included, unless it is a Saturday, Sunday, or legal holiday in Kentucky, in which event the period shall run until the end of the next day which is neither a Saturday, Sunday, nor legal holiday.

21.9Waiver.

Any waiver at any time, by either Party, of its rights with respect to the other Party, or with respect to any other matter arising in connection with this Agreement, shall not be considered a waiver with respect to any subsequent default or matter.

21.10Equal Opportunity Clause.

During the performance of those parts of this Agreement relating to the construction by a Party of any Incremental Capital Assets, such Party agrees as follows:

(a)Such Party will not discriminate against any employee or Applicant for employment because of race, color, religion, sex, or national origin.  Such Party will take affirmative action to Insure that applicants are employed, ad that employees are treated, during employment, without regard to their race, color, religion, sex, or national origin. Such action shall Include, but not be limited to, the following employment, upgrading, demotion, or transfer recruitment or recruitment advertising; layoff or termination; rates of pay it other forms of compensation; and selection for training. including apprenticeship. Such Party agrees to post, In conspicuous plans, available to employees and applicants for employment, notices setting forth the provisions of this. Non-discrimination clause;

(b)Such Party will, In all solicitations or advertisements for employees place by or on behalf of such Party, state that all qualified applicants will receive consideration for employment without regard to race, color, religion, sex, or national origin;

(c)Such Party will send to each labor union or representative of workers with which it has a collective bargaining agreement or other contract or understanding a notice, to be provided, advising the said labor union or workers’ representative, of such Party’s commitments under this Article 21.10, and shall post copies of the notice in conspicuous places, available to employees and applicants for employment.

(d)Such Party will comply with all provisions of Executive Order No. 1124 of September 24, 1965, and of the rules, regulations, and relevant orders of the Secretary of Labor.

(e)Such Party will furnish all information ad reports required by Executive Order No. 11246 of September 24, 1965, and by the rules, regulations, and orders of the Secretary of Labor, or pursuant thereto, and will permit access to Its books, records, and accounts by the administering agency and the Secretary of Labor, for purposes d Investigation, to ascertain compliance with such rules, regulations, and orders;

46

(f)In the event of such Party’s noncompliance with the non-discrimination clauses of this Agreement, or with any of the said rules, regulations, or orders of this Agreement may be canceled, terminated, or suspended, in whole or In part, and such Party may be declared Ineligible for fit Government contracts or federally assisted construction contracts In accordance with procedures authorized in Executive Order No. 11246 of September 24, 1965, and such other sanctions may be imposed and remedies Invoked as provided In said Executive Order or by rule, regulation, or order of the Secretary of Labor, or as otherwise provided by law;

(g)Such Party will Includes the words “During the performance of this contract, the contractor agrees as follows:” followed by the provisions of sections (a) through if) of this Article 21.10 In every subcontract or purchase order, unless exempted by rules, regulations, or orders or the Secretary of Labor issued pursuant to Section 204 of Executive Order No. 11244 of September 24, 1965, so that such provisions will be binding upon each subcontractor or vendor. Such Party will take such action with respect with any subcontract or purchase order as the administering agency may direct as a means of enforcing such provisions, including sanctions for non-compliance provided, however, that in the event such Party becomes involved in, or Is threatened with, litigation by a subcontractor or vendor as a result of such direction by the administering agency, such Party may request the United States to enter into such litigation to protect the Interests of the United States;

(h)For purposes of this Agreement, the term ‘this Agreement, as used in this Article 21.10 shall mean those parts of this Agreement relating to the construction by such Party of any additions, betterments, or improvements to the property. Nothing In this Article 21.10 shall be construed to prevent such Party from resisting, challenging, contesting, or appealing any law, statute, regulation, or decision of any federal, state, or local government or agency which such Party claims to be in invalid, unlawful, arbitrary, or capricious.

21.11Non-Segregated Facilities.

Each Party certifies further that it will not maintain or provide for its employees any segregated facilities at any of its establishments, and that it will not permit its employees to perform their services at any location, under its control, where segregated facilities are maintained. Each Party agrees that a breach of this certification is a violation of the Equal Opportunity Clause in this Agreement. As used in this certification, the term “segregated facilities” means any waiting rooms, work areas, rest rooms and washrooms, restaurants, and other eating areas, time clocks, locker rooms and other storage or dressing areas, parking lots, drinking fountains, recreation or entertainment areas, transportation, or housing facilities provided for employees which are segregated by explicit directive or are, in fact, segregated on the basis of race, color, religion, or national origin, because of habit, local custom, or otherwise. Each Party agrees that (except where it has obtained identical certifications from proposed subcontractors for specific time periods) it will obtain identical certifications from proposed subcontractors prior to the award of subcontracts exceeding $10,000 which are not exempt from the provisions of the Equal Opportunity Clause, and that it will retain such certifications In Its files.

Nothing in this Article 21.11 shall be construed to prevent any Party from resisting, challenging, contesting, or appealing any law, statue, regulations, or decision of any federal, state, or local government or agency which the Party claims to be invalid, unlawful, arbitrary, or capricious.

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21.12Condemnation.

In the event any portion of Trimble County Unit 1, or any portion of the Trimble County Site or the Trimble County General Plant Facilities as they pertain to the Parties’ use of Trimble County Unit 1, shall be condemned and taken by exercise of any right of eminent domain or for public or quasi-public use, and the Parties hereto are able to continue their use and operation of the remaining portion thereof, this Agreement shall not terminate. The proceeds of any payment of any award or compensation arising from such condemnation (net of any expenses of any nature incurred by the Parties with respect thereto, which expenses shall be fully reimbursed to the Party or Parties incurring such expenses) shall be apportioned between Louisville and IMEA on the basis of their respective ownership interests in Trimble County Unit 1.  In the event that all of Trimble County Unit 1, or all of the Trimble County Site, and the Trimble County General Plant Facilities as they pertain to the Parties’ use of Trimble County Unit 1, shall be condemned and taken by exercise of any right of eminent domain or for public or quasi-public use, this Agreement shall terminate as of the date of said taking and the proceeds of any award or compensation arising from such condemnation (net of any expenses of any nature incurred by the Parties with respect thereto, which expenses shall be fully reimbursed to the Party or Parties incurring such expenses) shall be apportioned between Louisville and IMEA on the basis of their respective ownership interests in Trimble County Unit 1.

ARTICLE 22

TERM AND TERMINATION

22.1Termination.

This Agreement shall terminate at such time as those activities which are necessary to retire Trimble County Unit 1 from service have been completed. Retirement from service shall include, without limitation: dismantling, demolishing, and removal of equipment, facilities, and structures; security; maintenance; disposing of debris; and any site work necessary to lawfully and responsibly effect such retirement. Termination of this Agreement, however, shall not terminate or affect, as between the Parties, the continued liability, if any, of the Parties for environmental considerations or other obligations imposed by law.

22.2Retirement Of Property.

The Coordination Committee shall have authority in decisions regarding the retirement from service of any and all property included in Trimble County Unit 1 and Trimble County General Plant Facilities which, in the Coordination Committee’s judgement, is damaged, worn out, unreliable, obsolescent, or otherwise unfit for use. However, Trimble County Unit 1 shall not be retired from service as a generating unit without the written consent of IMEA prior to the earlier of:

(a)the expiration of 35 years following the Commercial Operation Date of Trimble County Unit 1; or

(b)the final maturity date of the project revenue bonds originally issued by IMEA to finance its Initial ownership Interest in Trimble County Unit 1, or the final maturity date of any bonds issued by IMEA to refund such originally issued bonds.

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After the expiration of the applicable period in the preceding sentence, the Coordination Committee shall have the right to retire Trimble County Unit 1 from service as a generating unit at any time.

22.3Retirement Costs.

All costs (less salvage credits, if any) associated with retirement of Trimble County Unit 1 and the Trimble County General Plant Facilities and the Trimble County Site as they pertain to Trimble County Unit 1, including, without limitation, dismantling, demolishing, and removal of equipment, facilities, and structures; security; maintenance; disposing of debris; and any site work necessary to lawfully and responsibly effect such retirement, shall be . shared by the Parties in proportion to their respective percentage ownership interests in Trimble County Unit 1.  Payments for these costs (less salvage credits, if any) as they are expected to be incurred, shall be made in accordance with the provisions of Article 8. If such salvage credits exceed such costs, the difference shall be shared by the Parties In proportion to their respective percentage ownership interests In Trimble County Unit 1.

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IN WITNESS WHEREOF, each of the Parties has caused this Agreement to be duly executed.

	LOUISVILLE GAS AND ELECTRIC COMPANY
Attest:	By:
		Senior Vice President - Operations
	ILLINOIS MUNICIPAL ELECTRIC AGENCY
Attest:	By:
Secretary	President – Board of Directors

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APPENDICES

Appendices to Participation Agreement

Appendix	A.	Bill of Sale
Appendix	B.	Trimble County Unit No. 1 List
Appendix	C.	License Agreement and Trimble County General Plant Facility List
Appendix	D.	Known Detects at Execution Date
Appendix	E.	General Warranty Deed
Appendix	F.	Easement:  Louisville to IMEA
Appendix	G.	Easement: I~A to Louisville
Appendix	H.	Certificate of Satisfactory Completion of Performance Tests

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APPENDIX A

BILL OF SALE

LOUISVILLE GAS AND ELECTRIC COMPANY, a Kentucky corporation, 220 West Main Street, P.O. Box 32010, Louisville, Kentucky 40232, (“Seller”) and ILLINOIS MUNICIPAL ELECTRIC AGENCY, an Illinois municipal corporation, 919 South Spring Street , Springfield, Illinois 62704, (“Buyer”), for value received and in accordance with the covenants and conditions set forth in the Participation Agreement by and between Seller and Buyer, dated September 24, 1990, as amended by the Amendment to Participation Agreement dated January 22, 1991, and incorporated by reference herein (“Agreement”), and as part of the consideration for the performance of said Agreement, Seller hereby grants, bargains, transfers, sells and delivers unto Buyer, all of Seller’s right, title and interest in a 12.12% undivided interest as tenants in common in Trimble County Unit 1, as defined in the Agreement arid as more particularly described in Appendix B to the Agreement, and pursuant to the terms of the Agreement.

Seller hereby represents, warrants and covenants that it is the sole and lawful owner of the property described in this Bill of Sale, and has the full right, power and authority to sell and transfer the same.

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IN WITNESS WHEREOF, the undersigned have executed this Bill of Sale by their duly authorized officers this 28^th day of February, 1991.

	SELLER:
	LOUISVILLE GAS AND ELECTRIC COMPANY
Attest:	By:
	Frederick Wright, Senior Vice President- Operations
	BUYER:
	ILLINOIS MUNICIPAL ELECTRIC AGENCY
Attest:	By:
Secretary	Martin F. Johnson, President

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APPENDIX B

Trimble County Unit 1

STRUCTURES

A.	Unit Structure
1.	Concrete
a.	Base Pad Foundation
b.	Base Pad Finish Floor
c.	Elevated Floors
d.	Equipment Foundations
2.	Steel Structures
a.	Boiler and Air Preheater Room Steel
b.	Turbine Room Steel
c.	Stairways
d.	Equipment Platforms
3.	Enclosures
a.	Partial Insulated Multi-Layer Metal Siding
b.	Partial Uninsulated Metal Siding
c.	Concrete & Built-Up Roof
B.	Draft Equipment
1.	Concrete
a.	Equipment Foundations
C.	Boiler Feed and Service Water Equipment
1.	Concrete
a.	Equipment Foundations
D.	Coal Mills
1.	Concrete
a.	Equipment Foundations
E.	Electrostatic Precipitator
1.	Concrete
a.	Foundations
b.	Base Slab
2.	Steel Structures
a.	Column & Girders
b.	Stairways

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3.	Enclosures
a.	Metal Siding
b.	ESP End Walls
F.	Sulphur Dioxide Removal System
1.	Concrete
a.	Foundations
b.	Base Slab
c.	Equipment Foundations
2.	Steel Structures
a.	Column & Girders
b.	Stairways
3.	Enclosures
a.	Insulated Metal Siding
b.	Concrete & Built-Up Roof
G.	Bottom Ask Handling
1.	Concrete
a.	Equipment Foundations
H.	Turbine Generator
1.	Concrete
a.	Equipment Foundations
I.	Boiler
1.	Steel Structures
a.	Support Steel
EQUIPMENT AND SYSTEM COMPONENTS
A.	Unit Structure
1.	Masonry Blockwork
2.	HVAC
3.	Roof Drains
4.	Passenger Elevator
5.	Conduit &Cable Tray
6.	Lighting
7.	6900 Volt Equipment
8.	480 Volt Equipment
9.	208/110 Volt Equipment
10.	Control & Logic Room
11.	Batteries & Chargers

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12.	Uninterruptible Power Supply
13.	Station Fuel Oil Piping
14.	Ignition Oil Piping
15.	Main Steam Piping
16.	Hot & Cold Reheat Piping
17.	Condensate Piping
18.	Gland Seal Piping
19.	Attemperator Piping
20.	Boiler Feed Suction Piping
21.	Extraction Steam Piping
22.	Auxiliary Cooling Piping
23.	Closed Cooling Piping
24.	Compressor and Instrument Air Piping
25.	House Air Piping
26.	Condensate Makeup Piping
27.	Fire Protection
28.	Turbine Room Gantry and House Cranes
29.	Coal Silos
B.	Draft Equipment
1.	Inducted Draft Fans
2.	Forced Draft Fans
3.	Primary Air Fans
4.	Air & Gas Ducts
5.	Air Heater
C.	Boiler Feed and Service Water Equipment
1.	Motor Driven Feed Pumps
2.	Turbine Driven Feed Pumps
3.	Feedwater Heaters
4.	Cooling Pumps
D.	Coal Mills
1.	Coal Mills
2.	Feeders
E.	Electrostatic Precipitator
1.	Precipitator
a.	Elements
b.	Hoppers
c.	Vibrations
2.	HVAC
3.	Fire Protection Equipment
4.	Insulation
5.	480 Volt Equipment

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6.	208/110 Volt Equipment
7.	Conduit & Cable Tray
8.	Lighting
9.	Communications
10.	Control Building
11.	Piping Systems
F. Sulphur Dioxide Removal System
1.	Inlet & Outlet Ducts
2.	Absorber
3.	Demister Wash Equipment
4.	Seal Water Tank
5.	Control Building
6.	Electrical Building
7.	Horizontal Pumps
8.	Seal Air Fans
9.	Air Compressors
10.	Heat Exchangers
11.	Cranes & Hoists
12.	Piping Systems
13.	6900 Volt Equipment
14.	480 Volt Equipment
15.	208/110 Volt Equipment
16.	Lighting
17.	Communications
18.	Multiplex System
G.	Bottom Ash Handling
1.	Hoppers
2.	Ash Sluicing Equipment
3.	Piping System
4.	Bottom Ash Equipment
H.	Turbine Generator
1.	Turbine Generator
2.	Piping Systems
3.	Seal Oil Unit
4.	Hydrogen Coolers
S.	Turbine Oil System
6.	Electro Hydraulic Control
7.	Multiplex System
8.	Isolated Phase Bus
I.	Boiler
1.	Boiler

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2.	Economizer
3.	Superheat/Reheat Panels
4.	Water Walls
S.	Heater Drains & Vents
6.	Sootblowers
7.	Burners

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APPENDIX C

LICENSE AGREEMENT

THIS AGREEMENT made and entered into as of this 28th day of February, 1991, by and between LOUISVILLE GAS AND ELECTRIC COMPANY, a Kentucky corporation, having its principal offices at 220 West Main Street, P.O. Box 32010, Louisville, Kentucky 40232, (“Louisville or Licensor”) and ILLINOIS MUNICIPAL ELECTRIC AGENCY, an Illinois municipal corporation, having its principal offices at 919 South Spring Street, Springfield, Illinois 62704 (“IMEA or Licensee”).

W I T N E S S E T H:

WHEREAS Louisville is the owner of the Trimble County Plant which includes Trimble County Unit 1, the Trimble County General Plant Facilities, and the Trimble County Site:

WHEREAS pursuant to the Participation Agreement dated September 24, 1990, as amended by the Amendment to Participation Agreement dated January 22, 1991 (“Participation Agreement”) by and between Louisville and IMEA, the terms of which are incorporated by reference herein, Louisville has sold to IMEA, and IMEA has purchased from Louisville a 12.12% undivided ownership interest in Trimble County Unit 1 as tenants in common.

WHEREAS IMEA desires to obtain a nonexclusive license to use the Trimble County General Plant Facilities on the Trimble County Site in a manner consistent with IMEA’s ownership interest and so long as it may hold its interest in Trimble County Unit 1.

NOW THEREFORE, in consideration of the mutual covenants and promises herein contained, the parties agree as follows:

1.DEFINITIONS:

The terms Trimble County Unit 1, Trimble County General Plant Facilities, Trimble County Site, and Trimble County Plant as used herein shall be defined as set forth in the Participation Agreement.

2.GRANT:

Upon the terms, payments and conditions set forth in the Participation Agreement, incorporated herein by reference, Louisville hereby grants to IMEA a nonexclusive license to use the Trimble General Plant Facilities, as set forth in the attached list, to the extent necessary for efficient and full use by IMEA of its proportional ownership interest in Trimble County Unit 1.  Louisville shall retain full ownership of the Trimble County General Plant Facilities.

3.USE:

a)IMEA covenants that its use of the Trimble County General Plant Facilities pursuant to the license granted herein will be consistent with the Participation Agreement and otherwise in full compliance with all applicable laws, ordinances, statutes, codes, easements and restrictions.

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b)IMEA acknowledges that this nonexclusive license shall in no way restrict or prohibit Louisville from constructing additional units or facilities or expanding present units or facilities in a manner consistent with the Participation Agreement.

4.DURATION AND TERMINATION:

Unless otherwise terminated by mutual agreement of the parties, this Agreement and the license granted herein shall continue in full force and effect until the expiration or termination of the Participation Agreement.

5.NOTICES:

All notices, requests and demands and other communications given or made in connection with this Agreement, shall be given or made pursuant to and, in accordance with, the Participation Agreement.

6.CONSTRUCTION AND ASSIGNMENT:

a)This Agreement shall be binding on and inure to the benefit of the Licensor, its legal representatives, successors, heirs and assigns.

b)This Agreement shall be binding on and inure to the benefit of the Licensee, but shall not be transferable or assignable by the Licensee except as permitted by and consistent with the Participation Agreement.

c)This Agreement shall be deemed to be a contract made under the laws of the Commonwealth of Kentucky, and shall be construed and interpreted according to the laws of said state.

7.MODIFICATION:

This Agreement and the Participation Agreement embody all the understandings and obligations between the parties with respect to the subject matter hereof.  No amendment or modification of this Agreement shall be valid or binding upon the parties unless made in writing and signed on behalf of each of the parties by their respective proper officers, duly authorized.

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IN WITNESS WHEREOF, the parties caused this Agreement to be executed as of the date first written above.

		LOUISVILLE GAS AND ELECTRIC COMPANY
Attest:		By:
			Frederick Wright, Senior Vice President- Operations
		ILLINOIS MUNICIPAL ELECTRIC AGENCY
Attest:		By:
	Secretary	Martin F. Johnson, President

61

COMMONWEALTH OF KENTUCKY	)
	(SS
COUNTY OF JEFFERSON	)

The foregoing instrument was acknowledged before me this       day of February, 1991, by Frederick Wright, as Senior Vice President-Operations of LOUISVILLE GAS AND ELECTRIC COMPANY, a Kentucky corporation, on behalf of the corporation.

My Commission expires:

Notary Public, State at Large,

Kentucky

STATE OF ILLINOIS	)
		(SS
COUNTY OF COOK		)

The foregoing instrument was acknowledged before me this      day of February, 1991, by Martin F. Johnson, as President of ILLINOIS MUNICIPAL ELECTRIC AGENCY, an Illinois municipal corporation, on behalf of the corporation.

My Commission expires:

Notary Public, State of Illinois

(AFFIX SEAL)

THIS INSTRUMENT PREPARED BY:

C. Kent Hatfield

John M. Franck II

MIDDLETON & REUTLINGER

2500 Brown & Williamson Tower

Louisville, Kentucky 40202

Telephone (502) 584-1135

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List of Trimble County General Plant Facilities

STRUCTURES

A.	Service Building
1.	Concrete
	a.	Foundations
	b.	Base Slab
	c.	Elevated Floors
	d.	Unloading Ramps
2.	Steel Structures
	a.	Columns & Girders
3.	Enclosures
	a.	Insulated Metal Siding
	b.	Glass Curtain Wall
	c.	Concrete & Built-Up Roof
B.	As Fired Sample House
1.	Concrete
	a.	Foundations
	b.	Base Slab
	c.	Elevated Floors
2.	Steel Structures
	a.	Columns & Girders
	b.	Stairways
	c.	Grating
3.	Enclosures
	a.	Insulated Metal Siding
	b.	Concrete & Built-Up Roofing
C.	Screenwell
1.	Piles
	a.	Sheet Piles
	b.	H-Piles
2.	Concrete
	a.	Walls
	b.	Elevated Floors
3.	Steel Structures
	a.	Columns & Girders
	b.	Miscellaneous Platforms
4.	Enclosures
	a.	Insulate Metal Siding
	b.	Concrete & Built-Up Roof
D.	Stack
1.	Concrete

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	a.	Foundations
	b.	Base Slab
	c.	Concrete Shell & Liner
E.	Coal Handling
Barge Unloader
1.	Piles
	a.	Sheet Piles
	b.	H-Piles
2.	Steel Structures
	a.	Columns & Girders
	b.	Stairways
Transfer House
1.	Concrete
	a.	Foundations
	b.	Base Slab
2.	Steel Structures
	a.	Columns & Girders
3.	Enclosures
	a.	Uninsulated Metal Siding
	b.	Concrete & Built-Up
As Delivered Sample House
1.	Concrete
	a.	Foundations
	b.	Base Slab
	c.	Elevated Floors
	d.	Equipment Foundations
2.	Steel Structures
	a.	Columns & Girders
3.	Enclosures
	a.	Uninsulated Metal Siding
	b.	Concrete & Built-Up Roofing
Coal Dock Electrical Service Building
1.	Concrete
	a.	Foundations
	b.	Base Slab
2.	Steel Structures

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	a.	Pre-Engineered Building
Radial Stacker
1.	Concrete
	a.	Base Slab - Rail
Reclaim Hopper & Tunnel
1.	Concrete
	a.	Foundations
	b.	Base Slab
	c.	Walls
	d.	Elevated Slab
	e.	Access Stairway
Crusher House
1.	Concrete
	a.	Foundations
	b.	Base Slab
	c.	Elevated Floors
	d.	Equipment Foundations
2.	Steel Structures
	a.	Columns & Girders
	b.	Stairways
3.	Enclosures
	a.	Uninsulated Metal Siding
Crusher House Electrical Building
1.	Concrete
	a.	Foundations
	b.	Base Slab
2.	Steel Structures
	a.	Pre-Engineered Building
Coal Maintenance Building
1.	Concrete
	a.	Foundations
	b.	Base Slab
2.	Steel Structures
	a.	Pre-Engineered Building
Conveyors A, B, C, D, E, & S
1.	Piles
	a.	Bearing Piles

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2.	Concrete
	a.	Foundations
3.	Steel Structures
	a.	Steel Trusses.
	b.	Conveyor Bents
	c.	Stairways
4.	Enclosures
	a.	Conveyor Uninsulated Metal Siding
Conveyors Fl, F2, G1, and G2
1. Concrete
	a.	Foundations
2.	Steel Structures
	a.	Steel Trusses
	b.	Conveyor Bents
	c.	Stairways
	d.	Gallery Steel Enclosures
3.	Enclosures
	a.	Gallery Uninsulated Metal Siding
F.	Reactant Handling
Barge Unloader
1.	Piles
	a.	Sheet Piles
	b.	H-Piles
2.	Steel Structures
	a.	Column & Girders
	b.	Stairways
3.	Enclosures
	a.	Uninsulated Metal Siding
Transfer House
1.	Concrete
	a.	Foundations
	b.	Base Slab
	c.	Elevated Floors
2.	Steel Structures
	a.	Column & Girders
3.	Enclosures
	a.	Insulated Metal Siding

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Live Action Pile Enclosure
1.	Concrete
	a.	Foundations
	b.	Base Slab - Rail
2.	Steel Structures
	a.	A-Frame Structural Steel
3.	Enclosures
	a.	Uninsulated Metal Siding
Dead Storage Pile
1.	Concrete
	a.	Foundations
	b.	Base Slab
	c.	Walls
	d.	Elevated Slab
	e.	Access Stairway
Conveyors A, B, and C
1.	Concrete
	a.	Foundations
2.	Steel Structures
	a.	Steel Trusses
	b.	Conveyor Bents
	c.	Stairways
	d.	Gallery Steel Enclosure
	3.	Enclosures
		a.	Gallery Uninsulated Metal Siding
F.	Reactant Handling
	Barge Unloader
	1.	Piles
		a.	Sheet Piles
		b.	H-Piles
	2.	Steel Structures
	a.	Columns & Girders
	b.	Stairways
3.	Enclosures
	a.	Uninsulated Metal Siding
Transfer House

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1.	Concrete
	a.	Foundations
	b.	Base Slab
	c.	Elevated Floors
	2.	Steel Structures
	a.	Columns & Girders
3.	Enclosures
	a.	Insulated Metal Siding
Live Action Pile Enclosure
1.	Concrete
	a.	Foundations
	b.	Base Slab – Rail
2.	Steel Structures
	a.	A-Frame Structural Steel
3.	Enclosures
	a.	Uninsulated Metal Siding
Dead Storage Pile
1.	Concrete
	a.	Foundations
	b.	Base Slabs
	c.	Walls
	d.	Elevated Slab
	e.	Access Stairway
Conveyors A, B, and C
1.	Concrete
	a.	Foundations
2.	Steel Structures
	a.	Steel Trusses
	b.	Conveyor Bents
	c.	Stairways
Reactant Prep. Building
1.	Concrete
	a.	Foundations
	b.	Base Slab
	c.	Elevated Floors

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	d.	Equipment Foundations
2.	Steel Structures
	a.	Columns & Girders
	b.	Stairways
3.	Enclosures
	a.	Insulated Metal Siding
	b.	Concrete & Built-Up Roofing
Reactant Live Storage Tanks
1.	Concrete
	a.	Foundations
2.	Steel Structures
	a.	Carbon Steel Tanks
G.	Water Treatment Building
1.	Concrete
	a.	Foundations
	b.	Base Slab
	c.	Walls
	e.	Equipment Foundations
2.	Steel Structures
	a.	Columns & Girders
	b.	Stairways
	c.	Equipment Platforms
3.	Enclosures
	a.	Insulated Metal Siding
H.	Cooling Tower
1.	Concrete
	a.	Foundations
	b.	Base Slab
	c.	Poured Hyperbolic Natural Draft Tows
I.	Station Auxiliary
1.	Concrete
	a.	Equipment Foundations
EQUIPMENT AND SYSTEM COMPONENTS
A.		Service Building
1.		Masonry Blockwork
2.		Fire Protection Equipment
3.		Restrooms, Lockers, and Showers
4.		HVAC
5.		Roof Drains and Plumbing

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6.	Lighting
7.	Communications
8.	Office, Lab, and Kitchen Equipment
9.	Maintenance Shop Equipment
10.	Material Storage Bins and Shelves
11.	Freight Elevator
12.	Passenger Elevator
B.	As Fired Sample House
1.	HVAC
2.	Building Drains
3.	Fire Protection
4.	Lighting
5.	Communications
6.	Coal Silos
7.	Piping Systems
C.	Screenwell
1.	Masonry Blockwork
2.	Multiplex System
3.	HVAC
4.	Horizontal Pumps
5.	Vertical Pumps
6.	Traveling Water Screens
7.	Stop Log Gates and Screens
8.	Bridge Crane
9.	Strainers
10.	480 Volt Equipment
11.	208/110 Volt Equipment
12.	Conduit and Cable Tray
13.	Lighting
14.	Communications
15.	Multiplex System
16.	Roof Drains and Plumbing
D.	Stack
1.	Communications
E.	Coal Handling
1.	Coal Barge Unloader
2.	Conduit and Cable Tray
3.	Lighting
4.	Communications
Transfer House
1.	Barge Unloader Bin
2.	Feeders and Chutes
3.	Dust Collection/Suppression Equipment
4.	Sprinkler System
5.	Monorail and Trolley Hoist
6.	Conduit and Cable Tray
7.	Lighting
8.	Communications

70

As Delivered Sample House
1.	Feeders and Chutes
2.	Dust Collection/Suppression Equipment
3.	As Delivered Sampling System
4.	Sprinkler System
5.	Control Room . Static Wall Siding
6.	Fire Protection System
7.	Conduit and Cable Tray
8.	Lighting
9.	Communications
Coal Dock Electrical Service Building
1.	Masonry Blockwork
2.	Suspended Ceiling
3.	Static Wall Siding
4.	HVAC
5.	Fire Protection System
6.	Domestic Piping
7.	Conduit and Cable Tray
8.	Lighting
9.	Communications
10.	4160 Volt Equipment
11.	480 Volt Equipment
12.	208/110 Volt Equipment
13.	Multiplex System
Radial Stacker
1.	Radial Stacker
2.	HVAC Equipment
3.	Unit Substation
4.	Motor Control Centers
Reclaim Hopper and Tunnel
1.	Hopper
2.	Feeders and Chutes
3.	Vertical Pumps
4.	Conduit and Cable Tray
5.	Lighting
Crusher House
1.	Feeders and Chutes
2.	Crusher Bin
3.	Dust Collection/Suppression Equipment

71

4.	Magnetic Separators and Scales
5.	Crusher
6.	Conduit and Cable Tray
7.	Lighting
8.	Communications
9.	Piping Systems
Crusher House Electrical Building
1.	Masonry Walls
2.	Static Wall Siding
3.	Fire Protection Equipment
4.	Domestic Water
5.	Conduit and Cable Tray
6.	Lighting
7.	Communications
8.	Piping Systems
9.	4160 Volt Equipment
10.	480 Volt Equipment
11.	208/110 Volt Equipment
12.	Multiplex System
Coal Maintenance Building
1.	Masonry Blockwork
2.	Suspended Ceiling
3.	Dry Wall Partitions
4.	HVAC
5.	Sprinkler System
6.	Hoist and Lifts
F.	Reactant Handling
Barge Unloader
1.	Limestone Barge Unloader
2.	Conduit and Cable Tray
3.	Lighting
4.	Communications
Transfer House
1.	Feeders
2.	Hoppers
3.	Piping Systems
4.	Conduit and Cable Tray
S.	Lighting

72

Live Active Pile Enclosure
1.	Reclaimer
2.	Conduit and Cable Tray
3.	Lighting-
Dead Storage Pile
1.	Hopper ~
2.	Chutes and Feeders
3.	Sump Pumps
4.	Conduit and Cable Tray
5.	Lighting
Reactant Prep. Building
1.	Masonry Blockwork
2.	HVAC Equipment
3.	Fire Protection Equipment
4.	Piping Systems
5.	Limestone Crushers and Hoppers
6.	Compressors
7.	Lube Oil Systems
8.	Feeders and Chutes
9.	Bridge Crane
10.	4160 Volt Equipment
11.	480 Volt Equipment
12.	208/110 Volt Equipment
13.	Conduit and Cable Tray
14.	Lighting
15.	Communications
16.	Multiplex System
Reactant Live Storage Tanks
1.	Tank Agitators

73

APPENDIX D

KNOWN DEFECTS AT EXECUTION DATE

The attached list of known detects for Trimble county Unit 3 and the Trimble County General Plant Facilities as they pertain to Trimble County Unit 2. includes items for which construction is not complete as well as items where a deficiency is noted, and to the best of Louisville’ s knowledge information, and belief the attached list is current as of the month in which the Participation Agreement is executed.  Louisville will furnish IMEA such periodic lists of uncompleted items or defects as generated by the Company until Closing.

LOUISVILLE GAS AND ELECTRIC COMPANY

By:

Title:

74

LOUISVILLE GAS & ELECTRIC COMPANY

TRIMBLE CO. GENERATING STATION

STEVE EMERY

SEPTEMBER , 1990

OFM	01170022	LTG BLR RM OPER FLR
OFM	01170023	LTG BLR RM OPER FLR
OFM	01170033	INSTALL LTG BLR RM ABOVE~ 530’
OFM	01170034	INSTALLLTG BLR RH ABOVE 530’
OFM	01170036	EMEG LTG TR,GND,MZ & OPER FLRS
OFM	01170046	INSTL MN FEED & ENGZ LTG TUR P14 GND FLR
OFM	01170048	INSTL MAIN FEED & ENGZ PANEL 1BMLEB2
OFM	01170050	INSTL MAIN FEED & ENGZ PANEL IEPLEBI
OFM	01170052	INSTL MAIN FEED & ENGZ PANEL IBMLA2
OFM	01170054	INSTL PERM FIXTURES 545’-589
OEM	01170055	INSTALL PERM FIXTURES 545’-589
OFM	01170056	INSTL LTG IN BOILER WTR SAMPLE AREA
OFM	01180034	RUN PHONE WIRING
OFM	01180035	RUN PHONE WIRING PERMANENT POWER FOR PA
OFM	01180039	PERMANENT POWER FOR PA
OFM	01180040	PERMANENT POWER FOR PA
OFM	02010901	FINAL PUNCHLI5T-~SERVICE BLDG
OFM	02020219	SB SHOP HOISTS
OFM	02080012	CONDUIT/PWR WRG-SB DOCKLIFT, LEVELATOR
OFM	02080023	CONDUIT/PWR WIRING & LIGHTING DOCK AREA
OFM	01040316	HDR REM J—L, 11-15 ELEV 576+589
OFM	01040337	REMAINING TOE PLATE
OFM	01040339	REWORK STAIR STRINGERS
OEM	01050040	GRATING FINISH CONVEYOR ROOM
OFM	01060730	TURB RN GRT FIN TO 530’
OFM	01080616	CONTROL WRG FOR MOTOR OP LV BR 505’
OFM	0108061’8	POWER & CONTROL CARD READERS
OFM	01080619	POWER & CONTROL CARD READERS
OFM	01090037	MULTIPLEX ROOMS (9) CONDENSATE
OFM	01150003	PERM AC FROM MCC TO SPLICE BOX TE~
OFM	01150004	ELEVATOR PENTHOUSE EXHAUST FAN
OFM	01150005	SHIELD FOR LOUVER AT ELEV MACHINE RM
OFM	01170013	LTG MN TRANSF AREA
OFM.	01170016.	LTG BLR P14 GRD FLR
OFM	01170017	LTG ELR RM GRD FLR
OFM	01170018	LTG CONV RM MEZZ; EL 545 & 546
OFM	01170019	LTG CONV RM MEZZ; EL 545 & 546
OFM	01170020	LTG BLR RM1 MEZZ
OFM	01170021	LTG BLR RM MEZZ

SITE IMPROVEMENTS

1.	General Site Crating and Drainage
2.	Helicopter Pad
3.	Monitoring Wells
4.	Roadways
5.	Guard Facilities
6.	Underground Electrical Ducts
7.	Sanitary Sewer Lines
8.	Shoreline Protection
9.	Fire Protection Lines
10.	Potable Water Lines
11.	Cathodic Protection
G.	Water Treatment Building
1.	Masonry Blockwork
2.	Static Wall Siding
3.	HVAC
4.	Fire Protection Equipment
5.	Monorail
6.	Piping Systems
7.	Sanitary Waste Treatment Equipment
8.	Water Treatment Equipment
9.	Condensate Storage Tank
10.	Conduit and Cable Tray
11.	4160 Volt Equipment
12.	480 Volt Equipment
13.	208/110 Volt Equipment
14.	Lighting
15.	Communications
16.	Multiplex System
17.	Motor Driven Fire Pump
18.	Chemical injection Equipment
19.	Demineralizer Water System
H.	Cooling Tower
1.	Cooling Tower Pumps
2.	Circulating Water Lines
3.	Condenser
4.	480 Volt Equipment
5.	Lighting
6.	Communications
I.	Station Auxiliary
1.	138 Volt Equipment
2.	6900 Volt Equipment

2

3.	480 Volt-Equipment
4.	208/110 Volt Equipment
5.	Sprinkler System
OTHER EQUIPMENT, SYSTEMS, AND STRUCTURES
1.	Fuel Oil Tanks, Piping, Pump House, and Electrical Building
2.	Ash Pond, Pipe Rack, and Pipe
3.	Emergency Ash Pond

3

OFM	02080024	CONTROL WIRING DOCK AREA
OFM	02110010	PWR & CONDT-FIRE DETECTION SYSTEM-S. B.
OFM	02110011	INSTL FIRE DETECTION SYSTEM SERV BLDG
OFM	02110020	SECURITY MONITORING SYSTEM SERV BLDG
OFM	02110021	SECURITY MONITORING SYSTEM SERV BLDG
OFM	02110022	RPR 0/HEAD SPRINK HDS PPD CONY RM&0FF
OFM	02130051	PROVIDE LTG & PWR PPD WAREHOUSE OFF.
OFM	02130052	RELOCATE LIGHTS IN PPD WAREHOUSE
OFM	02140019	INSTL/WIRE AC/DC DISTRIBUTION
OFM	02140020	INSTL/WIRE AC/DC DISTRIBUTION
OFM	02160017	WATER SUPPLY FOR S.B. ROOF CHILLERS
OFM	02160901	CHECK -OUT EXHAUSTERS
OFM	02160902	CHECK-OUT EXHAUSTERS
OFM	02190001	SET PNLS & TR MECH MAINT SHOP EQUIP
OFM	02190002	CDL TRAY/COND MECH MAINT SHOP EQUIP
OFM	190003	POWER WIRING MAINT SHOP EQUIP
JLP	03120003	INSTALL SCREENHOUSE CABLE TRAY COVERS
CRP	06060088	COMPLETE SECURITY MONITORING
CRP	06090026	INSTL PIPE&WIRE SEW TREAT PUMP TO BAP
CRP	06090027	INSTL PIPE&WIRE S-W TREAT PUMP TO BAP
FJW	07010056	PIPE RACK FROM SWTB TO ASH POND
FJW	07010060	GROUND PIPE RACK STEEL
FJW	07010062	INSULATION-PIPE AT ASH POND
FJW	07010067	MOUNT FIELD MTD . INSTRUMENTS
FJW	07010074	PIPE RACK-STEEL-SDRS TO UNIT
FJW	07010075	PIPE RACK-’INSULATION-SDRS TO UNIT
FJW	07010077	INST TRS ,PNLS ,COND, WRG, & HT TRAC P RACK
FJW	07010900	OPERATIONAL CHECK-OUT ABOVE GND PPG
FJW	07010901	FINAL PUNCH LIST ABOVE GROUND PIPING
FJW	07010902	CHECK-OUT HEAT TRACE
FJW	07010905	CHECK-OUT FIELD MOUNTED INSTRUMENTS
FJW	07010903	OPERATIONAL CHECK-OUT ABOVE GND PPG
FJW	07010904	FINAL PUNCHLIST ABOVE GROUND PIPING
FJW	07010906	CHECK-OUT VERTICAL ASH WATER PUMPS
FJW	07010907	CHECK-OUT VERTICAL ASH WATER PUMPS
FJW	07010908	CHECK-OUT VERTICAL ASH WATER PUMPS
FJW	07010909	CHECK-OUT VERTICAL ASH WATER PUMPS
FJW	07030024	INSTALL & WIRE RECEPTACLES
FJW	07030040	SERV BLDG & YARD LTG
FJW	07030041	SERV BLDG & YARD LTG
FJW	07030900	OPERATIONAL CHECK-OUT ABOVE GND PPG

CRP	08150010	CHECK & BOND UNDGND PIPE 1990
CRP	08150901	FINAL PUNCHLIST-UNDERGROUND PIPING
WBH	10030034	INSTALL DRUM INSTRUMENTATION
WBH	10030900	OPERATIONAL CHECK-OUT BOILER
WBH	10030901	CHECK-OUT DRUM INSTRUMENTS
WBH	10030902	FINAL PUNCHLIST BOILER
WBH	10040900	CHECK-OUT ECONOMIZER INSTRUMENT
WBH	10060900	CHECK-OUT HEADER INSTRUMENT
WBH	10070864	REWORK BLR WTR WALL ROOF TUBE
WBH	10070865	REWORK BLR WTR WALL ROOF TUBE
WBH	10070900	CHECK-OUT FURNACE INSTRUMENT
WBH	10080900	CHECK-OUT DRAIN & VENT INSTRUMENT
WBH	10090900	CHECK-OUT SOOTBLOWERS & PROBES
WBH	10090901	CHECK-OUT SOOTBLOWERS & PROBES
WBH	10120202	BOILER PENTHOUSE WALLS
WBH	10120203	BOILER PENTHOUSE WALLS
WBH	10120204	INSULATE BOILER DRUM ENDS
WBH	10120208	LAGGING ON FURN REAR WALL
WBH	10120209	LAGGING ON FURN REAR WALL
WBH	10120210	LAGGING ON FURN SOUTH WALL
WBH	10120211	LAGGING ON FURN SOUTH WALL
WBH	10120212	LAGGING ON FURN NORTH WALL
WBH	10120213	LAGGING ON FURN NORTH WALL
WBH	10120214	LAGGING ON FURNACE FRONT WALL
WBH	1012015	LAGGING ON FURNACE FRONT WALL
WBH	10120216	ECONOMIZER WALL INSULATION
WBH	10120217	ECONOMIZER HOPPER INSULATION
WBH	10120218	ECONOMIZER LAGGING
WBH	10120219	ECONOMIZER LAGGING
WBH	10120220	INSULATE EXTENDED SIDE WALLS
WBH	10120221	LAGGING ON EXT SIDE WALL
WBH	10120222	LAGGING ON EXT SIDE WALL
WBH	10120223	INSULATE NORTH RETR STBLW PIPE
WBH	10120224	INSULATE SOUTH RETR STBLW PIPE
WBH	10120225	INSULATE WALLBLOWER PIPE
WBH	10120226	INSUL STBLOW REDUCING STATION
WBH	10120227	INSULATE REHEAT BYPASS TUBES
WBH	10120228	INSULATE ECON RECIRC LINE
WBH	10120229	INSULATE DRAIN PIPES
WBH	10120232	LAGGING ON BOILER LOWER DRUMS
WBH	10130010	INSTL BLR THERMA COUPLES & MISC INSTR
WBH	11030902	FINAL PUNCHLIST DRAFT EQUIP
WBH	11050902	FINAL PUNCHLIST DRAFT EQUIP
WBH	11030903	FINAL PUNCHLIST DRAFT EQUIP
WBH	11050903	FINAL PUNCHLIST DRAFT EQUIP
WBH	11010019	INSULATION ‘B’ IB ID FAN
WBH	11010045	INSULATION ‘A’ 1A ID FAN

2

WBH	11010900	OPERATIONAL CHECK-OUT DRAFT EQUIPMENT
WBH	11010901	OPERATIONAL CHECK-OUT DRAFT EQUIPMENT
WBH	11030900	OPERATIONAL CHECK-OUT DRAFT EQUIPMENT
WBH	11030901	OPERATIONAL CHECK-OUT DRAFT EQUIPMENT
WBH	11050904	C/OUT PAH DUCT, CONT DRIVERS & INSTR.
WBH	11050904	C/OUT ACM DUCT, CONT DRIVERS & INSTR.
WBH	11050906	C/OUT AAH DUCT CONT. DRIVERS & INSTR.
WBH	11060900	CHECK-OUT A&B SIDE GAS DUCT
WGH	11070018	INSULATE AIR PREHEATER
ALZ	15005902	OPERATIONAL C/OUT BLR FD & SER WTR EQP
ALZ	15005903	OPERATIONAL C/OUT BLR FD & SER WTR EQP
ALZ	15005904	OPERATIONAL C/OUT BLR FD & SER WTR EQP
ALZ	15005905	OPERATIONAL C/OUT BLR FD & SER WTR EQP
ALZ	15005906	FINAL PUNCHLIST-BLR FD & SER WTR EQUIP
ALZ	15005907	FINAL PUNCHLIST-BLR FD & SER WTR EQUIP
ALZ	15005908	FINAL PUNCHLIST-BLR FD & SER WTR EQUIP
ALZ	15005909	FINAL PUCHLIST-BLR FD & SER WTR EQUIP
ALZ	15010014	INSULATE PUMP
ALZ	15020003	FACTORY APPROVAL 1A TDBFP
ALZ	15020005	I & C TDBFP (A-SIDE)
ALZ	15020014	HYDRO TEST DUCT 1A TDBFP
ALZ	15020015	INSULATE DUCT
ALZ	15020023	FINAL PUMP MECH
ALZ	15020024	FINAL TURBINE MECHANICAL 1A TDBFP
ALZ	15020026	INSULATE 1A TDBFP
ALZ	15020043	FACTORY APPROVAL 1B TDBFP
ALZ	15020045	I & C TDBFP (B-SIDE) 1B TDBFP
ALZ	15020054	HYDRO TEST DUCT 1B TDBFP
ALZ	15020055	INSULATE DUCT 1B TDBFP
ALZ	15020063	FINAL PUMP MECHANICAL 1B TDBFP
ALZ	15020064	FINAL TURB MECHANICAL 1B TDBFP
ALZ	15020066	INSULATE 1B TDBFP
ALZ	15020900	CHECK-OUT 1A TDBFP
ALZ	15020901	CHECK-OUT 1B TDBFP
ALZ	15030023	INSULATE HTR A & B
ALZ	15050900	CHECK OUT CHEMICAL INJECTION EQUIPMENT
ALZ	15050901	CHECK OUT CHEMICAL INJECTION EQUIPMENT
FJW	18010004	PROJECT INSUL VENTS&DRAINS (NO JACKET)
FJW	18010008	INSULATE BLR FILL & DRAINS AFTER HYDRO
FJW	18010009	INSUL JACKET-VENTS & DRAINS
FJW	18060060	INSULATE MS-3,4,9 TR (NO JACKET)
FJW	18060062	INSULATE MS – 1,2 BR 14.5-12 (NO JACKET)
FJW	18060063	INSULATION MS-6/9 (NO JACKET)
FJW	18060065	INSUL JACKET –MS-3,4,9 TR
FJW	18060070	SET AND LOAD HANGERS MS
FJW	18060071	INSUL JACKET-MS BR&CR 17-14.5
FJW	18060072	INSUL JACKET-MS-1,2 BR-14.5-12

3

FJW	18060075	INSUL JACKET-MIS 6,9
FJW	18060212	CONT WRG MN STMT C & MISC INST
FJW	18070061	INSULATE HR BR & CR 17-14.5
FJW	18070062	INSULATE HR BR 14.5-12
FJW	18070063	INSULATE CR BR&CR 17-14.5 (NO JACKET)
FJW	18070064	INSULATE CR BR 14.5-12 (NO JACKET)
FJW	18070066	INSULATE CR TURBINE RM (NO JACKET)
FJW	18070070	SET AND LOAD HGRS REHEAT
FJW	18070075	INSULATE CR 2.1 (NO JACKET)
FJW	18070093	RECALIBRATE HOT-REHEAT HANGERS
FJW	18070361	INSUL JACKET –HR BR& CR 17-14.5
FJW	18070362	INSUL JACKET-JR BR 14.5-12
FJW	18070363	INSUL JACKET-CR BR&CR 17-14.5
FJW	18070364	INSUL JACKET-CR BR 14.5-12
FJW	18070366	INSUL JACKET-CR TURBINE ROOM
FJW	18070375	INSUL JACKET-CR 2.1
FJW	18090007	H/F/W GS TDBFP’S
FJW	18090008	H/F/W GS TDBFP’S
FJW	18090010	REMOVE GS TEMP PIPE HOTWELL PUMP
FJW	18090011	REMOVE GS TEMP PIPE MDBFP
FJW	18090012	REMOVE GS TEMP PIPE TDBFP’S
FJW	18090013	REMOVE GS TEMP PIPE COND MAKE-UP PUMPS
FJW	18100006	INSULATE BFD-5 BR&CR (NO JACKET)
FJW	18100010	INSUL JACKET –BFD-5 BR & CR
FJW	18100054	INS FOR 25 BFD & RECIRC
FJW	18100207	INSULATE BFD ELEV 505-530 (NO JACKET)
FJW	18100216	INSULATE BFD ELEV. 475-505 (NO JACKET)
FJW	18100224	INSUL JACKET-BFD ELEV 505-530
FJW	18100234	INSULATE BFD ELEV. 530-550 (NO JACKET)
FJW	18100241	WET AND LOAD HANGERS
FJW	18100266	INSUL JACKET-BFD ELEV 475-505
FJW	18100280	INSUL JACKET-BFD ELEV 530-550
FJW	18110006	INSULATE AT – 4,5,6,7 (NO JACKET)
FJW	18110009	INSUL JACKET-AT 4,5,6,7
FJW	18110027	INSULATE AT–1,2,3 (NO JACKET)
FJW	18110031	INSUL JACKET – AT 1,2,3
FJW	18110035	CONTROL WRG INSTRUM & CV’S
FJW	18110046	SET AND LOAD HANGERS
FJW	18120023	INSTRUM BFS PPG
FJW	18120025	CONT WRG INSTRUM
FJW	18120062	INS 12” BFS-2 HDR TO TDBFP (NO JACKET)
FJW	18120063	INS 12” BFS-2 HDR TO MDBFP (NO JACKET)
FJW	18120070	SET AND LOAD HANGERS BFS
FJW	18120262	INSUL JACKET-12” BFS-2 HEADER TO TDBFP
FJW	18120263	INSUL JACKET-12” BFS-2 HEADER TO MDBFP
FJW	18130021	INS ES-10, 11, 12 DAHDR-DA&TDBFD (NO JKT)
FJW	18130028	INSTRUM EXT STM PIPING

4

FJW	18130036	INSUL ES-18, 19, 22, 23, 24 CRV’S (NO JKT)
FJW	18130221	INSUL JACKET-ES-10, 11, 12 DAHDR DA&TDBFP
FJW	18130236	INS JKT-ES-12 TO TDBFD
FJW	18130244	INSUL JACKET-ES-12 TO TDBFD
FJW	18140082	INSUL JACKET-HOV PERSONEL PROT
FJW	18140225	INSUL HOV PERSONEL PROTECTION (NO JKT)
FJW	18150002	INSULATE TDR (NO JACKET)
FJW	18150007	INSUL JACKET-TDR
FJW	18150021	CONTROL WRG FOR 17 MOV’S FOR TDR
FJW	18190017	CTL COND-TUBE 4CV’S BA HOP OVERFLW TNK
FJW	18190025	INS FOR TUBE 2 CV’S & 4 INSTRU@FLYASH
FJW	18190030	HFW HP WTR PIPING PUMP TO HYDROVEYORS
FJW	18190031	HFW HP WTR PIPING PUMP TO HYDROVEYORS
FJW	18280002	B.R. HOUSE AIR ABOVE 530
FJW	18280003	B.R. HOUSE AIR ABOVE 530
FJW	18280005	CTL COND FOR (12) INSTT-UNIT HSE AIR PPG
FJW	1832002	INSULATE CHEM INJECTION PPG (NO JKT)
FJW	18320004	INSUL JACKET-CHEM INJECT PPG
JLP	21030041	CONDUIT FOR PRECIP INSTRUMENT.
JLP	21030043	CONDUIT FOR ID FAN MONORAILS
JLP	21030044	POWER WRG FOR ID FAN MONORAILS
JLP	21030045	CONDUIT FOR HOPPER HEATERS
JLP	21030046	POWER WRG FOR HOPPER HEATERS
JLP	21030047	CONDUIT FOR ESP MONORAILS
JLP	21030048	POWER WRG FOR ESP MONORAIL
JLP	21030052	CTL WRG HOPPER LEVEL DETECTORS
JLP	21030053	CONDUIT FOR ESP BRIDGE CRANE
JLP	21030054	POWER WRG FOR ESP BRIDGE CRANE
JLP	21030059	CONTROL WRG FOR ID FAN MONORAILS
JLP	21030061	CONTROL WRG FOR ESP MONORAIL
JLP	21030066	CONTROL WRG FOR ESP BRIDGE CRANE
JLP	21030075	CONDUIT FOR HVAC
JLP	21030076	PWR WIRING FOR HVAC
JLP	21030078	INSTALL UPS PANELS & FEEDS IN PRECIP
JLP	21030080	CONDUIT TO PENTHOUSE VENT FANS
JLP	21030081	POWER WIRING TO PENTHOUSE VENT FANS
JLP	21030082	CONTROL WIRING TO PENTHOUSE VENT FANS
JLP	21030083	PENTHOUSE VENT FANS
JLP	21030084	INSTALL KEY INTERLOCK SYS/ESP
JLP	21030085	INSTALL KEY INTERLOCK SYS/ESP
JLP	21040002	INSULATE N-SIDE END WALLS
JLP	21040004	INSULATE S-SIDE END WALLS
JLP	21040008	N-SIDE INLET NOZZLE INSULATION
JLP	21040010	S-SIDE INLET NOZZLE INSULATION
JLP	21040018	INSULATE N-SIDE OUTLET NOZZLE
JLP	21040019	INSULATE S-SIDE OUTLET NOZZLE
JLP	21040020	INSULATE S-SIDE OUTLET NOZZLE

5

JLP	21040026	INL DUCK PREINSUL SIDING
JLP	21040028	INST LTG ELCT BLDG
JLP	21040029	INST LTG ELCT BLDG
JLP	21040222	OUTLET DUCT PREINSULATED SIDING
JLP	21060003	INST RCPTS ELECT BLDG
JLP	21060004	INST RCPTS HOPPER RM
JLP	21060005	SET TR & RCPT PNL (PNTHSE)
JLP	21060006	SET TR & RCPT PNL (PNTHSE)
JLP	21060008	INST RECPTS PNTHSE
JLP	21080002	INST LTG HOPPER RM
JLP	21080003	INST LTG HOPPER RM
JLP	21080005	INST LTG PNTHSE
JLP	21080006	INST LTG PNTHSE
JLP	21080008	INST OUTDOOR LTG
JLP	21080009	INST OUTDOOR LTG
JLP	21090001	INST COMM ELECT BLDG
JLP	21090002	INST COMM ELECT BLDG
JLP	21090003	INST COMM ELECT BLDG
JLP	21090004	INST COMM HOPPER RM
JLP	21090005	INST COMM HOPPER RM
JLP	21090006	INST COMM HOPPER RM
JLP	21090007	INST COMM PNTHSE
JLP	21090008	INST COMM PNTHSE
JLP	21090009	INST COMM PNTHSE
JLP	21100008	INST GND SYS PNTHSE
JLP	21130005	POWER WIRING – HVAC
ADR	21130900	CHECK-OUT CONTROL BLDG HVAC
ADR	22020023	PERM FEED TO STACK LIGHTS
ADR	22020024	INSTALL PERM FEED TO ELEV
ADR	22030006	FINAL SUPPORT SAMPLE TUBING
ADR	22030900	C/OUT INSTRUMENTATION/STACK MONITORING
ALZ	25020035	INST TR, PNL, CON, WRG&HEAT TRACE CONV RM
ALZ	25020036	INST TR, PNL, CON, WRG&HEAT TRACE CONV RM
ALZ	25020902	FINAL PUNCHLIST-PLANT COAL HANDLING
ALZ	25020903	FINAL PUNCHLIST-PLANT COAL HANDLING
ALZ	25030900	CHECK-OUT AS-FIRED SAMPLING EQUIPMENT
ALZ	25040901	FINAL PUNCHLIST-PLANT COAL HANDLING
ALZ	26010017	FINAL ADJ MILLS
ALZ	26010900	OPERATIONALC/OUT PULVERIZED FUEL EQUIP
ALZ	26010901	FINAL PUNCHLIST-PULVERIZED FUEL EQUIP
ALZ	26010902	FINAL PUNCHLIST-PULVERIZED FUEL EQUIP
ALZ	26010903	FINAL PUNCHLIST-PULVERIZED FUEL EQUIP
ALZ	26020900	CHECK-OUT COAL FEEDERS
ALZ	26020901	CHECK-OUT COAL FEEDERS
ALZ	26020902	CHECK-OUT COAL FEEDERS

6

ALZ	26030011	INSTALL AIR CONNECTIONS @ PIPE
ALZ	26030012	INSTALL AIR CONNECTIONS @ PIPE
JLP	30070001	EXTERIOR LTG
JLP	30110008	FUEL OIL UNLOADING PAD
DCW	31030221	INSTL BULKHEAD&DOORS C,D & S CONVEYOR
DCW	31030223	INSTL BULKHEAD&DOORS C,D & S CONVEYOR
DCW	31030285	INST TR,PNL,COND,WRG&HT TRC COAL UNLD
DCW	31030901	FINAL PUNCHLIST-KCOAL UNLOADING
DCW	31040216	INSTALL TOEPLATE-TRANSFER HSE
ALZ	32010900	CHECKOUT-STACKER/RECLAIMER
ALZ	32020012	FINAL CONST INSPECT VIBRATING FEEDERS
ALZ	32020013	FINAL CONST INSPECT VIBRATING FEEDERS
ALZ	32020014	FINAL CONST INSPECT VIBRATING FEEDERS
ALZ	32020900	OPERATIONAL CHECKOUT-COAL CONVEYING
ALZ	32020901	FINAL PUNCHLIST-COAL CONVEYING
ALZ	32030039	INSTL BULKHDS & DRS CRUSH HSE CONV E&R1
ALZ	32030040	INSTL BULKHDS & DRS CRUSH HSE CONV E&R1
ALZ	32030084	FLUSH&TEST UPPER E/F1/F2 & r1 FIRE PROT
ALZ	32030900	OPERATIONAL CHECKOUT-COAL CONVEYING
ALZ	32030901	FINAL PUNCHLIST-COAL CONVEYING
ALZ	32030902	CHECKOUT-R CONVEYOR
ALZ	32040900	OPERATIONAL CHECKOUT-COAL CONVEYING
ALZ	32040901	FINAL PUNCHLIST-COAL CONVEYING
ALZ	32050018	MAGNETIC SEPERATOR TRASH CHUTE
ALZ	32050019	MAGNETIC SEPERATOR TRASH CHUTE
ALZ	32050900	OPERATIONAL CHECKOUT-COAL CONVEYING
ALZ	32050901	FINAL PUNCHLIST-COAL CONVEYING
ALZ	32070009	INSTALL FLOOR LIFT
ALZ	32070032	POWER WIRING HVAC
ALZ	32070033	CONTROL WIRING HVAC
ALZ	32070033	CONTROL WIRING HVAC
ALZ	32070037	CONDUIT/WIRING TO PUMPS
ALZ	32070038	CONDUIT/WIRING TO PUMPS
ALZ	32070051	SET AIR COMP & INSTL PIPING
ALZ	32070052	SET AIR COMP & INSTL PIPING
ALZ	32070053	SET AIR COMP & INSTL PIPING
ALZ	32070054	INSTALL PA & TELEPHONE EQUIP.
ALZ	32070055	INSTALL PA & TELEPHONE EQUIP.
ALZ	32070057	PWR & CTL FOR AIR COMPRESSOR
ALZ	32070058	PWR & CTL FOR AIR COMPRESSOR
ALZ	32070059	ELECTRICAL FOR (2) FLOOR LIFTS
ALZ	32070060	ELECTRICAL FOR (2) FLOOR LIFTS
ALZ	32070900	OPERATIONAL CHECKOUT-COAL
ALZ	32070901	FINAL PUNCHLIST-COAL CONVEYING
DCW	35030050	DUST SUPPRESSION SYS (A CONV)
DCW	35030051	DUST SUPPRESSION SYS (A CONV)
DCW	35030052	DUST SUPPRESSION SYS (A CONV)

7

DCW	35030053	DUST SUPPRESSION SYS (A CONV)
DCW	35030267	INST TR,PNL,COND,WRG&HT TRC-LS CONV&RPB
DCW	35030907	CHECK-OUT DUST SUPPRESSION EQUIPMENT
DCW	35030908	CHECK-OUT DUST SUPPRESSION EQUIPMENT
DCW	35030909	CHECK-OUT DUST SUPPRESSION EQUIPMENT
DCW	35030910	OPER C/OUT REACTANT SUPPLY & BARG UNLD
DCW	35030911	FINAL PUNCHLIST-REACT SUPPLE& BARGE UNLD
DCW	35050020	LIGHTING FOR LIME TRANSFER HSE
DCW	35050023	CONDUIT/PWR WRG-HVAC
DCW	35050901	CHECK-OUT MATERIAL HANDLING EQUIPMENT
DCW	35050902	CHECK-OUT MATERIAL HANDLING EQUIPMENT
DCW	35050903	OPER C/OUT REACTANT SUPPLY & BARGE UNLD
DCW	35050904	FINAL PUNCHLIST-REACT SUPPL & BARGE UNLD
DCW	35060028	LAPE LIGHTING
DCW	35070010	FINAL CONSTR INSPECTION DEAD STOR HOP
DCW	35110003	WIRE & ENERG RCPT PNL
DCW	35110005	INST RECPT BRIDGE,A CONV,&TRANSFER HSE
DCW	35110007	INST RECPT B7C CONV,LAPE,RECLM
DCW	35130003	PULL MN CBLS & ENERG LTG PNL
DCW	35130005	INST LGT A-CONV,B CONV,C CONV&RECLM TUN
DCW	35130006	INST LGT A-CONV,B CONV,C CONV&RECLM TUN
DCW	35140002	INST COMM TRANS HSE & A CONV
DCW	35140003	INST COMM TRANS HSE & A CONV
DCW	35140004	INST COMM TRANS HSE & A CONV
DCW	35140005	INST COMM B CONV, C CONV, LAPE
DCW	35140006	INST COMM B CONV, C CONV, LAPE&RECLM TUNL
DCW	35150001	INST UNDERGROUND GRID
DCW	35180009	INSTALL LIMESTONE HANDLING
DCW	35180010	INSTALL LIMESTONE HANDLING
CRP	40010900	CHECK-OUT INSTRUMENT FOR INLET DUCTS
CRP	40010901	OPERATIONAL CHECK-OUT – SDRS
CRP	40010902	FINAL PUNCH LIST – SDRS
CRP	40010903	FINAL PUNCH LIST – SDRS
CRP	40020550	SDRS ROOF HANDRAIL
CRP	40020707	CONDUIT FOR COMPRESSOR BAY ROOF EXHAUST
CRP	40020708	PWR WIR FOR COMPRESSOR BAY ROOF EXHAUST
CRP	40020709	CTL WIR FOR COMPRESSOR BAY ROOF EXHAUST
CRP	40020716	CONDUIT FOR SDRS ROLL UP DOORS
CRP	40020717	POWER WIRING FOR ROLL UP DOORS
CRP	40020718	CONTROL WRG FOR ROLL UP DOORS
CRP	40020719	CONDUIT FOR HVAC HEATER & EXH
CRP	40020720	PWR WRG FOR HVAC HEATER & EXH
CRP	40020721	CONTROL WRG-HVAC HEATER & EXH

8

CRP	40020722	INSTALL LTG IN SDRS STRUCTURE
CRP	40020850	SDRS HVAC, HEATER & EXHAUSTER
CRP	40020851	SDRS HVAC, HEATER & EXHAUSTER
CRP	40020852	SDRS HVAC, HEATER & EXHAUSTER
CRP	40020901	CHECK-OUT REACTANT NK SCREEN
CRP	40020902	OPERATIONAL CHECK-OUT – SDRS
CRP	40020903	FINAL PUNCH LIST – SDRS
CRP	40020904	FINAL PUNCH LIST – SDRS
CRP	40040900	CHECK-OUT REACTANT NK INSTRUM.
CRP	40040901	OPERATIONAL CHECK-OUT – SDRS
CRP	40040902	FINAL PUNCH LIST – SDRS
CRP	40040903	FINAL PUNCH LIST – SDRS
CRP	40050900	C/OUT DEMISTER WASH & SEAL WATER TANKS
CRP	40050901	C/OUT DEMISTER WASH & SEAL WATER TANKS
CRP	40050902	OPERATIONAL CHECK-OUT – SDRS
CRP	40050903	FINA PUNCH LIST – SDRS
CRP	40050904	FINAL PUNCH LIST – SDRS
CRP	40060008	SDRS SERVICE BLDG LIGHTING
CRP	40060009	SDRS SERVICE BLDG. LIGHTING
CRP	40060018	CONTROL WRG-SDRS SERV BLDG
CRP	40060051	DEMISTER ROOM LIGHTING
CRP	40080022	DEMISTER WASH PUMPS
CRP	40080206	CRANES & HOIST SDRS
CRP	40080235	CONDUIT FOR SDRS CRANES AND HOIST
CRP	40080237	POWER WIRING FOR SDRS CRANES AND HOISTS
CRP	40080904	CHECK-OUT PURGE AIR FANS
CRP	40080905	CHECK-OUT PURGE AIR FANS
CRP	40080906	CHECK-OUT CRANES & HOIST
CRP	40080910	CHECK-OUT SUMP PUMPS
CRP	40080911	CHECK-OUT SUMP PUMPS
CRP	40080912	OPERATIONAL CHECK-OUT – SDRS
CRP	40080913	FINAL PUNCH LIST – SDRS
CRP	40080914	FINAL PUNCH LIST – SDRS
CRP	40100051	FRP DUCK DRAIN PIPING
CRP	40100052	FRP DUCK DRAIN PIPING
CRP	40100059	HEAT TRACE & INS SERV& ASH WTR
CRP	40100060	HEAT TRACE & INS SERV& ASH WTR
CRP	40100066	HEAT TRACE&INS RETURN WTR REACT TANKS
CRP	40100067	HEAT TRACE&INS RETURN WTR REACT TANKS
CRP	40100070	HEAT TRACE&INS DEMIS WASH PIPING
CRP	40100071	HEAT TRACE&INS DEMIS WASH PIPING
CRP	40100900	OPERATIONAL CHECK-OUT – SDRS
CRP	40100902	FINAL PUNCH LIST – SDRS
CRP	40130003	INSTL & WIRE RECEPTABLE-A SIDE
CRP	40130006	INSTL & WIRE RECEPTABLE-B SIDE
CRP	40140003	INST CABLE TRAY ‘A’ ABSORBER
CRP	40140004	INST CABLE TRAY ‘A’ ABSORBER

9

CRP	40140005	INST CABLE TRAY ‘B’ ABSORBER
CRP	40140006	INST CABLE TRAY ‘B’ ABSORBER
CRP	40140900	OPERATIONAL CHECK-OUT – SDRS
CRP	40140901	FINAL PUNCH LIST – SDRS
CRP	40140902	FINAL PUNCH LIST – SDRS
CRP	40160001	INST COMM CONTROL BUILDING
CRP	40160002	INST COMM CONTROL BUILDING
CRP	40160003	INST COMM PMP BLDG
CRP	40160004	INST COMM PMP BLDG
CRP	40160005	INST COMM PMP BLDG
CRP	40160006	INST COMM A ABSORBER
CRP	40160007	INST COMM A ABSORBER
CRP	40160008	INST COMM A ABSORBER
CRP	40160009	INST COMM B ABSORBER
CRP	40160010	INST COMM B ABSORBER
CRP	40160011	INST COMM B ABSORBER
CRP	40160012	INST COMM REACT TANK
CRP	40160013	INST COMM REACT TANK
CRP	40160014	INST COMM REACT TANK
CRP	40160015	INST COMM STEEL TANKS
CRP	40160016	INST COMM STEEL TANKS
CRP	40160017	INST COMM STEEL TANKS
CRP	40160019	INSTL PHONE BOX,CABLE,HEADSETS & WIRE
CRP	40160900	OPERATIONAL CHECK-OUT – SDRS
CRP	40160901	FINAL PUNCH LIST – SDRS
CRP	40160902	FINAL PUNCH LIST – SDRS
CRP	40170003	INSTALL GROUND CONTROL BLDG
CRP	40190004	INSTALL UPS SYSTEM
JLP	41010900	OPERATIONAL CHECK-OUT-REACTANT
JLP	41010901	OPERATIONAL CHECK-OUT-REACTANT PREP
JLP	41010902	FINAL PUNCHLIST-REACTANT PREP
JLP	41010903	FINAL PUNCHLIST-REACTANT PREP
JLP	41010006	LIGHTING-REACTANT PREPARATION
JLP	41010007	HVAC-ELECT PWR/CNTL REACT PREP BLDG
JLP	41020040	INSTALL LEVEL SWITCHES
JLP	41020041	INSTALL LEVEL SWITCHES
JLP	41020042	INSTALL LEVEL SWITCHES
JLP	41050022	INSTR FOR REACT SUPPLY BLDG MILL EQUIP
JLP	41050080	COMPL GUARDS, DRS, MISC SYS ON MILLS
JLP	41050900	CHECK-OUT LIMESTONE MILL PUMPS
JLP	41050901	CHECK-OUT LIMESTONE MILL PUMPS
JLP	41050902	CHECK-OUT LIMESTONE MILL PUMPS
JLP	41050903	CHECK-OUT MILLS
JLP	41050904	CHECK-OUT MILLS
JLP	41050905	CHECK-OUT MILLS
JLP	41050906	CHECK-OUT JIB CRANE
JLP	41050907	CHECK-OUT REACTANT LIVE STORAGE PUMPS

10

JLP	41050908	CHECK-OUT REACTANT LIVE STORAGE PUMPS
JLP	41050909	CHECK-OUT REACTANT LIVE STORAGE PUMPS
JLP	41050910	CHECK-OUT LOAD CELLS
JLP	41050911	OPERATIONAL CHECK-OUT-REACTANT
JLP	41050912	FINAL PUNCHLIST-REACTANT PREP
JLP	41060002	INSULATE YARD AREA PIPE
JLP	41060015	HEAT TRACING
JLP	41060020	INSTL 15 INSTRU REACT SPLY BLDG PPG
JLP	41060021	INSTL 15 INSTRU REACT SPLY BLDG PPG
JLP	41060022	INSTL 15 INSTRU REACT SPLY BLDG PPG
JLP	41060030	HOUSE AIR PIPING – RPB
JLP	41060031	HOUSE AIR PIPING – RPB
JLP	41060900	CHECK-OUT PIPING/INSTRUMENTS
JLP	41060901	OPERATIONAL CHECK-OUT-REACTANT
JLP	41060902	FINAL PUNCHLIST-REACTANT PREP
JLP	41090006	INSTL & WIRE RECEPT REACT PREP BLDG
JLP	41110001	LST LIGHTING
JLP	41110002	LST LIGHTING
JLP	41120003	INSTL COMM EQUIP REACTANT PREP BLDG
JLP	41120005	INST COMM EQUIPMENT YARD
JLP	41120006	INST COMM EQUIPMENT YARD

11

EX-10.43

EXHIBIT 10.43

PARTICIPATION AGREEMENT

BY AND BETWEEN

LOUISVILLE GAS AND ELECTRIC COMPANY

220 West Main Street

Post Office Box 32010 (40232)

Louisville, Kentucky 40202

AND

INDIANA MUNICIPAL POWER AGENCY

11610 North College Avenue

Carmel, Indiana 46032

February 1, 1993

TABLE OF CONTENTS
ARTICLE 1. DEFINITIONS
1.1.	Agreed Rate.
1.2.	Agreement.
1.3.	Available.
1.4.	Capacity Factor.
1.5.	Closing.
1.6.	Commercial Operation Date.
1.7.	Construction Work.
1.8.	Coordination Committee.
1.9.	Delivery Points.
1.10.	Effective Date.
1.11.	Electric Capability.
1.12.	Electric Energy.
1.13.	Electric Capability And Energy.
1.14.	Electric Capability And Energy Entitlement.
1.15.	Execution Date.
1.16.	Fixed Operation and Maintenance Expenses.
1.17.	Force Majeure.
1.18.	Fuel/Reactant Operation Expenses.
1.19.	Good Utility Practice.
1.20.	Incremental Capital Assets.
1.21.	Insurance.
1.22.	Interconnection Agreement.
1.23.	Internal Load.
1.24.	Joint Transmission System.
1.25.	Louisville’s Cost Of Capital.
1.26.	Net Electric Generating Capability And Associated Electric Energy.
1.27.	Net Seasonal Capability.
1.28.	Operating Work.
1.29.	Owners.
1.30.	Representative.
1.31.	Trimble County General Plant Facilities.
1.32.	Trimble County Plant.
1.33.	Trimble County Site.
1.34.	Trimble County Unit 1.
1.35.	Uniform System Of Accounts.
ARTICLE 2. OWNERSHIP INTEREST AND SALE
2.1.	Ownership Interests.
2.2.	Sale Of Property Included In Trimble County Unit 1.
2.3.	Release From Lien Of Louisville’s Indenture.
2.4.	Closing.
2.5.	Additional Generating Units.
2.6.	Modification Of Existing Property.
ARTICLE 3. PURCHASE, PAYMENT, AND CLOSING

i

3.1.	Purchase Price.
3.2.	Closing.
3.2.1.	Date And Place.
3.2.2.	Delivery Of Documents, Certificates, And Funds.
3.3.	Special Conditions.
3.4.	Continued Marketing By Louisville.
3.5.	Termination If Closing Does-Not Occur.
ARTICLE 4. REPRESENTATIONS, WARRANTIES, AND MUTUAL COVENANTS
4.1.	IMPA Representations.
4.1.1.	IMPA Organization
4.1.2.	Authority Relative To This Agreement.
4.1.3.	Approvals And Consents.
4.1.4.	Legal Proceedings.
4.2.	Louisville Representations.
4.2.1.	Louisville Organization.
4.2.2.	Authority Relative To This Agreement.
4.2.3.	Approvals And Consents.
4.2.4.	Legal Title.
4.2.5.	Condition Of Plant And Equipment.
4.2.6.	Legal Proceedings.
ARTICLE 5. OPERATING ARRANGEMENTS
5.1.	Authority For Operation And Management.
5.2.	Scheduling And Dispatching Of Electric Generation
5.3.	Economic Replacement Of Trimble County Unit 1 Energy.
5.4.	Electric Capability And Energy Entitlements.
5.5.	Operations Management.
5.5.1.	Administration Of Operating Work And Incremental Capital Assets.
5.5.2.	Purchasing Necessary Goods And Services.
5.5.3.	Procurement Of Fuel.
5.5.4.	Expenditure Of Funds.
5.5.5.	Insurance.
5.5.6.	Enforcement Of Claims Against Third Parties.
5.5.7.	Processing Claims By Third Parties.
5.5.8.	Delivery Of Operating data.
5.6.	Environmental Laws and Regulations.
5.7.	Indemnification Of Environmental Fines And Penalties.
ARTICLE 6. INCREMENTAL CAPITAL ASSETS
6.1.	Determination Of Need.
6.2.	Estimate Of Costs.
6.3.	Responsibility For Costs.
ARTICLE 7. COMPENSATION
7.1.	Monthly Charges.
7.1.1.	Fuel/Reactant Operation Expense.
7.2.	Fixed Operation And Maintenance Expenses.
7.2.1.	Non-Fuel Operating Component.
7.2.2.	Working Capital Component.

ii

7.2.3.	Transmission Charge.
ARTICLE 8. BILLING, PAYMENTS, AND RECORDS
8.1.	Billings By Louisville.
8.2.	Payments By IMPA Or Louisville.
8.3.	Records.
ARTICLE 9. TRANSMISSION SERVICE
ARTICLE 10. BACKUP POWER AND ENERGY
10.1.	From Louisville.
10.2.	From Third Parties.
10.3.	Effective Date Of Backup Power Provision.
ARTICLE 11. GENERAL CONDITIONS
11.1.	Cooperation.
11.2.	Approvals.
11.3.	Access.
11.4.	Conditions Precedent To Louisville’s Obligations Hereunder.
11.4.1.	Accuracy Of IMPA’s Representations And Warranties.
11.4.2.	Capability Of Performance By IMPA.
11.4.3.	Opinion Of Counsel For IMPA.
11.4.4.	Payment Of Funds By IMPA.
11.5.	Conditions Precedent To IMPA’s Obligations Hereunder.
11.5.1.	Accuracy Of Louisville’s Representations And Warranties.
11.5.2.	Opinion of Counsel for Louisville.
11.5.3.	Opinion Of Counsel For Louisville.
11.6.	Conditions Precedent To The Respective Obligations Of The Parties.
11.7.	Release From Louisville’s Indenture(s).
11.8.	Amendments.
11.9.	Limited Warranty.
11.10.	No Agency Or Third Party Beneficiary
ARTICLE 12. TAXES
12.1.	Management Of Tax Matters.
12.1.1.	Louisville’s Responsibility
12.1.2.	IMPA’s Responsibility.
12.1.3.	Cooperation.
12.2.	Sharing Of Taxes And Related Payments
12.3.	Payment Of Title Taxes And Fees
12.4.	Exclusion Of Income Taxes
12.5.	Non-creation Of Taxable Entity
ARTICLE 13. INSURANCE
13.1.	Procurement Of Insurance.
13.1.1.	Sharing Of Insurance Costs.
13.1.2.	IMPA Named As Insured.
13.1.3.	Procurement Of Additional Insurance For IMPA.
13.1.4.	Sharing Of Refunds From Insurance Premiums.
13.1.5.	Sharing Of Insurance Proceeds
13.2.	Destruction.
13.2.1.	Damage Or Destruction Fully Covered By Insurance

iii

13.2.2.	Damage Or Destruction Not Fully Covered By Insurance.
ARTICLE 14. PARTITION OF OR TRANSFER OF INTEREST IN TRIMBLE COUNTY UNIT 1
14.1.	Special Nature Of Trimble County Unit 1 . Waiver Of Right Of Partition.
14.2.	Transfer Of Ownership Interests To Third Parties.
14.2.1.	Conditions Of Transfer
14.2.2.	Further Conditions Of Transfer
14.2.3.	Non-applicability Of Certain Provisions
14.3.	Transfer Of Associated Rights And Interests
ARTICLE 15. RIGHT OF FIRST REFUSAL
ARTICLE 16. ASSIGNMENT
16.1.	Limitation Of Assignability.
16.2.	Successors And Assigns.
ARTICLE 17. LIABILITY AND DEFAULT
17.1.	Liability To Third Parties.
17.2.	Liability Between The Parties.
17.3.	Indemnification.
17.4.	Nature And Survival Of Representations And Warranties.
17.5.	Default.
17.5.1.	Events of Default.
17.5.2.	Curing Default In Regard To Paying Money.
17.5.3.	Curing Default For Other Than Failure To Pay Money
17.5.4.	Non-Applicability Of Cure Provisions
17.5.5.	Appointment Of A Receiver.
17.5.6.	Additional Obligations.
17.5.7.	Waivers
17.5.8.	Legal And Other costs.
17.6.	Force Majeure
ARTICLE 18. ADMINISTRATION
18.1.	Coordination Committee.
18.2.	Membership.
18.3.	Meetings.
18.4.	Functions
18.5.	Records
18.6.	Expenses.
18.7.	Conduct
ARTICLE 19. DISAGREEMENT
19.1.	Consultation.
19.2.	Disagreement.
19.2.1.	Arbitration.
ARTICLE 20. REMEDIES
20.1.	All Remedies . Setoff.
20.2.	Injunctive Relief.
20.3.	No Remedy Exclusive.
20.4.	Failure To Participate In Incremental Capital Assets.
ARTICLE 21. MISCELLANEOUS

iv

21.1.	Governing Law.
21.2.	Notice To Parties.
21.3.	Article Headings Not To Affect Meaning.
21.4.	Counterparts.
21.5.	Time.
21.6.	Severability.
21.7.	Integration.
21.8.	Computation Of Time.
21.9.	Waiver.
21.10.	Equal Opportunity Clause.
21.11.	Non-Segregated Facilities.
21.12.	Condemnation.
ARTICLE 22. TERM AND TERMINATION
22.1.	Termination.
22.2.	Retirement Of Property.
22.3.	Retirement Costs.

v

AGREEMENT

This Agreement, dated February 1, 1993, between Louisville Gas and Electric Company (“Louisville” or a “Party”), a Kentucky corporation, and Indiana Municipal Power Agency (“IMPA” or a “Party”), a body corporate and politic and a political subdivision of the State of Indiana, collectively (the “Parties”).

WHEREAS, IMPA is an agency composed of numerous municipally-owned electric systems, and is empowered, among other things, to plan, finance, develop, own and operated projects to supply electric power and energy on a collective basis for the present and future needs of its members; and

WHEREAS, Louisville is a regulated public utility and owns and operates facilities for the generation, transmission, and distribution of electric power and energy in the Commonwealth of Kentucky, and

WHEREAS, IMPA owns and operates facilities for the generation and transmission of electric power and energy to provide electric power and energy to its members in the State of Indiana, and

WHEREAS, Louisville is the owner of the Trimble County Plant, consisting of Trimble County Unit 1, the Trimble County General Plant Facilities, and the Trimble County Site, of which Illinois Municipal Electric Agency (“IMEA”) owns an undivided 12.12 percent interest in Trimble County Unit 1; and

WHEREAS, Louisville and IMPA are entering into this Agreement to establish (a) the respective ownership interests of the Parties in Trimble County Unit 1, and (b) the respective obligations and rights of the Parties with respect to the operation and maintenance of Trimble County Unit 1.

NOW, THEREFORE, in consideration of the premises and of the mutual covenants herein set forth, and subject to the terms and conditions herein set forth, the Parties agree as follows:

1

ARTICLE 1.
DEFINITIONS

1.1.Agreed Rate.

Two (2) percent per annum above the published prime commercial lending rate established from time to time by Chase Manhattan Bank, N.A., New York, New York.

1.2.Agreement.

This Participation Agreement between Louisville and IMPA dated as of February 1, 1993.

1.3.Available.

The state in which a unit is capable of providing service regardless of the capacity level that can be provided.

1.4.Capacity Factor.

The ratio of the actual net electric energy generated by Trimble County Unit 1 in a period of time to the maximum net electric energy that could be generated by the same unit in the same period of time if such unit operated uninterrupted at its Net Seasonal Capability rating.

1.5.Closing.

The delivery of documents and certificates and the payment of money as provided in Article 3.

1.6.Commercial Operation Date.

December 23, 1990, the date on which Trimble County Unit 1 was determined by Louisville to be reliable as a source of electric capacity and energy.

1.7.Construction Work.

All engineering, design, contract preparation, purchasing (of equipment, materials, and supplies), construction, supervision, expediting, inspection, accounting, testing and start-up for the Trimble County Plant and preparation of operating and equipment manuals, quality assurance manuals, emergency action plans, all reports required by regulatory authorities and the conduct of hearings and all other activities incidental to obtaining requisite permits, licenses, and certificates for the construction and operation of the Trimble County Plant prior to the Commercial Operation Date of Trimble County Unit 1 in accordance with Electric Plant Instruction No. 3, Components of Construction Cost, Uniform System of Accounts. Construction Work, as used in

2

Article 15 hereof, shall refer to the categories of costs and expenses set forth above, which relate to the unit to be constructed referenced in Article 15.

1.8.Coordination Committee.

The committee established pursuant to Article 18 hereof.

1.9.Delivery Points.

The interconnection points of Louisville’s system with the Joint Transmission System and with any other utility or utilities with which IMPA has contracted for transmission service to transmit power from Louisville to IMPA.

1.10.Effective Date.

The date on which Closing occurs pursuant to Article 3 of this Agreement.

1.11.Electric Capability.

Megawatts (MW) of electric demand.

1.12.Electric Energy.

Megawatt-hours (MWH) of electric energy.

1.13.Electric Capability And Energy.

Electric Capability and associated Electric Energy.

1.14.Electric Capability And Energy Entitlement.

The percentage of the Net Electric Generating Capability and Associated Electric Energy of Trimble County Unit 1 to which Louisville or IMPA, as the case may be, is entitled under Article 5.4 of this Agreement.

1.15.Execution Date.

The date upon which the Parties entered into this Agreement, which appears at the beginning of this Agreement.

1.16.Fixed Operation and Maintenance Expenses.

The Fixed Operation and Maintenance Expenses are calculated as the sum of the following expenses as they relate to the operation ~ and maintenance of Trimble County Unit 1, Trimble County General Plant Facilities (as such pertain to Trimble County Unit 1), and the Trimble County Site (as such pertain to Trimble County Unit 1), as recorded in Louisville’s accounting records under the Uniform System of Accounts:

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(a)Operation supervision and engineering (Account 500).

(b)Steam expenses (Account 502 except for scrubber reactant).

(c)Electric expenses (Account 505).

(d)Miscellaneous steam power expenses (Account 506).

(e)Rents (Account 507).

(f)Maintenance supervision and engineering (Account 510).

(g)Maintenance of structures (Account 511).

(h)Maintenance of boiler plant (Account 512).

(i)Maintenance of electric plant (Account 513).

(j)Maintenance of miscellaneous steam plant (Account 514).

1.17.Force Majeure.

Any cause beyond the reasonable control of a Party, and which by reasonable efforts the Party is unable to overcome, including without limitation, the following: acts of God; strikes, lockouts, or other industrial disturbances; acts of public enemies; acts, orders, or absence of necessary orders and permits of any kind, from the government of the United States, or from the government of one of its sovereign states, or any of their departments, agencies, or officials, or from any civil or military authority insurrections; riots; delay in transportation; unforeseen soil conditions; equipment, material, supplies, labor, or machinery shortages; epidemics; landslides; lightning; earthquakes; fire; hurricanes; tornadoes; storms; floods; washouts; drought; arrest; war; civil disturbances; explosions; breakage or accident to machinery, equipment, transmission lines, pipes, or canals; partial or entire failure of utility service; breach of contract by any supplier, contractor, subcontractor, laborer, or materialman; sabotage; injunction; blight; famine; blockage; quarantine; or any other similar or dissimilar cause or event not reasonably within the control of the Party. Force Majeure does not include financial inability to pay, and shall not, in any event, excuse payment for obligations already incurred hereunder at the time such claim is made.

1.18.Fuel/Reactant Operation Expenses.

The fuel/reactant operation expenses are calculated as the sum of the following expenses as recorded in Louisville’s accounting records under the Uniform System of Accounts:

(a)Fuel (Account 501).

(b)Scrubber reactant expenses in Steam Expenses (Account 502).

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1.19.Good Utility Practice.

At a particular time, any of the practices, methods, and acts, which, in the exercise of reasonable judgment in the light of the facts known at the time the decision was made, would have been expected to accomplish the desired result or further the possibility of achieving such result, at a reasonable cost consistent with reliability and safety and all applicable laws and governmental rules, regulations, and orders pertaining to Trimble County Plant. Such practices, methods, and acts shall include, but shall not be limited to, any of the practices, methods, and acts engaged in or approved by other members of the electric utility industry at, prior to, or subsequent to the time the decision was made. Good Utility Practice is not intended to be limited to the optimum practice, method, or act to the exclusion of all others, but rather to be a number of possible practices, methods, or acts.

1.20.Incremental Capital Assets.

All assets of the Trimble County Plant pertaining to the use of Trimble County Unit 1 which are not included in Accounts 101, 106, or 107 of the Uniform System of Accounts on the Commercial Operation Date, or such later date as is necessary to complete the original construction of Trimble County Unit 1 and the Trimble County General Plant Facilities and the Trimble County Site as they pertain to Trimble County Unit 1.

1.21.Insurance.

Policies of insurance of any type procured and maintained, including any self-insurance maintained by Louisville or jointly by the Parties, relating to Trimble County Unit I on and after its Commercial Operation Date, in accordance with Article 13 hereof.

1.22.Interconnection Agreement.

The agreement between Louisville and IMPA as such agreement may be amended from time to time, providing for purchases and sales of electric capacity and energy between the Parties, and specifying the rates to be charged for such transactions as filed with the Federal Energy Regulatory Commission (“FERC”).

1.23.Internal Load.

Aggregate electric demand of all retail consumers served, including those served under non-firm (interruptible) rate schedules, and associated transmission and distribution losses.

1.24.Joint Transmission System.

The Joint Transmission System shall be the transmission facilities owned and jointly operated by PSI Energy (“PSI”), IMPA, and Wabash Valley Power Association

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(“WVPA”) functionally serving as transmission facilities, all having an operating voltage of 69,000 volts or higher.

1.25.Louisville’s Cost Of Capital.

An amount determined by the weighted average cost of capital based on Louisville’s capital structure at the end of the prior month, including short-term debt, long-term debt, preferred stock, and common equity. The cost rates for short-term debt, long-term debt, and preferred stock shall be determined based on the average embedded cost at the end of the prior month. The cost of common equity shall be based upon the rate of return on common equity allowed by the Kentucky Public Service Commission, or its successor, by its Order in Louisville’s last general rate case.

1.26.Net Electric Generating Capability And Associated Electric Energy.

The maximum continuous ability of Trimble County Unit 1 to produce power which can be available at any particular time, less any power required for operation of the unit, taking into account all relevant conditions and factors affecting or limiting the capability of the unit to produce power at such time, including, without limitation, availability and quality of fuel, any mechanical or other defects, breakdowns, malfunctions, or environmental and permit limitations then existing.

1.27.Net Seasonal Capability.

The steady hourly output, less auxiliary usage, which generating equipment is expected to produce under ideal conditions, and adjusted due to seasonal variations in ambient temperature, condensing water availability and/or temperature, reservoir levels, scheduled reservoir discharge, river flow head, etc. Such output shall be declared on a monthly basis and determined according to testing criteria defined in the East Central Area Reliability Coordination Agreement’s Document No. 4 entitled, “Criteria and Method For the Uniform Rating of Generating Equipment.”

1.28.Operating Work.

All engineering, contract preparation, purchasing, repair, supervision, recruitment, training, expediting, inspection, accounting, testing, protection, operating, management, maintenance, and all other work and activities associated with operating Trimble County Unit 1 which are not included in Construction Work, but excluding all work on any Incremental Capital Assets.

1.29.Owners.

The Parties and Illinois Municipal Electric Agency (“IMEA”).

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1.30.Representative.

A Party’s member of the Coordination Committee as set forth in Article 18 of this Agreement.

1.31.Trimble County General Plant Facilities.

Facilities on the Trimble County Site, excluding those in which an interest is conveyed as identified in Appendix B, which are necessary for use by IMPA with respect to its proportional ownership of Trimble County Unit 1, for which IMPA shall have a non-exclusive license, substantially in the form shown in Appendix C, to use consistent with its ownership interests. Ownership in such facilities is not conveyed to IMPA hereunder. Such facilities are identified in Appendix C hereto, and in the absence of other units at the Trimble County Site, all such facilities shall be considered to pertain to the use of Trimble County Unit 1.

1.32.Trimble County Plant.

The generating plant at a site along the Ohio River at river mile 571.4 at Wises Landing in Trimble County, Kentucky, which plant currently consists of a single coal-fired steam electric generating unit of 495,000 kilowatts, and includes Trimble County Unit 1, the Trimble County General Plant Facilities, and the Trimble County Site.

1.33.Trimble County Site.

Certain land, consisting of approximately 2,200 acres, and certain rights in land owned by Louisville, including the land on which Trimble County Unit 1 is constructed and including that portion of the land underlying Trimble County Unit 1 which is conveyed to IMPA under Article 2.2 hereof. In the absence of other units at the Trimble County Site, all such land shall be considered to pertain to the use of Trimble County Unit 1.

1.34.Trimble County Unit 1.

The 495,000 kilowatt unit, located at the Trimble County Site, consisting of the property set forth in Appendix B hereto.

1.35.Uniform System Of Accounts.

The FERC’s “Uniform System of Accounts Prescribed for Public Utilities and Licensees (Class A and Class B)”, in effect as of the date of this Agreement, as such Uniform System of Accounts may be modified from time to time. References in this Agreement to any specific account number shall mean the account number in effect as of the Execution Date of this Agreement or any successor account.

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ARTICLE 2.

OWNERSHIP INTEREST AND SALE

2.1.Ownership Interests.

Trimble County Unit 1 shall be owned by the Parties and IMEA as tenants in common. The undivided ownership interest of each Party and IMEA in Trimble County Unit 1 shall be free and clear of the lien of any indenture of mortgage, deed of trust, bond resolution, or other instrument (hereinafter called “indenture”) establishing a lien upon some or all of the property of the other Party or IMEA. The undivided ownership interests of Louisville, IMPA, and IMEA in Trimble County Unit 1 shall be 75.00, 12.88, and 12.12 percent, respectively. Trimble County Unit 1 is more specifically described in Appendix B attached hereto which may be revised from time to time in accordance with this Agreement. Louisville shall retain full ownership of the Trimble County General Plant Facilities as described in Appendix C attached hereto, subject to the non- exclusive licenses granted to IMPA hereunder and to IMEA. Louisville shall retain full ownership of the Trimble County Site except for that portion of the Trimble County Site conveyed to IMPA pursuant to Article 2.2, and except for that portion of the Trimble County Site previously conveyed to IMEA, and subject to the reciprocal easements over the Trimble County Site conveyed to and by Louisville, IMPA, and IMEA.

It is recognized by the Parties, however, that various items of property included in Trimble County Unit 1 may be leased from others in lieu of purchasing such items of property. Nothing in this Agreement shall preclude the Parties from leasing such items of property. Such leased property shall be held by the Owners in an undivided ownership as tenants in common.

2.2.Sale Of Property Included In Trimble County Unit 1.

At the Closing, from its ownership share of Trimble County Unit i~ Louisville shall sell and convey to IMPA, and IMPA shall purchase from Louisville, a 12.88 percent undivided ownership interest as a tenant in common in Trimble County Unit 1 as set forth in Appendix B. Upon such conveyance, the undivided ownership shares of Trimble County Unit 1 shall be as follow: Louisville.  75 percent, IMPA- 12.88 percent, IMEA- 12.12 percent. Such conveyance shall be by Bill of Sale substantially in the form shown in Appendix A attached hereto and made a part hereof

From its ownership share of the Trimble County Site, Louisville shall further convey to IMPA by general warranty deed, substantially in the form shown in Appendix E, an undivided ownership interest in 12.88 percent of that portion of the real estate constituting the Trimble County Site underlying Trimble County Unit 1 to be held is tenants in common. Upon such conveyance, the undivided ownership shares of that portion of the real estate constituting the Trimble County Site underlying Trimble County Unit 1 shall be as follow: Louisville 75 percent, IMPA 12.88 percent, IMEA . 12.12 percent.

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Louisville shall further grant to IMPA a nonexclusive license, substantially in the form shown in Appendix C, to use the Trimble County General Plant Facilities and a non-exclusive easement, substantially in the form shown in Appendix F, over that portion of the Trimble County Site owned by Louisville, as the Trimble County- General Plant Facilities and the Trimble County Site pertain to IMPA’s use of Trimble County Unit 1. IMPA shall rant to Louisville and any other Owners of Trimble County Unit 1 an easement, substantially in the form shown in Appendix G, over IMPA’s interest in the Trimble County Site.

Further, after the Closing, the Parties shall execute such other instruments, if any, as may be necessary or appropriate to confirm the respective rights and interests of the Parties hereunder and to maintain their respective ownership interests.

2.3.Release From Lien Of Louisville’s Indenture.

At the Closing, Louisville shall furnish to IMPA a properly executed release of that portion of the property being conveyed to IMPA at the Closing from the lien of any and all indentures, applicable to Louisville’s property conveyed to IMPA hereunder.

2.4.Closing.

The Closing shall be held in accordance with the provisions of Article 3.

2.5.Additional Generating Units.

Subject to Article 15 hereof, Louisville shall have the sole and exclusive right to own, install, enlarge, modify, and operate any generating unit or units other than Trimble County Unit 1, as well as any other facility, including necessary appurtenances thereto, on the Trimble County Site, provided that such other units or facilities shall not be so installed, enlarged, modified, and operated, as the case may be, as to unreasonably impair (economically or operationally) the operation of Trimble County Unit 1.

2.6.Modification Of Existing Property.

Subject to the approval of the Coordination Committee, and in accordance with the terms of this Agreement, Louisville shall have the right to use, enlarge, modify, or relocate any facilities installed as a part of Trimble County Unit 1 or Trimble County General Plant Facilities in connection with the installation, enlargement, modification, or operation, as the case may be, of such other unit or units or facilities provided that:

(a)such use, enlargement, modification, or relocation of Trimble County Unit 1 facilities or Trimble County General Plant Facilities shall not unreasonably impair (economically or operationally) the operation of Trimble County Unit 1; and

(b)the cost of such use, enlargement, modification, or relocation of Trimble County Unit 1 facilities or Trimble County General Plant Facilities, in connection with such other unit or units or facilities, shall be borne by Louisville (except that if such use,

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enlargement, modification, or relocation of Trimble County Unit 1 facilities or Trimble County General Plant Facilities is in connection with the installation, enlargement, modification, or operation of any additional unit or units or facilities which are owned or to be owned by the Owners in common, then the cost of such use, enlargement, modification, or relocation of said Trimble County Unit 1 facilities or Trimble County General Plant Facilities shall be shared by the Owners in proportion to their respective ownership interests in such additional unit or units or facilities); and

(c)such action shall not enlarge or diminish the respective ownership interests of the Owners in any part of Trimble County Unit 1; and

(d)such action shall not enlarge or diminish the Owner’s respective obligations to share in the costs of any part of Trimble County Unit 1; and

(e)further, where modification of existing property and rights requires revisions to existing documents setting forth the respective rights and interests of the Owners, or where new conveyances are required to properly effectuate the modifications to property and rights made hereunder, the Parties agree to cooperate to promptly execute and deliver such documents.

ARTICLE 3.

PURCHASE, PAYMENT, AND CLOSING

3.1.Purchase Price.

The purchase price for IMPA’s 12.88 percent undivided ownership interest in Trimble County Unit 1 shall be $91,075,617 (the amount established pursuant to the Option Agreement of December 30, 1991, between the Parties) (the “Purchase Price”), paid at Closing in immediately available funds.

3.2.Closing.

3.2.1.Date And Place.

Provided that the conditions in Article 3.3 hereof have been fulfilled, Closing shall occur at such location as may be selected by the Parties, on such date as set forth in the Option Agreement, or on such other date as mutually agreed upon by the Parties.

3.2.2.Delivery Of Documents, Certificates, And Funds.

At the Closing, Louisville shall deliver to IMPA the Bill of Sale, deed, easement, license, the release of any and all indentures of the ownership interest in Trimble County Unit 1 to be conveyed to IMPA hereunder at the Closing from the lien of such indenture(s), and all certificates and evidences of authorizations, approvals, and documents as provided for herein. IMPA shall deliver to Louisville the Purchase Price at the Closing, in immediately available funds and all certificates, easements, and evidences of authorizations, approvals, and documents as provided for herein.

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3.3.Special Conditions.

IMPA’s obligation to complete the transaction as contemplated in this Article shall be subject to the fulfillment, prior to Closing, of each of the following special conditions:

(a)IMPA shall have exercised the Option set forth in the Option Agreement of December 30, 1991, between the Parties.

(b)IMPA shall have obtained entitlement or contractual authority and any required regulatory approval for the use of such transmission system or systems as are necessary to transmit power and energy from the Delivery Points to IMPA.

(c)IMPA shall have issued and sold tax-exempt bonds sufficient in amount to pay for any and all sums due to be paid by IMPA to Louisville at Closing.

(d)The Parties shall have executed the Interconnection Agreement.

IMPA shall endeavor in good faith to fulfill each of these special conditions as soon as reasonably practicable. In the event IMPA determines that it cannot fulfill the sale of tax-exempt bonds, it shall notify Louisville. IMPA shall regularly report on its progress to Louisville.

Should IMPA fail or be unable to close by Closing due to its inability to meet these special conditions, the Agreement shall terminate without penalty to either Party.

3.4.Continued Marketing By Louisville.

IMPA understands and acknowledges that Louisville may incur certain costs should Closing not occur. IMPA shall undertake to keep Louisville promptly and adequately informed of its efforts and progress toward satisfying the conditions set forth in Article 3.3 above, as well as any event, situation, or occurrence which could adversely affect IMPA’s ability or decision to close as scheduled. In this regard, IMPA shall regularly, no less frequently than monthly, report on its efforts and progress, and shall declare its intention to close as scheduled.

Except as otherwise specifically provided in this Agreement, IMPA also understands and acknowledges that Louisville, in its sole discretion, reserves the right to sell prior to and subsequent to the Closing, all or any portion of Trimble County Unit 1 or the output thereof, including the Trimble County General Plant Facilities and the Trimble County Site, other than the portion to be conveyed to IMPA hereunder.

3.5.Termination If Closing Does-Not Occur.

Should Closing not occur at the time set for Closing under Article 3.2.1 due to any default or failure to satisfy any condition or contingency by IMPA, this Agreement shall immediately terminate with Louisville having no further obligation or liability

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hereunder. In such event, the Unit Power Purchase Agreement of December 30, 1991, between Louisville and IMPA, shall remain in full force and effect.

ARTICLE 4.

REPRESENTATIONS, WARRANTIES, AND MUTUAL COVENANTS

4.1.IMPA Representations.

IMPA hereby represents and warrants to Louisville as of the Closing as follows:

4.1.1.IMPA Organization.

IMPA is a body corporate and politic and a political subdivision of the State of Indiana, duly organized, validly existing and in good standing under the laws of the State of Indiana, has the full power, legal capacity, and authority to enter into this Agreement and related agreements, and to carry out the transactions contemplated by this Agreement, and to carry on its business as it is now being conducted and as it is contemplated to be conducted after the Closing. IMPA has delivered to Louisville on or before the Closing a true and complete copy of its Statement of Organization and By-Laws as amended to date.

4.1.2.Authority Relative To This Agreement.

The execution, delivery, and performance by IMPA of this Agreement have been duly authorized by all necessary corporate action on the part of IMPA, and the execution, delivery, and performance by IMPA of the Interconnection Agreement will have been duly authorized by all necessary corporate action on the part of IMPA prior to Closing. The execution, delivery, and performance by IMPA of this Agreement and the Interconnection Agreement do not contravene any law, or any governmental rule, regulation, or order, applicable to IMPA or its properties, or the Statement of Organization or By-Laws of IMPA and do not and will not contravene the provisions of, or constitute a default under, any indenture, mortgage, contract, or other instrument to which IMPA is a party or by which IMPA is bound, and this Agreement constitutes a legal, valid, and binding obligation of IMPA, enforceable in accordance with its terms, except as limited by applicable bankruptcy, insolvency, reorganization, or similar laws at the time in effect.

4.1.3.Approvals And Consents.

Any consent or approval of, giving of notice to, registration with, or taking of any other action by any state, federal, or other governmental commission, court, agency, or regulatory authority including, without limitation, the Indiana Utility Regulatory Commission, the Federal Energy Regulatory Commission, and the Securities and Exchange Commission, in connection with the execution, delivery, and performance of this Agreement and the Interconnection Agreement required to be obtained by IMPA on or before the Closing will have been obtained by the Closing.

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4.1.4.Legal Proceedings.

There is no materially adverse legal action, suit, arbitration, governmental investigation, or other legal or administrative proceeding, or any order, decree, or judgment in progress, pending or in effect, or to the knowledge of IMPA threatened against or relating to IMPA in connection with or relating to the transactions contemplated by this Agreement, and IMPA does not know or have any reason to be aware of any basis for the same.

4.2.Louisville Representations.

Louisville hereby represents and warrants to IMPA as of the Closing as follows:

4.2.1.Louisville Organization.

Louisville is a corporation duly organized and validly existing under the laws of the Commonwealth of Kentucky, and has corporate power to carry on its business as it is now being conducted and as it is contemplated to be conducted after the Closing. Louisville has delivered to IMPA on or before the Closing a true and complete copy of its Articles of Incorporation and By-Laws as amended to date.

4.2.2.Authority Relative To This Agreement.

The execution, delivery, and performance by Louisville of this Agreement and the Interconnection Agreement have been duly authorized, or by Closing, will be ratified by all necessary corporate action on the part of Louisville, do not contravene any law, or any governmental rule, regulation, or order, applicable to Louisville or its properties, or the Articles of Incorporation or By-Laws of Louisville and do not and will not contravene the provisions of, or constitute a default under, any indenture, mortgage, contract, or other instrument to which Louisville is a party or by which Louisville is bound, and this Agreement constitutes a legal, valid, and binding obligation of Louisville, enforceable in accordance with its terms, except as limited by applicable bankruptcy, insolvency, reorganization, or similar laws at the time in effect.

4.2.3.Approvals And Consents.

Any consent or approval of, giving of notice to, registration with, or taking of any other action by any state, federal, or other governmental commission, court, agency, or regulatory authority including, without limitation, the Kentucky Public Service Commission, the Federal Energy Regulatory Commission, and the Securities and Exchange Commission, in connection with the execution, delivery, and performance of this Agreement and the Interconnection Agreement required to be obtained by Louisville on or before the Closing will have been obtained by the Closing.

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4.2.4.Legal Title.

Louisville has good and marketable title to the assets conveyed to IMPA free and clear of all liens, except easements, restrictions, . and stipulations of record, and the lien of current real property taxes not delinquent, subject to the rights of IMEA which owns a 12.12 percent undivided interest as tenants in common to the assets conveyed. Before Closing, Louisville shall provide to IMPA a list of all easements, restrictions, and stipulations of record. Within thirty days thereafter, IMPA shall consent to such easements, restrictions, and stipulations of record, which consent shall not unreasonably be withheld, if it reasonably determines that the easements, restrictions, and stipulations of record will not adversely affect the marketability of said title. Should IMPA reasonably refuse to consent to any such easement, restriction, or stipulation of record, Louisville, at its option and at its expense, may (I) remove such easement, restriction, or stipulation of record from the property, or (ii) remove the limiting language “except easements, restrictions, or stipulations of record’ from the representation of good and marketable title in this Article, and convey good and marketable title subject only to current taxes not delinquent, or (iii) purchase standard form title insurance with respect to the real estate to be conveyed herein in favor of IMPA, which title insurance, if obtainable, will insure over any easement, restriction, or stipulation of record adversely affecting marketability of said title, reasonably objected to by IMPA. If title insurance is obtained under this provision in favor of IMPA, Louisville shall be responsible for the cost of such title insurance covering the real estate conveyed to IMPA, up to a maximum of $5,000.00, with IMPA being responsible for the cost of such insurance above $5,000.00.

4.2.5.Condition Of Plant And Equipment.

As of the Closing Date, the portions of the Trimble County Plant pertaining to the original construction of Trimble County Unit 1 are capable of full operation, according to their design and specifications, except as set forth in a certificate in the form attached as Appendix D hereto.

4.2.6.Legal Proceedings.

There is no materially adverse legal action, suit, arbitration, governmental investigation, or other legal or administrative proceeding, or any order, decree, or judgment in progress, pending or in effect, or to the knowledge of Louisville threatened against or relating to Louisville in connection with or relating to the transactions contemplated by this Agreement, and Louisville does not know or have any reason to be aware of any basis for the same.

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ARTICLE 5.

OPERATING ARRANGEMENTS

5.1.Authority For Operation And Management.

Subject to any directions from the Coordination Committee, Louisville shall have sole authority to manage, control, maintain, and operate (including dispatch) Trimble County Unit 1 for the benefit of each Party’s respective interest and Louisville shall take all steps which it deems necessary or appropriate for that purpose. Louisville shall discharge such authority in accordance with Good Utility Practice and the other provisions of this Agreement.

5.2.Scheduling And Dispatching Of Electric Generation

When Trimble County Unit 1 is~ Available, IMPA shall have the right to schedule, subject to the scheduling provisions herein, all, or any part that is five (5) megawatts or greater, of its Electric Capability and Energy Entitlement in Trimble County Unit 1 (or as such Electric Capability and Energy Entitlement may be modified herein); provided, that during periods when Trimble County Unit 1 is being operated at minimum generation, IMPA, unless otherwise agreed to by Louisville, shall not schedule less than what its Electric Capability and Energy Entitlement in Trimble County Unit 1 would have been had the Net Electric Generating Capability and Associated Electric Energy of Trimble County Unit 1 been restricted to such minimum generation. Louisville shall promptly notify IMPA of any significant change in the Net Electric Generating Capability of Trimble County Unit 1. As used in this paragraph, the term “minimum generation’ means the Net Electric Generating Capability level below which Trimble County Unit 1 cannot operate in a stable manner and must be shut down.

Louisville and IMPA shall each be entitled to dispose of their respective Electric Capability and Energy Entitlement through scheduled transactions with other electric utilities in a manner consistent with Good Utility Practice.

IMPA shall schedule Electric Energy to be delivered pursuant to this Agreement prior to 12:00 noon E.S.T. of the day prior to delivery; provided that, for Saturdays, Sundays, Mondays, and holidays recognized by Louisville, IMPA shall schedule the Electric Energy prior to 12:00 noon E.S.T. on the last normal work day prior to the weekend or holiday. : Schedules shall be subject to change after 12:00 noon E.S.T. of the applicable day on which the schedule is submitted only upon the mutual consent of the Parties, but Louisville shall make every reasonable effort to accommodate changes in the schedules. All schedules shall be in increments of whole megawatts; provided, that where IMPA’s full entitlement is requested and available, IMPA shall be entitled to its full Electric Capability and Energy Entitlement. Prior to each calendar year, Louisville shall notify IMPA of the holidays to be recognized by Louisville for that year. In the event Louisville fails to provide such notice, the said holidays shall be the same as for the prior year.

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Louisville will provide to IMPA, by 9:00 A.M. each day, the Net Electric Generating Capability expected for the next day; provided that, for Saturdays, Sundays, Mondays, and holidays recognized by Louisville, Louisville will provide this information on the last normal work day prior to the weekend or holiday. At all times, Louisville will immediately inform IMPS of any increase or decrease in unit Net Electric Generating Capability that will or may occur, or any suspected conditions that could cause such change.

At any time IMPA is not requesting, for any reason, including a claim by 1MPA of Force Majeure, the maximum amount of Net Electric Generating Capability available to it from Trimble County Unit 1, Louisville shall have the right to utilize, for its own use, ail or any part of the Electric Energy associated with such unused Net Electric Generating Capability. When so utilized, the energy consumed by Louisville shall be referred to as “Banked Energy.’ At a future date, IMPA shall be entitled to request, in accordance with the scheduling provisions of Article 5.2, Electric Energy associated with the Net Electric Generating Capability from Louisville’s portion of Trimble County Unit 1 in an amount equal to all or any portion of the then-current balance of Banked Energy due to IMPA. Louisville shall be obligated to supply the requested amount of IMPA’s Banked Energy unless, pursuant to guidelines established by the Coordination Committee, conditions are unsuitable to do so. Pursuant to procedures and guidelines established by the Coordination Committee, the balance of Banked Energy owed to IMPA shall be periodically returned to zero. When Banked Energy is used by Louisville or returned to IMPA, the Fuel/Reactant Operation Expenses for the Electric Energy associated therewith shall be assumed by the Party using such Electric Energy. Louisville shall maintain records adequate to determine the transactions related to, and balances of, Banked Energy.

Louisville shall submit to IMPA, as far in advance as practicable, schedules showing the expected time and duration for maintenance and repair outages of Trimble County Unit 1. Louisville will adjust such schedules to accommodate IMPA’s operating needs, where, in Louisville’s sole judgment, it is practicable to do so, consistent with Good Utility Practice. Should IMPA desire a schedule for maintenance and repair outages which Louisville believes is impracticable, IMPA shall be entitled to raise the scheduling issue with the Coordination Committee.

5.3.Economic Replacement Of Trimble County Unit 1 Energy.

In the event, and only in the event, Louisville voluntarily ceases to operate Trimble County Unit 1 or reduces the output therefrom solely because of the availability of Electric Energy to Louisville from other sources, the cost of which is projected to be lower than what the cost of Fuel/Reactant Operation Expenses of Electric Energy generated by Trimble County Unit 1 would be during the period of such cessation in operation, Louisville shall make available to IMPA replacement Electric Energy from such other sources during the period of such cessation in operation. The amount of such replacement Electric Energy to be made available to IMPA during such period shall be the amount of Electric Energy requested by IMPA during such period, but not in excess

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of the amount to which IMPA would have been entitled during such period had the operation of Trimble County Unit 1 not ceased or the output not been reduced. The per kilowatt-hour cost of such replacement Electric Energy shall be the per kilowatt-hour cost incurred by Louisville for such replacement Electric Energy obtained from such other sources during such period.

5.4.Electric Capability And Energy Entitlements.

Louisville and IMPA shall be entitled to the Net Electric Generating Capability and Associated Electric Energy of Trimble County Unit 1 in proportion to their respective ownership interests in Trimble County Unit 1; however, the Net Electric Generating Capability of Trimble County Unit 1 shall not exceed the applicable Net Seasonal Capability of Trimble County Unit 1, except under criteria as may be established by the Coordination Committee.  These entitlements shall begin at the time of Closing and continue until Trimble County Unit 1 ceases to be used for the generation of Electric Energy.

5.5.Operations Management.

5.5.1.Administration Of Operating Work And Incremental Capital Assets.

Louisville shall perform all work, or execute, and enforce (including any renegotiation and settlement) all contracts, contractual obligations and arrangements for Operating Work and Incremental Capital Assets, including, without limitation, any and all warranties on equipment, facilities, materials, and services furnished pursuant to any such contracts. Warranties and claims arising under this Article shall be administered in accordance with the provisions of Article 5.5.6 of this Agreement.

5.5.2.Purchasing Necessary Goods And Services.

Louisville shall purchase and procure, through and from any source it may select, the equipment, apparatus, machinery, tools, services, materials and supplies, and emergency spare parts necessary for the performance of Operating Work and Incremental Capital Assets.

5.5.3.Procurement Of Fuel.

At all times, Louisville shall make necessary and reasonable efforts to maintain an adequate supply of fuel. At IMPA’s request, Louisville will receive bids or proposals from suppliers of Indiana coal who wish to be considered for purchases of coal supplies for Trimble County Unit 1. Louisville shall have no obligation to consider any particular bid or proposal, which in Louisville’s sole judgment, is not in the best interest of the Owners when considering price, reliability, quality, and other relevant terms, conditions, and considerations. IMPA may elect from time to time to purchase fuel directly for use in connection with its share of Trimble County Unit I pursuant to fuel specifications and procedures for delivery, handling, testing, and use as approved by Louisville. In such case, IMPA shall contract and pay directly to suppliers and billing under this Agreement

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shall be adjusted appropriately. IMPA shall be responsible for all its costs resulting from these separate fuel procurement activities, and for any additional costs imposed upon the other Owners where such additional costs result from activities not performed by or under the direct supervision of Louisville pursuant to this Agreement.

5.5.4.Expenditure Of Funds.

Louisville shall expend funds in accordance with the terms and conditions of this Agreement.

5.5.5.Insurance.

Louisville shall arrange for the placement and maintenance of Insurance, as provided herein in Article 13.

5.5.6.Enforcement Of Claims Against Third Parties.

Louisville shall present and prosecute known claims against third parties, including but not limited to claims against insurers and indemnitors providing Insurance or indemnities with respect to any loss of or damage to any property of Trimble County Unit 1, or the Trimble County General Plant Facilities or the Trimble County Site as they pertain to Trimble County Unit 1, or any interest of the Owners pertaining thereto, and with respect to any liability of Louisville or IMPA to third parties covered by Insurance or indemnity agreement. To the extent that such loss, damage, or liability is not covered by Insurance or by any indemnity agreement, Louisville shall present and prosecute claims therefor against any parties who may be liable therefor. Nothing herein shall require Louisville to initiate, present, or prosecute any claim which, in its sole judgment, is without sufficient merit to warrant such enforcement, or otherwise is inconsistent with the Owners’ general business interests. Nothing herein shall require Louisville to invoke any certain type of enforcement procedure, or to seek, or to continue to seek, enforcement of any claim, when in Louisville’s sole judgment, the Owners’ general business interests are better served by settling or withdrawing such claim. If any such claim by the Owners is in excess of $250,000 in amount, Louisville shall notify IMPA of the existence and nature of such claim and shall also notify IMPA if and when any settlement of such claim is accomplished by Louisville.

In the event that Louisville should fail or refuse to diligently prosecute any claim, nothing herein contained shall prevent IMPA from prosecuting such claim or demand in its own name, to the extent of, and as such claim or demand affects, its interest.  IMPA may intervene in any suit on a claim pursuant to this Article as an additional plaintiff or defendant to assert or defend as to its respective ownership interest and rights. Cost and monies net of reasonable expenses recovered are to be shared by the Owners in proportion to their respective ownership interests in Trimble County Unit 1.

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5.5.7.Processing Claims By Third Parties.

Louisville shall investigate, adjust, defend, and settle claims by third parties against IMPA and Louisville, arising out of or attributable to Operating Work or Incremental Capital Assets, or the past or future performance or nonperformance of the obligations and duties of either IMPS or Louisville under or pursuant to this Agreement, including but not limited to any claim resulting from death or injury to persons or damage to property, when such claims are not covered by valid and collectible Insurance carried by Louisville or IMPA and, whenever and to the extent reasonable, present and prosecute claims against any third party, including insurers, for any costs, losses, and damages incurred in connection’ with such claims. If tiny such claim against IMPS and Louisville is in excess of $50,000 in amount and is not covered by valid and collectible Insurance carried by Louisville or 1MPA, Louisville shall notify IMPA of the existence and nature of such claim and shall also notify IMPA if and when any settlement of such claim is accomplished by Louisville. Settlement of claims in excess of $1,000,000 shall be reported to and approved by the Coordination Committee.

In the event that Louisville should fail or refuse to diligently defend any claim, nothing herein contained shall prevent IMPA from defending such claim or demand in its own name, to the extent of, and as such claim or demand affects, its interest. IMPA may intervene in any suit on a claim pursuant to this Article as an additional party to defend as to its respective ownership interests and rights in Trimble County Unit 1.

5.5.8.Delivery Of Operating data.

As promptly as practicable after the end of each month, Louisville shall render to IMPA a statement setting forth appropriate operating data as may be needed for reports and records.

5.6.Environmental Laws and Regulations.

Each Party shall be responsible for its own share of any obligations, costs, or burdens of any kind, resulting from any federal, state, or local environmental law, regulation, or requirement, as amended from time to time. Similarly, each Party shall be entitled to its share, on a pro rata ownership basis, of any rights, credits, or entitlements associated with such law, regulation, or requirement. Louisville’s obligation to produce generation from IMPA’s share of Thimble County Unit 1, as well as Louisville’s obligation to produce backup power and energy as set forth in Article 10 hereof, shall be conditioned upon IMPA’s compliance with such laws, regulations, or requirements as set forth in this Article, and IMPA’s possession of required environmental allowances needed for such generation. In the event IMPA’s rights, credits, or entitlements from Trimble County Unit 1 or other sources are not sufficient to allow the desired level of generation from IMPA’s share of Trimble County Unit 1 or the production of backup power and energy, Louisville shall provide such rights, credits, or entitlements to IMPA upon IMPA’s request and after consultation with IMPA concerning the availability and cost of such rights, credits, or entitlements. Louisville shall have no obligation, however,

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to provide such rights, credits, or entitlements where such rights, credits, or entitlements are required for use by Louisville to serve its Internal Load, or any firm off-system sales existing prior to any request for backup power and energy, or backup power and energy to IMEA. Louisville may satisfy this obligation, at its option, by supplying such rights, credits, or entitlements from its own system, or by purchasing from other sources. Such obligation shall be limited to the rights, credits, or entitlements necessary to operate IMPA’s portion of Trimble County Unit 1 at the lower of an 80 percent Capacity Factor or IMPA’s actual Capacity Factor, and shall apply only to the excess requirements above the rights, credits, or entitlements obtained by IMPA as a result of its ownership Interest in Trimble County Unit 1 or from other sources.

IMPA shall compensate Louisville for providing such allowances for IMPA’s Trimble County Unit 1 generation, as well as for allowances for backup power and energy sold by Louisville to IMPA under Article 10 hereof, at a price equal to the fair market value of such allowances, as such value may change from time to time. Fair market value and procedures for billing and payment will be determined according to criteria set forth by the Coordination Committee; provided that, fair market value shall not be less than

Louisville’s actual cost of providing or obtaining such allowances. In lieu of compensation under this Article for such allowances, where agreed by the Parties, such compensation may be accounted for by inclusion in the price for backup power pursuant to the Interconnection Agreement between the Parties.

5.7.Indemnification Of Environmental Fines And Penalties.

Louisville will indemnify IMPA against administrative fines and civil penalties arising out of the operation of the Trimble County Plant imposed for violations of applicable environmental laws and regulations, resulting from acts of Louisville as plant operator. Exclusions from this special indemnification shall include operation and maintenance costs which might be incurred as a result of environmental laws and regulations, Incremental Capital Assets incurred in environmental compliance, occurrences from acts of third parties or from equipment failure or malfunction, remedial measures imposed by administrative agencies for environmental purposes, or reimbursement of response costs under Comprehensive Environmental Response Compensation And Liability Act (CERCLA) and K.R.S. Chapter 224, and subsequent amendments thereof, and any subsequently enacted legislation covering the same subject matter as CERCLA and K.R.S. Chapter 224, or to any claims of personal injury or property damage.

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ARTICLE 6.

INCREMENTAL CAPITAL ASSETS

6.1.Determination Of Need.

The Coordination Committee shall approve Incremental Capital Assets expected to cost over $250,000. Louisville shall have the authority to make all decisions with respect to Incremental Capital Assets expected to cost $250,000 or less. Emergency expenditures for Incremental Capital Assets which total in excess of $250,000 in any calendar year shall be submitted to the Coordination Committee for ratification.

6.2.Estimate Of Costs.

Prior to beginning of work on any Incremental Capital Asset which Louisville expects to cost more than $1,000,000, such estimate shall be furnished by Louisville in reasonable detail to IMPA for use by it in anticipating its financial requirements. Such estimate shall be subject to revision periodically to reflect more current information on such Incremental Capital Asset.

6.3.Responsibility For Costs.

Subsequent to the Closing, the costs of each Incremental Capital Asset shall be borne by Louisville and IMPA in proportion to their respective percentage ownership interests in Trimble County Unit 1. The amount incurred for Incremental Capital Assets during each month shall be included in the monthly billings provided for in Article 8.L IMPA’s share of all Incremental Capital Assets booked during January 1993, shall not be reflected in the Purchase Price stated in Article 3.1 hereof, but shall be included instead in the first monthly billing to IMPA following Closing.

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ARTICLE 7.

COMPENSATION

7.1.Monthly Charges.

The Owners will share all costs associated with Trimble County Unit 1, and with the Thimble County General Plant Facilities and the Trimble County Site as they pertain to Trimble County Unit 1. These costs are set forth below in five components for billing and accounting purposes. The Parties intend that these components incorporate all costs which are or could be associated with Trimble County Unit 1, and with the Trimble County General Plant Facilities and the Trimble County Site as they pertain to Trimble County Unit 1. Should, however, any item or category of costs not fall within the technical definitions of any of the five components, the Parties agree to adjust the billing components so as to include such item or category.

Starting at the Closing, IMPA shall pay a monthly amount equal to the sum of the five components delineated in Articles 7.1.1, 7.1.2, 7.1.3, 7.1.4, and 7.1.5, as provided for in Article 8.1.

7.1.1.Fuel/Reactant Operation Expense.

All Fuel/Reactant Operation Expenses of Trimble County Unit 1 will be prorated to the Parties, according to the net Electric Energy consumed by each Party as compared to the total net energy generated by Trimble County Unit 1.

For purposes of this Article, Fuel/Reactant Operation Expenses shall be allocated to IMPA on the basis of its loss-adjusted net Electric Energy during the applicable month. This loss-adjusted net Electric Energy shall be calculated by multiplying IMPA’s actual Trimble County Unit 1 net Electric Energy during the month by a loss factor to be determined using load flow studies or other mutually acceptable analyses which, at the request of either Party, but not more frequently than once every two years, shall be reviewed and shall be adjusted as appropriate.

7.2.Fixed Operation And Maintenance Expenses.

A Fixed Operation and Maintenance Expenses component shall be shared by the Parties in proportion to their respective percentage ownership interest in Trimble County Unit 1.

7.2.1.Non-Fuel Operating Component.

A non-fuel operating component shall be shared by the Parties in proportion to their respective percentage ownership interest in Trimble County Unit 1, calculated monthly as the sum of the following four items as they relate to Trimble County Unit 1, and the Trimble County General Plant Facilities and the Trimble County Site as they pertain to Trimble County Unit I:

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(a) Taxes other than federal and state income taxes (Account 408.1), except that those categories of taxes, or payments in lieu thereof, that are directly billed to IMPA by the taxing authority and paid by IMPA, shall not be included in this item.

(b) Administrative and general expenses (Accounts 920-935) as recorded in Louisville’s accounting records under the Uniform System of Accounts.

(c) Lease payments which result from a third-party financed Incremental Capital Asset.

(d) Penalties (Account 426.3), except for those environmental penalties against which Louisville is indemnifying IMPA under Article 5.7 hereof.

7.2.2.Working Capital Component.

A working capital component shall be shared by the Parties in proportion to their respective percentage ownership interests in Trimble County Unit 1. This component is comprised of the items listed below, to the extent that each of these items relates to Trimble County Unit 1, the Trimble County General Plant Facilities (as they pertain to Trimble County Unit 1), and the Trimble County Site (as it pertains to Trimble County Unit 1). This component shall be calculated by multiplying the beginning monthly balances of the items by Louisville’s Cost of Capital as “grossed up’ for federal and state income taxes.

(a)Fuel stocks (Account 151).

(b)Fuel stock expenses undistributed (Account 152).

(c)Plant materials and operating supplies (Account 154).

(d)Stores expense undistributed (Account 163).

(e)Prepayments (Account 165).

(f)Miscellaneous deferred debits (Account 186).

7.2.3.Transmission Charge.

A transmission charge to cover transmission of the Electric Energy from Trimble County Unit 1 to the Delivery Points shall be assessed according to the Trimble County schedule contained in the Interconnection Agreement. Such schedule may be changed by Louisville from time to time based on revised cost information, but shall continue to be calculated throughout the duration of this Agreement according to the same cost of service methodology as was used to support the initial schedule. Should FERC at any time decline to accept a rate based on such methodology, a new rate shall be calculated using approved methodology as close as possible to the initial methodology such that the original intent of the Parties in pricing this service shall be maintained.

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ARTICLE 8.

BILLING, PAYMENTS, AND RECORDS

8.1.Billings By Louisville.

As promptly as practicable, but not more than twelve working days after the end of each calendar month during the term of this Agreement, Louisville shall prepare and send to IMPA a statement, in such detail and with such segregations as may be needed for operating and accounting records, to indicate monthly amounts due under the provisions of this Agreement.

8.2.Payments By IMPA Or Louisville.

All bills under Article 8.1 for amounts owed by IMPA to Louisville shall be due and payable on the tenth working day following the invoice date. Amounts owing by either Party to the other under the Interconnection Agreement or under the provisions of this Agreement, other than under Article 8.1, shall be settled in accordance with the procedures set forth in such provisions as give rise to the obligations. Interest on unpaid amounts shall accrue at the Agreed Rate from the date due until the date upon which payment is made. Payments by IMPA to Louisville based on over billing by

Louisville shall bear interest at the Agreed Rate beginning on the thirty. first day after receipt by Louisville and running until such amount is repaid or credited by Louisville. Unless otherwise agreed upon, a calendar month shall be the standard monthly period for the purpose of settlements under this Agreement.

Should either Party withhold payment of any contested amount, the procedure for resolution of disputes under Article 19 shall be invoked automatically. Non-payment of any amount contested in good faith by either Party shall not constitute a default under Article 17 prior to completion of the disagreement procedures under Article 19. The unpaid Party may contend a default exist! under Article 17, if payment continues to be withheld following completion of the disagreement procedures under Article 19 including arbitration if both Parties have elected to arbitrate.

8.3.Records.

Louisville will record its accounting information in accordance with generally accepted accounting principles, as modified by the requirements or permitted practices of applicable regulatory authorities. For the purpose of this Agreement, all account references are to the Uniform System of Accounts. In the event of any changes in FERC’s accounting procedures which might result in different charges than those contemplated by the Agreement, the Parties will agree upon the appropriate changes to the Agreement to achieve the original intent of the Parties, unless otherwise mutually agreed by the Parties.

The Parties shall keep and maintain such records as may be necessary or useful in carrying out this Agreement. Each Party shall keep such records as may be needed to

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afford a clear history of all transactions under this Agreement and make copies of such records available to the other Party upon request. Each Party shall have the right during normal business hours, but no more often than once each calendar year, at its own expense, to audit, or cause independent certified public accountants of its choice to audit, the accounting and other records relating to transactions under this Agreement and shall have the right to make copies of records as necessary; provided that IMPA shall not be permitted to retain documents which Louisville has designated as confidential or proprietary where to do so would make such records open records under any applicable “open records’ or “public records’ procedure or regulation. All such records shall be considered confidential and proprietary business records of the Party that generated the particular record in question. Neither Party shall make use of records of the other Party without the express written consent of such Party, except for disclosure or use which is permitted by this Agreement or where required by lawful authority, or for purposes of litigation or alternative dispute resolution procedures.

ARTICLE 9.

TRANSMISSION SERVICE

All Electric Energy delivered under this Agreement shall be of the character commonly known as three-phase sixty-hertz energy, and shall be considered as being delivered at Louisville’s Delivery Points.

Obtaining transmission service for transmitting power under this Agreement from Louisville’s Delivery Points shall be the sole responsibility of IMPA. If an electric system or systems, which is not part of the electric systems owned by either of the Parties, is used to transmit the Net Electric Energy from Louisville’s delivery Points to IMPA, the cost of such transmission service shall be paid by IMPA. Losses which are incurred through such third party transmission(s) shall be assumed by IMPA.

ARTICLE 10.

BACKUP POWER AND ENERGY

10.1.From Louisville.

In any hour of any month that the Net Electric Generating Capability of Trimble County Unit 1 is less than the Net Seasonal Capability, IMPA shall have the option to request from Louisville backup power and energy from Louisville’s other generating resources. For IMPA to receive this backup power and energy, both of the following conditions must be met:

(a)the amount of backup power and energy shall not exceed an amount equal to IMPA’s share (based on its percentage ownership interest in Trimble County Unit 1) of such reduction from Net Seasonal Capability; and

(b)the amount of backup power and energy requested, as limited by (a) above, is available from Louisville’s other generating resources and is not required to serve Louisville’s Internal Load, to honor any firm commitments made by Louisville for

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off-system sales existing prior to any particular request for backup power and energy, or to provide backup power and energy to IMEA.

Compensation for backup power and energy will correspond to the demand and energy rate provisions of the Backup Power service schedule contained in the Interconnection Agreement in effect at the time backup energy is delivered. Nothing in this Agreement shall require Louisville to construct, acquire, expand, or maintain new or existing generating resources for the purpose of supplying backup power to IMPA pursuant to this Agreement.

10.2.From Third Parties.

In the event Louisville is unable to provide backup power and energy from its own system, Louisville will, at the request of IMPA, make its best effort to purchase backup power and energy from another party for resale to IMPA. Louisville will bill IMPA for such purchased backup power and energy according to the terms for such third party transactions contained in the Backup Power service schedule contained in the Interconnection Agreement in effect at the time backup energy is delivered.

10.3.Effective Date Of Backup Power Provision.

The provisions of this Article 10 will become effective at the time of Closing.

ARTICLE 11.

GENERAL CONDITIONS

11.1.Cooperation.

Louisville and IMPA shall cooperate with each other and provide information as may be necessary to facilitate, among other things, the filing of applications for authorizations, permits, licenses, or financing and the execution of such other documents as may be reasonably necessary to carry out the provisions of this Agreement, subject to reasonable protections necessary to preserve each Party’s confidential or proprietary information.

11.2.Approvals.

The Parties shall use their best efforts to obtain as quickly as possible all requisite governmental, regulatory, and judicial approvals, where applicable, of the consummation of the transactions contemplated herein. To the extent any provision of this Agreement prevents IMPA from receiving a favorable tax ruling authorizing the issuance by IMPA of tax-exempt bonds to finance the purchase contemplated herein, the Parties agree to negotiate In good faith and cooperate with each other so as to effectuate sale of such bonds; provided that the foregoing shall not be construed so as to impose any economic detriment or burden or unreasonable condition or obligation on Louisville or any other Owner of Trimble County Unit 1.

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11.3.Access.

Official representatives of IMPA and their designees, including IMPA’s bond trustee, shall have the right, upon sufficient advance notice to Louisville, to enter upon the Trimble County Site subject to all safety, insurance, and industrial security requirements and the need for efficient operation of Trimble County Unit 1.

11.4.Conditions Precedent To Louisville’s Obligations Hereunder.

All obligations of Louisville under this Agreement are subject to the fulfillment, prior to or at the Closing, of each of the conditions (or the waiver in writing of such conditions by Louisville) that are delineated in Articles 11.4.1 through 11.4.4 and IMPA shall exert its best efforts to cause each such condition to be fulfilled.

11.4.1.Accuracy Of IMPA’s Representations And Warranties.

Louisville and IMPA shall not have discovered any material error, misstatement, or omission in the representations and warranties made by IMPA in this Agreement.

11.4.2.Capability Of Performance By IMPA.

IMPA’s representations and warranties contained in this Agreement shall be deemed to have been made again at and as of the time of the Closing and shall then be true in all material respects; IMPA shall have performed and complied with all agreements, covenants, and conditions required by this Agreement to be performed or complied with by it prior to or at the Closing Louisville shall have been furnished with certificates signed by the principal officer of IMPA, dated the date of the Closing, certifying ii form and substance satisfactory to Louisville to the fulfillment of the foregoing conditions and to the further effect that there are no actions, suits, or proceedings pending or, to such officer’s knowledge, threatened against or affecting IMPA before any court or administrative body or agency which would materially adversely affect the ability of IMPA to perform its obligations under this Agreement.

11.4.3.Opinion Of Counsel For IMPA.

Louisville shall have been furnished with an opinion of counsel for IMPA, which counsel shall be satisfactory to Louisville, in form and substance satisfactory to Louisville, dated the date of the Closing, to the effect that:

(a)IMPA is a body corporate and politic and a political subdivision of the State of Indiana, duly organized and validly existing in good standing under the laws of the State of Indiana and has the corporate power, legal capacity, and authority to carry on its business as presently conducted and to enter into and perform its obligations under this Agreement; and

(b)The execution, delivery, and performance by IMPA of this Agreement have been duly authorized by all necessary corporate action on the part of IMPA, do not

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contravene any law, or any governmental rule, regulation, or order, applicable to IMPA or its properties, or the Statement of Organization, or the By-Laws of IMPA and do not and will not contravene the provisions of, or constitute a default under, any indenture, mortgage, contract, or other instrument to which IMPA is a party or by which IMPA is bound; and

(c)This Agreement has been duly executed and delivered by IMPA and constitutes the legal, valid, and binding obligation of IMPA enforceable in accordance with its respective terms, except as limited by applicable bankruptcy, insolvency, reorganization, or similar laws at the time in effect; and

(d)There are no actions, suits, or proceedings pending or, to such counsel’s knowledge, threatened against or affecting IMPA before any court or administrative body or agency which might materially adversely affect the ability of IMPA to perform its obligations under this Agreement; and

(e)Any consent or approval of, giving of notice to, registration with, or taking of any other action by, any state, federal, or other governmental commission, agency, regulatory authority, or court, where applicable, including, without limitation, the Indiana Utility Regulatory Commission, the Federal Energy Regulatory Commission, and the Securities and Exchange Commission, in connection with the execution, delivery, and performance of this Agreement required to be obtained by IMPA on or before the Closing has been obtained.

11.4.4.Payment Of Funds By IMPA.

The portion of the Purchase Price required to be paid by IMPA to Louisville at the Closing shall be paid in immediately available funds.

11.5.Conditions Precedent To IMPA’s Obligations Hereunder.

All obligations of IMPA under this Agreement are subject to the fulfillment, prior to or at the Closing, of each of the conditions (or the waiver in writing of such conditions by IMPA) that are delineated in Article 11.5.1 through 11.5.3 and Louisville shall exert its best efforts to cause each such condition to be fulfilled.

11.5.1.Accuracy Of Louisville’s Representations And Warranties.

IMPA and Louisville shall not have discovered any material error, misstatement, or omission in the representations and warranties made by Louisville in this Agreement.

11.5.2.Opinion of Counsel for Louisville.

Louisville’s representations and warranties contained in this Agreement shall be deemed to have been made again at and as of the time of the Closing and shall then be true in all material respects. Louisville shall have performed and complied with all agreements, covenants, and conditions required by this Agreement to be performed or

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complied with it prior to or at the Closing IMPA shall have been furnished with certificates signed by the President or a Vice President of Louisville, dated the date of the Closing, certifying in form and substance satisfactory to IMPA, to the fulfillment of the foregoing conditions and to the further effect that there are no actions, suits, or proceedings pending or, to such officer’s knowledge, threatened against or affecting Louisville before any court or administrative body or agency which would adversely affect the ability of Louisville to perform its obligations under this Agreement.

11.5.3.Opinion Of Counsel For Louisville.

IMPA shall have been furnished with an opinion of counsel for Louisville, which may include counsel employed directly by Louisville as well as Louisville’s outside counsel, which counsel shall be satisfactory to IMPA, in form and substance satisfactory to IMPA, dated the date of the Closing, to the effect that:

(a)Louisville is a corporation duly organized and validly existing under the laws of the Commonwealth of Kentucky and has the corporate power and authority to carry on its business as presently conducted and to enter into and perform its obligations under this Agreement; and

(b)The execution, delivery, and performance by Louisville of this Agreement have been duly authorized by all necessary corporate action on the part of Louisville, does not contravene any law, or any governmental rule, regulation, or order applicable to Louisville or its properties, or the Articles of Incorporation or By-Laws of Louisville, and do not and will not contravene the provisions of, or constitute a default under, any indenture, mortgage, contract, or other instrument to which Louisville is a party or by which Louisville is bound; and

(c)The documents executed by Louisville in connection with the Closing have been duly authorized, executed, and delivered by Louisville; and

(d)There are no actions, suits, or proceedings pending or, to such counsel’s knowledge, threatened against or affecting Louisville before any court or administrative body or agency which would materially adversely affect the ability of Louisville to perform its obligations under this Agreement; and

(e)Any consent or approval of, giving of notice to, registration with or taking of any other action by, any state, federal, or other governmental commission, agency, or regulatory authority, including, without limitation, the Kentucky Public Service Commission, the Federal Energy Regulatory Commission, and the Securities and Exchange Commission, in connection with the execution, delivery, and performance of this Agreement required to be obtained by Louisville on or before the Closing has been obtained; and

(f)Louisville’s conveyance to IMPA in fee simple with covenant of general warranty of a 12.88 percent undivided ownership interest as tenants in common in the real estate set forth in Appendix E, is free and clear from all encumbrances, except

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easements, restrictions, and stipulations of record, taxes assessed and payable in the year of Closing and thereafter, and subject to the rights of IMEA which owns a 12.12 percent undivided interest as tenants in common, but such opinion will be inapplicable to matters not of record; and

(g)Louisville has paid all property taxes (other than sales or use or other transfer taxes, if applicable) which are assessed on the interests conveyed to IMPS hereunder, except for property taxes assessed and payable in the year of Closing.

11.6.Conditions Precedent To The Respective Obligations Of The Parties.

The respective obligations of Louisville and IMPS hereunder are, unless waived in writing by Louisville and IMPS prior to or at the Closing, subject to the special conditions in Article 3.3 hereof and the additional condition that all governmental, judicial, and regulatory approvals of the execution, delivery, and performance of this Agreement required to be obtained by Louisville and IMPS on or before the Closing shall have been obtained, including all governmental, judicial, and regulatory approvals necessary for the issuance of IMPA’s tax-exempt revenue bonds in an aggregate principal amount sufficient to pay for any and all sums due to be paid by IMPS to Louisville at Closing.

11.7.Release From Louisville’s Indenture(s).

Louisville shall have obtained the releases from any and all indentures of the ownership interest in Trimble County Unit 1 to be conveyed to IMPS hereunder at the Closing from the lien of such indenture.

11.8.Amendments.

This Agreement may be amended only by a written instrument duly executed by the Parties. When so amended, the Parties shall execute a conformed copy of the Agreement, which conformed copy shall contain all amendments to the Agreement and shall thereafter govern the Parties.

11.9.Limited Warranty.

Louisville warrants that as of the Closing Date hereof, except as set forth in Appendix D, it knows of no defects in the original design or construction of Trimble County Unit 1 or the Trimble County General Plant Facilities, and that such facilities were designed for the generation and production of electric power and energy Should this Agreement become effective prior to full completion of such facilities, Louisville shall complete the original construction of such facilities at its expense.

Louisville also warrants that for the time periods set forth below, Trimble County Unit I and the Trimble County General Plant Facilities shall be free of defects in materials or workmanship in the design and construction of such facilities: (a) if the Closing Date occurs by or before December 31, 1993, the limited warranty period shall

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be ninety days from the Closing Date; (b) if the Closing Date occurs by or before December 31, 1994, but after December 31, 1993, the limited warranty period shall be sixty days from the Closing Date; (c) if the Closing Date occurs by or before December 31, 1995, but after December 31, 1994, the limited warranty period shall be thirty days from the Closing Date; (d) if the Closing Date occurs after December 31, 1995, there shall be no limited warranty. Defects that are discovered during this warranty period, shall be repaired at Louisville’s expense. OTHER THAN FOR THIS EXPRESS WARRANTY, IMPA’S OWNERSHIP INTEREST IN TRIMBLE COUNTY UNIT 1 IS TO BE SOLD “AS IS” AND “WHERE IS”. LOUISVILLE MAKES NO OTHER REPRESENTATION OR WARRANTY WHATSOEVER IN THIS AGREEMENT, EXPRESSED, IMPLIED, OR STATUTORY, INCLUDING, WITHOUT LIMITATION, ANY REPRESENTATION OR WARRANTY AS TO THE VALUE, QUANTITY, CONDITION, SALABILITY, OBSOLESCENCE, MERCHANTABILITY, FITNESS, OR SUITABILITY FOR USE OR WORKING ORDER OF ANY OF TRIMBLE COUNTY UNIT 1 INCLUDING THE TRIMBLE COUNTY GENERAL PLANT FACILITIES, NOR DOES LOUISVILLE REPRESENT OR WARRANT THAT THE USE OR OPERATION OF ANY SUCH FACILITIES WILL NOT VIOLATE PATENT, TRADEMARK, OR SERVICE MARK RIGHTS OF ANY THIRD PARTIES. THE PROVISIONS OF THIS ARTICLE 11.9 SHALL GOVERN OVER ANY CONFLICTING PROVISIONS OF THIS AGREEMENT.  Notwithstanding the foregoing, IMPA shall have the benefit, in proportion to its percentage ownership interest in Trimble County Unit 1, of all manufacturers’ and vendors’ warranties and all patent, trademark, and service mark rights running to Louisville in connection with Trimble County Unit 1 and the Trimble County General Plant Facilities as they pertain to Trimble County Unit 1; provided that Louisville shall have sole authority in decisions regarding the enforcement (including any renegotiation and settlement) of such warranties and patent, trademark, and service mark rights, subject to the rights of IMPA as set forth in Article 5.5.6 hereof.

11.10.No Agency Or Third Party Beneficiary

Nothing herein is intended to or shall create an agency whereby IMPA becomes an agent for Louisville in any relationship with any third party. This Agreement is solely between Louisville and IMPA and shall not be construed to create any third party beneficiary relationship with any other person or entity.

ARTICLE 12.

TAXES

12.1.Management Of Tax Matters.

12.1.1.Louisville’s Responsibility

Louisville shall have the responsibility for filing returns, making property tax declarations, paying, seeking official tax rulings or determinations, and other related functions pertaining to all taxes, payments in lieu of taxes, assessments, impositions,

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charges, and related costs of every kind and nature, ordinary or extraordinary, general or special, foreseen or unforeseen, settled or pending settlement, including, but not limited to, property, sales, use and payroll taxes, connected with or arising out of the construction, ownership, operation, maintenance, alteration, repair, rebuilding, use, or retirement of, and arising out of its ownership interest in, Trimble County Unit 1, the Trimble County General Plant Facilities, or any part thereof, which are or may be imposed on Louisville by any federal, state, county, municipal, local, interregional, or quasi~ governmental authority.

12.1.2.IMPA’s Responsibility.

IMPA shall have the responsibility for filing returns, making property tax declarations, paying, seeking official tax rulings or determinations, and other related functions, for which it assumes responsibility from and after Closing, pertaining to all taxes, payments in lieu of taxes, assessments, impositions, charges, and related costs of every kind and nature, ordinary or extraordinary, general or special, foreseen or unforeseen, settled or pending settlement, arising out of its 12.88 percent ownership interest in Trimble County Unit 1, including, but not limited to, property, sales, use, and payroll taxes, connected with or arising out of the construction, ownership, operation, maintenance, alteration, repair, rebuilding, use, or retirement of Trimble County Unit 1, the Trimble County General Plant Facilities, or any part thereof, which are or may be imposed on IMPA by any federal, state, county, municipal, local, interregional, or quasi-governmental authority (collectively, the “Taxes’).

12.1.3.Cooperation.

Louisville and IMPA will mutually cooperate and reasonably assist each other in meeting their respective tax obligations under this Agreement. IMPA shall, prior to filing any election, return, declaration, refund claim, request for ruling or determination, any pleading in any court or administrative proceeding, or any other document with any governmental authority relating to the Taxes (a “Tax Filing”) give Louisville seven business days prior written notice of such proposed filing, which notice shall include a copy of the Tax Filing. Louisville will advise IMPA in writing within three business days of the filing due date of any suggested changes which Louisville deems appropriate for the Tax Filing. IMPA is under no obligation to incorporate in the Tax Filing changes suggested by Louisville.

12.2.Sharing Of Taxes And Related Payments

All such taxes, payments in lieu of taxes, assessments, impositions, charges and related costs of Trimble County Unit 1, or the Trimble County General Plant Facilities or the Trimble County Site as they pertain to Trimble County Unit 1, shall be shared and borne by Louisville and IMPA in proportion to their respective percentage ownership interests in Trimble County Unit 1; provided, however, IMPA shall be entitled to the entire benefit to the extent of actual realization, of all exemptions from and reductions of taxes, including but not limited to property, sales, use, and payroll taxes, connected with

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or arising out of the ownership, operation, maintenance, alteration, repair, rebuilding, use, or retirement of Trimble County Unit 1 or any part thereof, which may be realized because of the provisions, if any, of the Constitutions (of the Commonwealth of Kentucky, the State of Indiana, and the United States of America), statutes, ordinances, rules, regulations, and laws applicable to IMPA and not Louisville.

The portion of such taxes, payments in lieu of taxes, assessments, impositions, charges and related costs that are to be borne by IMPA as set forth above in this Article 12.2 shall be billed to and paid by IMPA in accordance with Articles 7 and 8, as applicable, except for those taxes which are paid by IMPA directly to the taxing authority.

12.3.Payment Of Title Taxes And Fees

IMPA shall be responsible for all sales taxes, recording fees, and other taxes related to transfer of property, if any, incurred in connection with the conveyance(s) to IMPA by Louisville at Closing.

12.4.Exclusion Of Income Taxes

Notwithstanding the generality of Article 12.1 above, Louisville and IMPA agree that the foregoing provisions of this Article 12 shall not apply to any tax on or measured by income.

12.5.Non-creation Of Taxable Entity

Notwithstanding any other provision of this Agreement, Louisville and IMPA do not intend to create hereby at law any joint venture, partnership, association taxable as a corporation, or other entity for the conduct of any business for profit. Louisville and IMPA agree to elect under Section 76 1(a) of the Internal Revenue Code of 1986, as amended, to exclude the transactions created by this Agreement from the application of Subchapter K, Chapter 1 of the Code, and both Parties agree to revise the terms of this Agreement to the extent and in a manner necessary to permit such election.

ARTICLE 13.

INSURANCE

13.1.Procurement Of Insurance.

Except with regard to directors and officers liability insurance, Louisville shall maintain in force, for the benefit of Louisville and IMPA as their interests in Trimble County Unit 1, Trimble County General Plant Facilities, and the Trimble County Site shall appear, such available insurance and self-insurance as the Coordination Committee shall determine to be appropriate.

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13.1.1.Sharing Of Insurance Costs.

The costs of such insurance policies referenced to in Article 13.1 above shall be shared by the Parties in proportion to their respective percentage ownership interests in Trimble County Unit 1. IMPA shall also pay any additional premium that results from IMPA being named as an additional insured party on Louisville’s existing policies. IMPA shall bear responsibility for costs of and any losses incurred within the limits of any deductibles on policies of insurance. If IMPA elects to participate in self-insurance, as discussed in the following paragraph, the costs of claims and expenses for such self. insurance shall also be shared in proportion to the respective ownership interests in Trimble County Unit 1. IMPA’s share of such insurance and self-insurance costs shall be paid in accordance with Articles 7 and 8, as applicable.

With regard to the portion of any self-insurance for which IMPA is responsible, IMPA shall be entitled, at its option, to separately fund and administer a reserve account to fund all claims and expenses for which it is maintaining self-insurance. Any such separately maintained and administered fund shall be established, maintained, and administered according to policies and procedures approved by the Coordination Committee. Such fund will be a financial device for funding IMPA’s self-insurance obligation and will play no role in administering claims. Where IMPA establishes and maintains such an account,. the Coordination Committee will determine appropriate procedures and methodology for regularly billing for and recovering amounts due to be paid by IMPA to Louisville for such claims and expenses. Such procedures and methodology may include making adjustments to the billing and payment practices set forth in Article 7 and 8, as such Articles relate to IMPA’s self-insurance.

13.1.2.IMPA Named As Insured.

IMPA shall be named as an additional insured in such insurance policies. Louisville shall use its reasonable best efforts to have the insurance underwriters furnish IMPA with a Certificate of Insurance of each such insurance policy. In addition, Louisville shall use its reasonable best efforts to have each of such policies endorsed so as to provide that IMPA shall be given the same advance notice of cancellation or material change as is required to be given to Louisville. Loss or claim, if any, under such insurance policies shall be adjusted and settled by Louisville with the insurance underwriters in accordance with the third party claims procedure provided for in Article 5.5.6.

13.1.3.Procurement Of Additional Insurance For IMPA.

IMPA may obtain additional insurance beyond that provided for in this Article 13 to insure its ownership interest in Trimble County Unit 1 and the Trimble County Site and its rights with respect to the Trimble County General Plant Facilities at its cost. With respect to such additional insurance:

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(a)the proceeds from any claim arising through such additional insurance shall be disbursed to IMPA; and

(b)loss or claim, if any, under such additional insurance shall be adjusted and settled by IMPA with the insurance underwriters.

13.1.4.Sharing Of Refunds From Insurance Premiums.

Any refunds of insurance premiums shall be allocated among the Owners on the same basis as the premium payment allocation from which such refund was derived.

13.1.5.Sharing Of Insurance Proceeds

In the event of damage to property insured under this Article, it is agreed that the proceeds from insurance obtained by Louisville on behalf of the Owners shall be shared by the Owners on a pro rata basis based on their relative payments of insurance premiums covering the damaged property.

13.2.Destruction.

13.2.1.Damage Or Destruction Fully Covered By Insurance

If property insured under this Article or any portion thereof should be damaged or destroyed to the extent that the cost of repairs or reconstruction is estimated to be covered by the aggregate amount of insurance coverage (including any deductible) carried by Louisville for the benefit of Louisville and IMPA pursuant to Article 13 hereof, then Louisville shall cause such repairs or reconstruction to be made so that such property shall be restored to substantially the same general condition, character, or use as existed prior to such damage or destruction; provided however, if the estimate is wrong, and the insurance proceeds are insufficient to pay the cost of repair or reconstruction, the Owners shall share the cost not reimbursed by such insurance in proportion to their percentage ownership interests in Trimble County Unit 1.

13.2.2.Damage Or Destruction Not Fully Covered By Insurance.

If Trimble County Unit 1, the Trimble County General Plant Facilities or any portion thereof as they pertain to Trimble County Unit 1, should be damaged or destroyed to the extent that the cost of repairs or reconstruction is estimated to be more than the aggregate amount of insurance coverage (including any deductible) carried by Louisville for the benefit of Louisville and IMPA pursuant to Article 13 hereof and covering the cost of such repairs or reconstruction, then, if Louisville elects to repair and reconstruct such property and upon agreement of Louisville and IMPA, Louisville shall cause such repairs or reconstruction to be made and Louisville and IMPA shall share the costs of such repairs or reconstruction not reimbursed by such insurance, in proportion to their percentage ownership interests in Trimble County Unit 1; provided, however, that:

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(a)If IMPA elects not to join Louisville in repairing and reconstructing such property, then, at Louisville’s election, the Parties shall determine the monetary amount to be paid by Louisville to IMPA or by IMPA to Louisville, as provided for in paragraph (b) of this Article 13.2.2. Upon payment of such monetary amount by Louisville to IMPA or by IMPA to Louisville, as the case may require as set forth in said paragraph (b), IMPA shall transfer its ownership interest in Trimble County Unit 1 and the Trimble County Site, and its license to use the Trimble County General Plant Facilities, and its easement to the Trimble County Site, to Louisville free and clear of all liens and encumbrances, and this Agreement shall be deemed to have expired.

(b)The monetary amount to be paid to or received from IMPA pursuant to the provisions of paragraph (a) of this Article 13.2.2, shall be determined in accordance with the following equation:

P=W*X

Where:

P	=	the monetary amount to be paid to or received from IMPA. If P is positive, the monetary amount shall be paid to IMPA;and if P is negative, the monetary amount shall be received from IMPA.
W		IMPA’s percentage ownership interest in Trimble County Unit 1 before transfer of IMPA’s ownership interest in such property.
X	=	the fair market value (as determined by an independent appraiser selected jointly by the Parties) of (I) Trimble County Unit 1 and (ii) the Trimble County Site and the Trimble County General Plant Facilities as they pertain to IMPA’s use of Trimble

County Unit 1, at the time IMPA elects not to join Louisville in repairing and reconstructing Trimble County Unit 1 or the Trimble County General Plant Facilities. Fair market value shall be determined after taking into account all applicable costs of dismantling, demolishing, and removal of equipment, facilities, and structures; security; maintenance; disposing of debris; and any site work necessary to remove the effects of such damage or destruction. Fair market value may be a negative figure where appropriate.

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ARTICLE 14.
PARTITION OF OR TRANSFER OF INTEREST IN TRIMBLE COUNTY UNIT 1

14.1.Special Nature Of Trimble County Unit 1 . Waiver Of Right Of Partition.

The Parties recognize that Trimble County Unit 1 Is an Integral part of the facilities required to provide adequate service in their respective service territories and the service territories of other co owners of Trimble County Unit 1 and that the physical partition of Trimble County Unit 1 or any material part thereof would be Impossible and impractical and wholly Inconsistent with the purposes for which this Agreement Is made.

Each of the Parties agrees that It will not take any action, by judicial proceedings or otherwise, to partition Trimble County Unit 1, or that portion of the Trimble County Site conveyed by Louisville to IMPA pursuant to Article 2.2 hereof, or any part thereof, in any way, whether by partition In Mud or by sale and division of the proceeds thereof. Each of the Parties further waives the right of partition and the benefit of all statutory or common law that may now or hereafter authorize such partition of Trimble County Unit 1 or any part thereof, or that portion of the Trimble County Site conveyed by Louisville to IMPA pursuant to Article 2.2 hereof. In the event any such right of partition shall hereafter accrue, each Party shall from time to time upon the written request of the other Party execute and deliver such further Instruments as may be necessary to confirm the foregoing waiver and release of Its right to partition. The foregoing provisions of this Article 14.1 shall be binding upon and Inure to the benefit of the Parties, their respective successors and assigns, including mortgagees, receivers, trustees, or other representatives and their respective successors and assigns, and shall run with the land. Louisville agrees to Insert a similar covenant In any contract with another party which acquires an ownership Interest in Trimble County Unit 1, which covenant will be enforceable by IMPA.

14.2.Transfer Of Ownership Interests To Third Parties.

If either Party (“Transferring Party’) shall desire to transfer (whether by sale, conveyance, assignment, lease, or otherwise) all or any portion of Its ownership Interest In Trimble County Unit 1 In a bona fide arms length transaction to any unaffiliated third party or parties, the Transferring Party shall give the other Party written notice thereof, and any such transaction with such unaffiliated third party or parties shall not be consummated until the other Party has determined not to exercise Its right of first refusal, as set forth In this paragraph. Such written notice shall fully disclose the nature and terms of the proposed transaction and the Identity of the third party or parties Involved. Upon receipt of such written notice, the other Party shall have the first right to acquire the Transferring Party’s ownership Interest in Trimble County Unit 1 that the Transferring Party proposes to transfer to the third party or parties, upon the same terms and conditions which the Transferring Party proposes to make with the third party or parties; provided, however, that where Louisville Is the Transferring Party, IMPA’s right of first refusal shall be subordinate to a prior right of IMPA to acquire Louisville’s ownership Interest. Within ~0 days following receipt of such notice, the other Party shall give

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written notice to the Transferring Party stating whether or not It elects to acquire the Transferring Party’s undivided ownership Interest In Trimble County Unit 1 which the Transferring Party proposes to dispose of to the third party or parties; provided however, that where Louisville Is the Transferring Party, IMPA’s election to acquire such Interest shall be deemed to be of no effect If IMEA elects to acquire such Interest. If the Party elects to exercise Its rights to acquire such Interest, the Transferring Party, as soon as practicable, shall execute such Instruments as may be necessary and appropriate to effectuate such sale, conveyance, transfer, assignment, lease, or other disposition, as the case may be, to the other Party, free and clear of all liens, charges, and encumbrances for which the

Transferring Party, as between the Parties, is responsible, including the indenture(s) of the Transferring Party.

14.2.1.Conditions Of Transfer

If the other Party elects not to acquire the Transferring Party’s ownership interest in Trimble County Unit 1, as provided in the first paragraph of Article 14 2, the Transferring Party may consummate its proposed transaction with the third party or parties and dispose of such ownership interest to the third party or parties, provided, that such transaction is consummated within 240 days following receipt by the other Party of the written notice first referred to in the first paragraph of Article 14.2; and provided further, that the other Party has approved the prospective purchaser as suitable and desirable as a joint owner of Trimble County Unit 1, although such approval may not unreasonably be withheld and grounds for withholding such approval shall be limited to such factors as will materially, adversely affect the other Party’s interests hereunder; provided, however, that where Louisville is the Transferring Party, IMPA’s right to approve the prospective purchaser as suitable and desirable shall be limited to situations in which the proposed transfer reduces Louisville’s ownership interest in Trimble County Unit 1 to less than fifty (50) percent, or where such proposed transfer conveys, in whole or part, Louisville’s rights and obligations for operation of Trimble County Unit 1 under this Agreement to such third party or parties; and provided, further, that IMPA shall require (as a condition of or In connection with the sale, conveyance, transfer, assignment, lease, or other disposition, and for the benefit of the other Party) the third party or parties acquiring such ownership interest to assume and agree to be bound by the provisions of this Agreement and any amendments thereto, and In furtherance thereof the provisions of this Agreement shall be amended appropriately to reflect:

(a)the addition of such third party or parties as a party or parties to this Agreement; and

(b)the ownership Interest In Trimble County Unit 1 acquired by such third party or parties and the decreased ownership Interest in Trimble County Unit 1 of the Transferring Party; and

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(c)the rights, duties, and obligations of the Transferring Party and such third party or parties under this Agreement. Further, the Transferring Party hereby agrees to save the other Party harmless from and against all loss or liability which the other Party may Incur as a result of any failure by such third party or parties to fulfill its or their duties and obligations under this Agreement and any amendments thereto. In addition, the consummation of any transaction by the Transferring Party with a third party or parties shall not release the Transferring Party from any of its debts or liabilities to the other Party which, at the time of the consummation of the transaction, have accrued under this Agreement, and any amendments thereto, unless the Parties shall agree in writing to the contrary.

14.2.2.Further Conditions Of Transfer

The right of the Transferring Party to dispose of such ownership interest to a third party or parties, as set forth in the first paragraph of Article 14.2, is subject to the further condition that the other Party shall be given written notice thereof and shall have the further right of first refusal, to the same extent and by the same procedure described in the first paragraph of Article 14.2:

(a)if the Transferring Party shall undertake to consummate its proposed transaction at a time subsequent to 240 days following receipt of the written notice first referred to in the first paragraph of Article 14.2; or

(b)if the Transferring Party shall undertake to dispose of such ownership interest to a third party or parties other than those whose identity was disclosed in said notice; or

(c)if the Transferring Party shall undertake to dispose of such ownership interest upon different terms and conditions than were disclosed in said notice.

14.2.3.Non-applicability Of Certain Provisions

The provision of the foregoing Articles 14 2, 14 2 1, and 14 2 2 shall continue for the duration of this Agreement and shall be applicable to each and every occasion and whenever either Party desires to dispose of (whether by sale, conveyance, transfer, assignment, lease, or otherwise) all or any portion of its ownership interest in Trimble County Unit 1 to any third party or parties, provided, that such provisions shall not be applicable to, and each of the Parties hereby consents to, the following:

(a)the transfer, sale, or assignment to a financially responsible subsidiary, affiliate, or successor of Louisville; or

(b)the transfer, sale, or assignment by IMPA to a financially responsible successor agency or affiliate operating as a single entity; provided that if IMPA is dissolved or liquidated by operation of law or otherwise, and IMPA’s interest herein is not assumed by a financially responsible successor agency operating as a single entity, Louisville shall have the immediate option to purchase all of IMPA’s interest herein at

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fair market value. For this purpose, fair market value shall be determined by an Independent appraiser selected jointly by the Parties; or

(c)the transfer, assignment, pledge, hypothecation, mortgage, or grant (by indenture of mortgage, deed of trust, or otherwise) by either Party of Its ownership Interest In Trimble County Unit 1, together with all or substantially all of Its other electric utility property, for the purpose of securing bonds or other obligations for borrowed money Issued or to be Issued by It, Including the effect of any after-acquired property clause of any such Indenture of mortgage, deed of trust, or other Instrument now existing or hereafter created by such Party, or the realization on or enforcement of such security or the exercise by the trustee or the mortgagee, or as the case may be, or the beneficiaries of such security of any of the rights, powers, or privileges provided for with respect. thereto; or

(d)the transferring by either Party to a third party of Its undivided ownership Interest In Trimble County Unit 1, together with all or substantially all of Its other electric utility property, whether by sale or pursuant to or as a result of a merger, consolidation, or corporate reorganization; or

(e)the transferring by Louisville of any interest In Trimble County Unit 1 which transfer would not reduce Louisville’s interest in Trimble County Unit 1 to a level below seventy-five (75) percent; or

(f)the transferring by Louisville of any interest in Trimble County Unit 1 to IMEA.

All transfers of interest set forth in this Article 14 shall be conditioned upon the transferee, by written agreement or by operation of law, assuming the obligations of this Agreement, and any amendments thereto, of the Party so transferring; except that transfer under (b) and (c) above shall not be subject to this condition prior to any exercise of ownership, control, or possession by the transferee over the interest transferred.

14.3.Transfer Of Associated Rights And Interests

No transfer (whether by sale, conveyance, assignment, lease, or otherwise) by IMPA of any interests under this Agreement shall be permitted, or shall become effective, unless the interest transferred includes a corresponding and equivalent transfer of IMPA’s associated rights and interests under this Agreement, including its rights and interests in Trimble County Unit 1, the Trimble County General Plant Facilities, and the Trimble County Site, and unless such transfer is made in full compliance with this Article 14.

ARTICLE 15.
RIGHT OF FIRST REFUSAL

If, at any time within the term of this Agreement, Louisville shall apply to the Kentucky Public Service Commission for a certificate of public convenience and

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necessity for the Installation at the Trimble County Site of a coal-fired generating unit for use by Its system as a base load plant, IMPA shall have a right of first refusal to participate in the ownership of said unit by electing to own 12.88 percent of such unit on the terms set forth herein. In the event such a certificate is not legally required, Louisville shall use Its best efforts to give notice to IMPS equivalent In time and content to that which would be given where a certificate Is required. At least ninety days prior to applying for such certificate, Louisville shill provide written notice to IMPA of Its Intention to make such application, and shall provide IMPA with technical and economic Information available at that time which pertains to the planned unit, and the estimated cost thereof. IMPA shall have 180 days to elect to participate In such unit. IMPA’s right to participate in such unit shall lapse and expire unless IMPA provides written notice to Louisville of Its acceptance of such participation within 180 days after the date of Louisville’s earlier notice to IMPA. Within 180 days of Louisville’s receipt of IMPA’s notice of acceptance, the Parties shall negotiate in good faith and execute a separate contract Incorporating the terms and conditions of this Article 15, as well as other appropriate terms and conditions, covering the Installation and operation of such new unit.

Should IMPA elect to participate, It shall pay its pro rata share of all actual expenditures made for Construction Work In connection with such unit and shall make quarterly progress payments to Louisville as said expenditures are Incurred and billed by Louisville to IMPA. In addition to such actual expenditures, IMPA shall pay Louisville a general supervisory fee equal to two percent of such actual expenditures. IMPA’s participation In the unit shall be subject to all terms and conditions set forth In this Agreement unless waived In writing by Louisville, or otherwise mutually agreed by the Parties. Terms relating to Louisville’s operation and management of such unit may be set forth In an additional agreement between the Parties. Payment of the above amounts shall entitle IMPA, In addition to Its ownership Interest in such unit, to a license to use the Trimble County General Plant Facilities and the Trimble County Site as they pertain to such unit. Subject to IMPA’s right to elect to participate In 12.88 : percent of such unit, nothing herein shall prevent Louisville from selling, offering to sell, or contracting with any other Party, for an ownership or other Interest in or contractual entitlement from the remainder of such unit, or In the Trimble County General Plant Facilities or Trimble County Site as they pertain to such unit. The right of first refusal shall apply only to the next coal-fired generating unit built at the Trimble County Site for use as a base load plant, and shall not extend to any subsequently built unit IMPA accepts this right of first refusal acknowledging that IMEA has a similar right of first refusal In such unit In the event Louisville assigns or conveys Its right to develop such unit to an affiliate of Louisville or to a third party, such assignment or conveyance shall be subject to IMPA’s right of first refusal on the same terms and conditions as if Louisville were the developer.

If Louisville Is the developer of such unit, contracts for general construction of such unit (not Including design, architecture, and engineering services) will be awarded by Louisville pursuant to a bidding process arranged and implemented by Louisville. Louisville reserves the right to participate, for itself and for any affiliate of Louisville, as a bidder for the contractual services to be awarded. Louisville, In Its sole discretion, will

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determine the winning bidder based on a “best bid’ approach considering price, quality, experience, and all other factors deemed relevant by Louisville.

ARTICLE 16.
ASSIGNMENT

16.1.Limitation Of Assignability.

This Agreement shall not be assignable by either Party without the written consent of the other Party, except that no such consent shall be required for IMPA to assign this Agreement (a) as an incident to the disposition of all of its ownership interest in accordance with Articles 14.2, 14.2.1, and 14.2.2 hereof, or (b) to the trustee for the tax-exempt revenue bonds issued by IMPA to pay the costs of the acquisition of IMPA’s ownership interest in Trimble County Unit 1 hereunder; and (c) each of the Parties hereby consents to the assignment of this Agreement as an incident to the disposition of a Party’s ownership interest, as permitted by Article 14.2.3.

16.2.Successors And Assigns.

This Agreement shall inure to the benefit of and be binding upon Louisville and IMPA and their respective successors. This Agreement shall inure to the benefit of and be binding upon the assigns of Louisville and IMPA when such assignment is made in accordance with the provisions of Article 16.1.

ARTICLE 17.
LIABILITY AND DEFAULT

17.1.Liability To Third Parties.

Notwithstanding any provision to the contrary In this Agreement, any liability or any payment, cost, expense, or obligation arising from a claim of liability (after application thereto of any Insurance coverage or proceeds) to a third party or parties against one or both of the Parties and arising from the acquisition, planning, engineering, design, licensing, procurement, construction, Installation, completion, operation, use, management, control, maintenance, replacement, alteration, modification, renewal, rebuilding or repair, retirement, disposal, or salvaging of Trimble County Unit 1 or any part thereof and the Trimble County General Plant Facilities and the Trimble County Site as they pertain to Trimble County Unit 1; or from any other action or failure to act by either Party (or Its employees, agents, or contractors) In carrying out any of the provisions of this Agreement in regard to Trimble County Unit 1 or any part thereof and the Trimble County General Plant Facilities and the Trimble County Site as they pertain to Trimble County Unit 1, shall be shared by the Parties in proportion to their respective percentage ownership interests in Trimble County 1 in all circumstances except where such liability or claim of liability Is the result of gross negligence or intentional wrongdoing on the part of Louisville or IMPA. If, by reason of any such liability or claim of liability (after application thereto of any Insurance coverage or proceeds) to a third party or parties, either Party shall be called upon to make any payment or to Incur any

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cost, expense, or obligation In excess of that for which It Is responsible under the provisions of the preceding sentence, then the other Party shall reimburse the Party making such excess payment or Incurring any such excess cost, expense, or obligation to the full extent of the excess. Louisville shall be solely responsible for third party claims arising prior to Closing and shall fully indemnify IMPA against any such claim.

17.2.Liability Between The Parties.

Except as set forth In this Article 17.2, Louisville shall not be liable to IMPA for any loss, cost, damage, or expense Incurred by IMPA as a result of any action or failure to act, under any circumstances, by Louisville (or Its employees, agents, or contractors) In carrying out any of the provisions of this Agreement, except that Louisville will be liable to IMPA for (a) any such loss, cost, damage, or expense which is the result of gross negligence or intentional wrongdoing on the part of Louisville, and (b) any damage to IMPA caused by Louisville’s negligence, but only If such damage results from Louisville’s failure to follow Good Utility Practice in operating Trimble County Unit 1; provided, that no liability for failure to follow Good Utility Practice shall exceed, in any one contract year, five percent of the amount paid by IMPA pursuant to Articles 7.1.2, 7.1.3 and. 7.1.4 in that same contract year.

Notwithstanding any other provision of this Agreement, in no event, however, shall Louisville be liable to IMPA with respect to any claim, whether based on contract, tort (including negligence), patent, trademark or service mark, or otherwise, for any indirect, special, incidental, or consequential damages, including, but not limited to, loss of profits or revenues, loss of use of Trimble County Unit 1 or any part thereof and the Trimble County General Plant Facilities and the Trimble County Site as they pertain to Trimble County Unit 1, cost of capital, cost of purchased or replacement power, claims of the customers of IMPA for service interruptions.

In no event shall Louisville be excused from liability for its fraudulent acts.

17.3.Indemnification.

Subject to Article 17.2 hereof, each Party (“breaching Party~) hereby agrees to indemnify and hold the other Party (“non-breaching Party”) harmless from, against, and in respect of and shall on demand reimburse the non-breaching Party for:

(a)any and all loss, liability, or damage resulting from any untrue representation, breach of warranty, or non-fulfillment of any covenant or agreement by the breaching Party contained herein or In any certificate, document, or instrument delivered to the non-breaching Party hereunder and

(b)any and all loss suffered by the non-breaching Party due to the breaching Party’s failure to perform or satisfy any obligation assumed pursuant to this Agreement; and

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(c)any and all loss resulting from actions, suits, proceedings, claims, demands, assessments, judgments, costs, and expenses, including, without limitation, legal fees and expenses, incident to any of the foregoing or incurred in investigating or attempting to avoid the same or to oppose the imposition thereof, or in enforcing this indemnity.

17.4.Nature And Survival Of Representations And Warranties.

Each representation, warranty, indemnity, covenant, and agreement made by the Parties in this Agreement or In any document, certificate, or other instrument delivered by or on behalf of the Parties pursuant to this Agreement or in connection herewith, shall survive the Closing.

17.5.Default.

17.5.1.Events of Default.

The following shall be Events of Default under this Agreement:

17.5.1.1.Failure To Make Payment.

Subject to Article 8.2 hereof, failure by either Party to make any payment to the other Party required under this Agreement within sixty (60) days after the date on which such payment becomes due, or failure by either Party to give any credit to the other Party required under this Agreement for a period of sixty (60) days after the date on which such credit becomes due, or failure by either Party to make payment for a period of sixty (60) days after the date on which such payment becomes due to any third party, when failure to do so could result in a lien on any of the property included under this Agreement or otherwise adversely affects the interests of the other Party; provided, however, that no Party shall be in default if the amount it owes hereunder can be, and is, offset in whole within sixty (60) days after the date on which such amount became due and payable, by the Party to whom that sum is owed under this Agreement.

17.5.1.2.Failure To Perform.

Failure by either Party to perform any material obligation, duty, or responsibility in accordance with the provisions of this Agreement.

17.5.2.Curing Default In Regard To Paying Money.

As to any default resulting from the failure to pay money, the defaulting Party may remedy its default (when its default is the failure to pay money) by paying to the non-defaulting Party on or before ninety (90) days from the date the payment becomes due:

(a)the sums due; and

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(b)interest on the sums due at the Agreed Rate from the date due until paid; and

(c)any other costs incurred by the non-defaulting Party as a result of such default.

17.5.3.Curing Default For Other Than Failure To Pay Money

A Party in default for reasons other than the failure to pay money may cure such default by performing such act as is necessary to cure the default and by paying the non-defaulting Party on or before ninety (90) days from the date such default occurred, any sums due under Article 17.3 hereof.

17.5.4.Non-Applicability Of Cure Provisions

Articles 17.5.2 and 17.5.3 hereof shall not be applicable to any Event of Default relating to pre-Closing or Closing activities set forth in this Agreement. Cure periods under Articles 175.2 and 17.5.3 will not operate to extend the time specified in any other Article of this Agreement for the performance or occurrence of any act or event, unless otherwise specified.

17.5.5.Appointment Of A Receiver.

In the event the default continues for a period of 180 days, then the Non-Defaulting Party may have a receiver appointed by a state or federal court sitting in Louisville, Kentucky to take control of and operate the defaulting Party’s interest in the facilities and perform in accordance with the terms of this Agreement.

17.5.6.Additional Obligations.

With respect to any Party as to which an Event of Default has occurred, such Party shall use its best efforts to take any and all such further actions and shall execute and file where appropriate any and all such further legal documents and papers as may be reasonable under the circumstances in order to facilitate the carrying out of this Agreement or otherwise effectuate its purpose, including but not limited to action to seek any required governmental or regulatory approval and to obtain any other required consent, release, amendment, or other similar document.

17.5.7.Waivers

No waiver of any default or Event of Default hereunder shall extend to or affect any subsequent default or Event of Default or shall impair any rights or remedies consequent thereon. No delay or omission to exercise any remedy available upon any Event of Default shall impair any Party’s right to exercise such remedy or shall be construed to be a waiver thereof, but any such remedy may be exercised from time to time and as often as may be deemed expedient. In order to entitle each Party hereto to

45

exercise any remedy conferred upon or reserved by it in this Article 17, notice shall be provided in accordance with Article 21.2 hereof.

17.5.8.Legal And Other costs.

In the event that any Party (the “Defaulting Party’) defaults in its obligations under this Agreement and, as a result thereof, the other Party (the “Non-Defaulting Party’) seeks to legally enforce its rights hereunder against the Defaulting Party, then, in addition to all damages and other remedies to which the Non-Defaulting Party Is entitled by reason of such default, the Defaulting Party shall promptly pay to the Non-Defaulting Party an amount equal to all costs and expenses (including reasonable attorneys’ fees) paid or incurred by the Non-Defaulting Party in connection with such enforcement.

17.6.Force Majeure

In no event shall either Party be liable to the other Party for failure by such Party to perform any of its obligations under this Agreement because of Force Majeure. Nothing contained herein shall be construed to require a Party to settle any strike, lockout, work stoppage, or other industrial disturbance or dispute in which it may be involved or to take an appeal from any judicial, regulatory, or administrative action. Any Party rendered unable to fulfill any of its obligations under this Agreement by reason of Force Majeure shall exercise due diligence to remove such inability with all reasonable dispatch. In the event either Party is unable, in whole or in part, to perform any of its obligations by reason of Force Majeure, other than obligations to make payments hereunder, the obligations of the Party relying thereon, insofar as such obligations are affected by such Force Majeure, shall be suspended during the continuance thereof but no longer. The obligation of IMPA to make payments as set forth in Articles 7 and 8 shall be unconditional and absolute, and shall not be subject to reduction, setoff, or claim of Force Majeure. The Party invoking the Force Majeure shall specifically state the full particulars of the Force Majeure and the time and date when the Force Majeure occurred. Notices given by telephone under the provision of this Article shall be confirmed in writing as soon as reasonably possible. When the Force Majeure ceases, the Party relying thereon shall give immediate notice thereof to the other Party. This Agreement shall not be terminated by reason of Force Majeure but shall remain in full force and effect.

ARTICLE 18.
ADMINISTRATION

18.1.Coordination Committee.

From time to time various administrative, financial, and technical matters may arise in connection with the terms and conditions of this Agreement which will require the cooperation and consultation of the Parties and interchange of information. As a means of providing for such consultation, interchange, decision making, or ratification, a Coordination Committee is hereby established with functions as described in Article 18.4 below. However, such Committee shall not diminish in any manner the authority of

46

Louisville or the rights of IMPA as set forth in the various sections of this Agreement. The Coordination Committee shall have no authority to modify or amend the terms of this Agreement.

18.2.Membership.

The Coordination Committee shall have one member from each Party. Within 60 days after execution of this Agreement, each Party shall designate in writing its Representative and at least one alternate on the Coordination Committee and shall promptly give written notice thereof to the other Parties. Thereafter, each Party shall promptly give written notice to the other Party any change in the designation of its Representative on the Coordination Committee. The Chairman of the Coordination Committee shall be the Louisville Representative, who shall be responsible for calling meetings and establishing agenda Each Party, however, shall have the right to have an item included on the agenda. All actions taken by the Coordination Committee must be by majority vote, with each Party entitled to vote in shares equal to its ownership interest. The Coordination Committee may also act without a meeting by telephone conference or notational voting by correspondence. Majority vote shall not be required for either Party to invoke the procedure under Article 19.2 for handling disagreements.

18.3.Meetings.

The Coordination Committee shall meet annually on a date and at a location to be announced by the Chairman at least thirty (30) days in advance, or sooner with the consent of all members. Such other meetings as are reasonably required may be called by any member with as much advance notice as is practical. Meetings may be attended by other representatives of the Parties.

18.4.Functions

The Coordination Committee shall have the following functions:

(a)Provide liaison between the Parties at the management level and exchange Information with respect to significant matters of licensing, design, construction, operation, and maintenance of Trimble County Unit 1 and the Trimble County General Plant Facilities and the Trimble County Site as they pertain to Trimble County Unit 1.

(b)Appoint Ad Hoc Committees, the members of which need not be members of the Coordination Committee, as necessary to perform detailed work and conduct studies regarding matters requiring investigation.

(c)Review and discuss disputes arising under this Agreement.

(d)Provide liaison between the Parties with respect to the financial and accounting aspects of Incremental Capital Assets and operation of Trimble County Unit I and perform those functions set forth in Article 6.1 hereof.

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(e)Provide a liaison between the Parties with respect to the financial and accounting aspects of the ownership of the property.

(f)Review and approve budgets for operation, maintenance, and Incremental Capital Assets, including retirement of facilities, which affect Trimble County Unit 1 and the Trimble County General Plant Facilities and the Trimble County Site as they pertain to Trimble County Unit 1.

(g)Perform such other duties as set forth pursuant to the other Articles of this Agreement.

18.5.Records

The Coordination Committee shall keep written records of all meetings.

18.6.Expenses.

Each Party shall be responsible for the personal expenses of its Representative and its other attendees. All other expenses incurred in connection with the performance by the Coordination Committee of its functions shall be allocated and paid as determined by the Coordination Committee.

18.7.Conduct

Members of the Coordination Committee shall use their reasonable best efforts to perform Committee functions by taking into account Good Utility Practice.

ARTICLE 19.
DISAGREEMENT

19.1.Consultation.

In accordance with the provisions of Article 18, the members of the Coordination Committee will consult in connection with any major matter arising under this Agreement.

19.2.Disagreement.

If any disagreement arises on major operation and maintenance matters pertaining to Trimble County Unit 1, major capital matters pertaining to Trimble County Unit 1, or major retirement matters, or other matters arising under this Agreement, pertaining to Trimble County Unit 1 (“Plant Subject?), such matters shall be discussed by the Coordination Committee and timely mutual agreement sought in regard thereto. If each of the members of the Coordination Committee agrees to the resolution of any Plant Subject, such agreement shall be reported in writing to and shall be binding upon the Parties—within the authority of the Coordination Committee as stated in Article 18. In the unlikely event that each of the members of the Coordination Committee is unable to

48

reach agreement within a reasonable time (giving due cognizance to the operating and maintenance schedules of Trimble County Unit 1 and all other pertinent circumstances) with respect to any Plant Subject under consideration, the President of Louisville or the President of IMPA can, by written notice to the members of the Coordination Committee, withdraw the matter from consideration by the Coordination Committee and submit the same for resolution to the President of Louisville and the President of IMPA. If these senior representatives of the Parties agree to a resolution of the matter, such agreement shall be reported in writing to and shall be binding upon the Parties; but if said senior representatives fail to resolve the matter within seven days after its submission to them, then the matter may proceed to arbitration as provided in Article 19.3.

19.2.1.Arbitration.

If a disagreement should arise with respect to any Plant Subject which is not resolved by the Coordination Committee or the senior representatives of the Parties as provided in Article 19.2 or any other disagreement concerning this Agreement, then such disagreement may be settled by an Arbitration Board, (or by such other form of dispute resolution as agreed upon by the Parties) which shall consist of three arbitrators as hereinafter provided, in accordance with the provision of this Article 19.3. If, after the procedure for resolving such disagreement by the Coordination Committee or the senior representatives of the Parties as provided Ii Article 19.2 has been exhausted, either Party desires that such disagreement shall be settled by arbitration, it shall serve written notice upon the other Party setting forth in detail such disagreement with respect to which arbitration is desired. Such disagreement shall be settled by arbitration if, after receipt of such written notice, both of the Parties shall agree in writing that such disagreement shall be settled by arbitration.

Within a period of thirty (30) days from the date of such agreement in writing to settle such disagreement by arbitration, each Party shall select one arbitrator. Within a period of sixty (60) days from the date of such agreement in writing to settle such disagreement by arbitration, the two arbitrators so selected shall meet and select one additional arbitrator. If either or both of the two arbitrators to be selected by the Parties, as herein provided, are not so selected within the specified 30 day period, or if the two arbitrators selected by the Parties shall fail to agree upon the selection of the additional arbitrator within the specified 60 day period, either Party may, upon written notice to the other Party, apply to the American Arbitration Association for the appointment of the arbitrator or arbitrators who have not been so selected and such Association shall thereupon be empowered to select such arbitrator or arbitrators.

The arbitration proceedings shall be conducted in Louisville, Kentucky unless otherwise mutually agreed. The Arbitration Board shall afford adequate opportunity to both of the Parties to present information with respect to the disagreement submitted to arbitration and may request further information from either Party. Except as provided in the preceding sentence, the Parties may, by mutual agreement, specify the rules which are to govern any proceeding before the Arbitration Board and limit the matters to be considered by the Arbitration Board, in which event the Arbitration Board shall be

49

governed by the terms and conditions of such agreement. In the absence of any such agreement respecting the rules which are to govern any proceeding, the then current rules of the American Arbitration Association for the conduct of commercial arbitration shall govern the proceedings, except that if such rules shall conflict with the then current provisions of the laws of Kentucky relating to arbitration, such conflict shall be governed by the then current provisions of the laws of Kentucky relating to arbitration.

Procedural matters pertaining to the conduct of the arbitration and the award of the Arbitration Board shall be made upon a determination of a majority of the arbitrators. The Parties shall, however, be entitled to all discovery provided for by the Kentucky Rules of Civil Procedure. The findings and award of the Arbitration Board, so made upon a determination of a majority of the arbitrators, shall be final and conclusive with respect to the disagreement submitted for arbitration and shall be binding upon the Parties, except as otherwise provided by law. Each Party shall pay the fee and expenses of the arbitrator selected by or for it, together with the costs and expenses incurred by it in the preparation of its case to the arbitrators. The fee and expenses of the third arbitrator selected in accordance with this Article 19.3 shall be assigned in equal parts to the Parties, and each Party shall assume and pay the portion of such fee and costs so assigned to it Judgment upon the award may be entered in any court having jurisdiction In the event the Parties do not agree to arbitrate, each shall have the right to take appropriate judicial action. 19 4 Obligations To Make Payments

If a disagreement should arise from any Plant Subject which is not resolved by the Coordination Committee or the senior representatives of the Parties as provided in Article 19.2, then, pending the resolution of the disagreement by arbitration and/or litigation, Louisville shall continue to operate Trimble County Unit 1 and make necessary Incremental Capital Assets in a manner consistent with this Agreement, and IMPA shall continue to make all payments required in accordance with the applicable provisions of this Agreement.

ARTICLE 20.
REMEDIES

20.1.All Remedies . Setoff.

In the event either Party (the “Defaulting Party’) fails to pay when due any amount owing by it to the other Party (the “Non-Defaulting Party”) under this Agreement or the Interconnection Agreement or fails to perform or observe any covenant, condition, or agreement to be performed or observed under this Agreement or the Interconnection Agreement, the Non. Defaulting Party shall have available to it all remedies, legal and equitable, including, without limitation those available in order to enforce payment of any such amount or performance or observance of any such covenant, condition, or agreement, subject to the defaulting Party’s rights to cure default under Article 17.5. All overdue payments shall bear interest at the Agreed Rate. Further, the Non-Defaulting Party shall have the right to setoff against any amount owed to it by the Defaulting Party the amount of any payment which such Party has failed to pay when due under this

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Agreement or the Interconnection Agreement. In addition, the Non-Defaulting Party shall have the other rights and remedies available to it under this Article 20.

20.2.Injunctive Relief.

The Parties hereto agree and acknowledge that the failure to perform any of their obligations under this Agreement, including the execution of legal documents which may be reasonably requested as set forth in this Article, would cause irreparable injury to the other Party and that the remedy at law for any violation or threatened violation thereof would be inadequate, and agree that the other Party shall be entitled to a temporary or permanent injunction or other equitable relief specifically to enforce such obligation without the necessity of proving the inadequacy of its legal remedies.

20.3.No Remedy Exclusive.

No remedy conferred upon or reserved to the Parties hereto in this Agreement is intended to be exclusive of any other remedy or remedies available hereunder or now or hereafter existing at law, in equity, or by statute or otherwise, but each and every such remedy shall be cumulative and shall be in addition to every other such remedy. The pursuit by any Party of any specific remedy shall not be deemed to be an election of that remedy to the exclusion of any other or others, whether provided hereunder or by law, equity, or statute.

20.4.Failure To Participate In Incremental Capital Assets.

If IMPA fails to make any payment of its share of the cost of Incremental Capital Assets after the Closing, Louisville shall have the right, at its election, to give written notice of such failure to IMPA. If such overdue payment and all other overdue payments~ if any, of IMPA’s share of the cost of the Incremental Capital Assets after the Closing, together with interest on such overdue payment or payments, are not paid within ninety (90) days after the giving of the written notice first referred to in this paragraph, then (a) IMPA’s rights to make any further payments of its share of the cost of the Incremental Capital Asset shall thereupon terminate, and (b) the respective percentage ownership interests in Trimble County Unit 1 shall be adjusted in accordance with the following formula:

ADD = ALGE*IPCT/(IMPA+ALGE) .

where:

ADD =	Additional percentage ownership interest accruing to Louisville as a result of making its additional investment to complete construction of Incremental Capital Assets (there shall be a corresponding reduction in the percentage ownership interest of IMPA in Trimble County Unit 1 and the Trimble County Site).
IMPA  =	Investment made by IMPA for its respective percentage ownership

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	interest in Trimble County Unit 1, the Trimble County Site and its nonexclusive license with respect to the Trimble County General Plant Facilities to the time of the written notice first referred to in this Article 20.4.
ALGE  =	Additional Investment made by Louisville to complete construction of Incremental Capital Assets as aforesaid.
IPCT  =	IMPA’s percentage ownership interest in Trimble County Unit 1 at the time of the written notice first referred to in this Article 20.4.

ARTICLE 21.
MISCELLANEOUS

21.1.Governing Law.

The validity, interpretation, and performance of this Agreement and each of its provisions shall be governed by the laws of the Commonwealth of Kentucky, except that the power and authority of IMPA to enter into this Agreement shall be governed by the laws of the State of Indiana.

21.2.Notice To Parties.

Unless otherwise specifically provided by other provisions of this Agreement, any notice, consent, or other communication required to be made under this Agreement shall be addressed to or made by such officer, agent, representative, or employee of each Party as such Party may, from time to time, designate in writing, provided that any written notice required to be made pursuant to Articles 14, 18, and 19.3 hereof shall be delivered in person, by prepaid telegram, or by registered or certified mail, to the named officer of the Party at the address listed below; provided, that either Party may, from time to time, change such designated officer or the address thereof by giving written notice of such change to the other Party. Any requirement for notice in writing may be met by telex, telecopy, or other electronic means of communicating written or printed material, if promptly confirmed in writing.

TOLouisville:

President

Louisville Gas and Electric Company

220 West Main Street (40202)

Post Office Box 32010

Louisville, Kentucky 40232

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TOIMPA:

General Manager

Indiana Municipal Power Agency

11610 North College Avenue

Carmel, Indiana 46032

21.3.Article Headings Not To Affect Meaning.

The descriptive headings of the various Articles of this Agreement have been inserted for convenience of reference only and shall in no way modify or restrict any of the terms or provisions hereof.

21.4.Counterparts.

This Agreement may be executed simultaneously in two or more counterparts, each of which shall be deemed an original, but all of which together shall constitute one and the same instrument.

21.5.Time.

Louisville and IMPA agree that time is of the essence in this Agreement.

21.6.Severability.

In the event that any provision of this Agreement, or the application of any such provision to any person or circumstance, shall be held invalid or unenforceable, the remainder of this Agreement, or the application of such provision to persons or circumstances other than those as to which it is held invalid or unenforceable, shall not be affected thereby.

21.7.Integration.

The terms and provisions contained in this Agreement and the Interconnection Agreement constitute the entire agreement between Louisville and IMPA in regard to the respective matters of said Agreement, and shall supersede all previous communications, representations, or agreements, either oral or written, between Louisville and IMPA with respect to the respective subject matters of said Agreements.

21.8.Computation Of Time.

In computing any period of time prescribed or allowed by this Agreement, the day of the act, event, or default from which the designated period of time begins to run shall

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not be included. The last day of this period so computed shall be included, unless it is a Saturday, Sunday, or legal holiday in Kentucky, in which event the period shall run until the end of the next day which is neither a Saturday, Sunday, nor legal holiday.

21.9.Waiver.

Any waiver at any time, by either Party, of its rights with respect to the other Party, or with respect to any other matter arising in connection with this Agreement, shall not be considered a waiver with respect to any subsequent default or matter.

21.10.Equal Opportunity Clause.

During the performance of those parts of this Agreement relating to the construction by a Party of any Incremental Capital Assets, such Party agrees as follows:

(a)Such Party will not discriminate against any employee or applicant for employment because of race, color, religion, sex, or national origin. Such Party will take affirmative action to insure that applicants are employed, and that employees are treated, during employment, without regard to their race, color, religion, sex, or national origin. Such action shall include, but not be limited to, the following: employment, upgrading, demotion, or transfer; recruitment or recruitment advertising; layoff or termination; rates of pay or other forms of compensation; and selection for training, including apprenticeship. Such Party agrees to post, in conspicuous places, available to employees and applicants for employment, notices setting forth the provisions of this non-discrimination clause;

(b)Such Party will, in all solicitations or advertisements for employees place by or on behalf of such Party, state that all qualified applicants will receive consideration for employment without regard to race, color, religion, sex, or national origin;

(c)Such Party will send to each labor union or representative of workers with which it has a collective bargaining agreement or other contract or understanding, a notice, to be provided, advising the said labor union or workers’ representative, of such Party’s commitments under this Article 21.10, and shall post copies of the notice In conspicuous places, available to employees and applicants for employment;

(d)Such Party will comply with all provisions of Executive Order No. 11246 of September 24, 1965, and of the rules, regulations, and relevant orders of the Secretary of Labor

(e)Such Party will furnish all information and reports required by Executive Order No. 11246 of September 24, 1965, and by the rules, regulations, and orders of the Secretary of Labor, or pursuant thereto, and will permit access to its books, records, and accounts by the administering agency and the Secretary of Labor, for purposes of investigation, to ascertain compliance with such rules, regulations, and orders;

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(f)In the event of such Party’s noncompliance with the none discrimination clauses of this Agreement, or with any of the said rules, regulations, or orders, this Agreement may be canceled, terminated, or suspended, in whole or in part, and such Party may be declared ineligible for further Government contracts or federally assisted construction contracts in accordance with procedures authorized in Executive Order No. 11246 of September 24, 1965, and such other sanctions may be imposed and remedies invoked as provided in said Executive Order or by rule, regulation, or order of the Secretary of Labor, or as otherwise provided by law

(g)Such Party will includes the words “During the performance of this contract, the contractor agrees as follows:” followed by the provisions of sections (a) through (I) of this Article 21.10 in every subcontract or purchase order, unless exempted by rules, regulations, or orders or the Secretary of Labor issued pursuant to Section 204 of Executive Order No. 11246 of September 24, 1965, so that such provisions will be binding upon each subcontractor or vendor. Such Party will take such action with respect with any subcontract or purchase order as the administering agency may direct as a means of enforcing such provisions, including sanctions for noncompliance; provided, however, that in the event such Party becomes involved in, or is threatened with, litigation by a subcontractor or vendor as a result of such direction by the administering agency, such Party may request the United States to enter into such litigation to protect the interests of the United States;

(h)For purposes of this Agreement, the term “this Agreement,’ as used in this Article 21.10 shall mean those parts of this Agreement relating to the construction by such Party of any additions, betterments, or improvements to the property. Nothing in this Article 21.10 shall be construed to prevent such Party from resisting, challenging, contesting, or appealing any law, statute, regulation, or decision of any federal, state, or local government or agency which such Party claims to be in invalid, unlawful, arbitrary, or capricious.

21.11.Non-Segregated Facilities.

Each Party certifies further that It will not maintain or provide for its employees any segregated facilities at any of its establishments, and that it will not permit its employees to perform their services at any location, under its control, where segregated facilities are maintained. Each Party agrees that a breach of this certification is a violation of the Equal Opportunity Clause in this Agreement. As used in this certification, the term “segregated facilities’ means any waiting rooms, work areas, rest rooms and washrooms, restaurants, and other eating areas, time clocks, locker rooms and other storage or dressing areas, parking lots, drinking fountains, recreation or entertainment areas, transportation, or housing facilities provided for employees which are segregated by explicit directive or are, in fact, segregated on the basis of race, color, religion, or national origin, because of habit, local custom, or otherwise. Each Party agrees that (except where it has obtained identical certifications from proposed subcontractors for specific time periods) it will obtain identical certifications from proposed subcontractors prior to the award of subcontracts exceeding $10,000 which are not exempt from the

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provisions of the Equal Opportunity Clause, and that it will retain such certifications in its files.

Nothing in this Article 21.11 shall be construed to prevent any Party from resisting, challenging, contesting, or appealing any law, statue, regulations, or decision of any federal, state, or local government or agency which the Party claims to be invalid, unlawful, arbitrary, or capricious.

21.12.Condemnation.

In the event any portion of Trimble County Unit 1, or any portion of the Trimble County Site or the Trimble County General Plant Facilities as they pertain to the Parties’ use of Trimble County Unit 1, shall be condemned and taken by exercise of any right of eminent domain or for public or quasi-public use, and the Parties hereto are able to continue their use and operation of the remaining portion thereof, this Agreement shall not terminate. The proceeds of any payment of any award or compensation arising from such condemnation (net of any unrecovered expenses of any nature incurred by the Parties with respect thereto, which expenses shall be fully reimbursed to the Party or Parties incurring such expenses) shall be apportioned between the Owners on the basis of their respective ownership interests in Trimble County Unit 1. In the event that all of Trimble County Unit 1, or all of the Trimble County Site, and the Trimble County General Plant Facilities as they pertain to the Parties’ use of Trimble County Unit 1, shall be condemned and taken by exercise of any right of eminent domain or for public or quasi-public use, this Agreement shall terminate as of the date of said taking and the proceeds of any award or compensation arising from such condemnation (net of any unrecovered expenses of any nature incurred by the Owners with respect thereto, which expenses shall be fully reimbursed to the Owner or Owners incurring such expenses) shall be apportioned between the Owners on the basis of their respective ownership interests in Trimble County Unit 1.

ARTICLE 22.
TERM AND TERMINATION

22.1.Termination.

This Agreement shall terminate at such time as those activities which are necessary to retire Trimble County Unit 1 from service have been completed. Retirement from service shall include, without limitation: dismantling, demolishing, and removal of equipment, facilities, and structures; security; maintenance; disposing of debris; and any site work necessary to lawfully and responsibly effect such retirement. Termination of this Agreement, however, shall not terminate or affect, as between the Parties, the continued liability, if any, of the Parties for environmental considerations or other obligations imposed by law. •

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22.2.Retirement Of Property.

The Coordination Committee shall have authority in decisions regarding the retirement from service of any and all property included in Trimble County Unit 1 and Trimble County General Plant Facilities which, in the Coordination Committee’s judgment, is damaged, worn out, uneconomic, unreliable, obsolescent, or otherwise unfit for use. However, Trimble County Unit 1 shall not be retired from service as a generating unit without the written consent of IMPA prior to the earlier of:

(a)the expiration of 35 years following the Commercial Operation Date of Trimble County Unit 1; or

(b)the final maturity date of the project revenue bonds originally issued by IMPA to finance its initial ownership interest in Thimble County Unit 1, or the final maturity date of any bonds issued by IMPA to refund such originally issued bonds.

After the expiration of the applicable period in the preceding sentence, subject to the rights of any other Owner of Trimble County Unit 1, the Coordination Committee shall have the right to retire Trimble County Unit 1 from service as a generating unit at any time. Notwithstanding the above, in the event the Coordination Committee approves a major life extension or the installation of Incremental Capital Assets, either of which costs in excess of twenty-five percent of the original construction cost of the Trimble County Plant, and IMPA issues improvement or other bonds to finance such improvements, Louisville agrees, subject to the interests of any co-owners of Trimble County Unit 1, not to retire such unit prior to the expiration of 75 percent of the remaining useful life of such unit as determined by a qualified engineering consultant selected by the Coordination Committee.

22.3.Retirement Costs.

All costs (less salvage credits, if any) associated with retirement of Trimble County Unit 1 and the Trimble County General Plant Facilities and the Trimble County Site as they pertain to Trimble County Unit 1, including, without limitation: dismantling, demolishing, and removal of equipment, facilities, and structures; security; maintenance; disposing of debris; and any site work necessary to lawfully and responsibly effect such retirement, shall be shared by the Owners in proportion to their respective percentage ownership interests in Trimble County Unit 1. Payments for these costs (less salvage credits, if any) as they are expected to be incurred, shall be made In accordance with the provisions of Article 8. If such salvage credits exceed such costs, the difference shall be shared by the Owners in proportion to their respective percentage ownership Interests in Trimble County Unit 1.

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IN WITNESS WHEREOF, each of the Parties has caused this Agreement to be duly executed.

		LOUISVILLE GAS AND ELECTRIC COMPANY
Attest:		By:
	Secretary		Chris Hermann,
			Vice President and General Manager,
			Wholesale Electric Business
		INDIANA MUNICIPAL POWER AGENCY
Attest:		By:
	Dwight D. Langer		Frank Rudolph,
	Secretary		Chairman

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APPENDICES

Appendices to the Participation Agreement

Appendix A.	Bill of Sale
Appendix B.	Trimble County Unit No. 1 List
Appendix C.	License Agreement and Trimble County General Plant Facility List
Appendix D.	Known Defects at Closing
Appendix E.	General Warranty Deed
Appendix F.	Easement: Louisville to IMPA
Appendix G.	Easement: IMPA to Louisville

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APPENDIX A

BILL OF SALE

LOUISVILLE GAS AND ELECTRIC COMPANY, a Kentucky corporation, 220 West Main Street, P.O. Box 32010, Louisville, Kentucky 40232 (“Seller”) and INDIANA MUNICIPAL POWER AGENCY, a body corporate and politic and a political subdivision of the State of Indiana, 11610 North College Avenue, Carmel, Indiana 46032 (“Buyer”) for value received and in accordance with the covenants and conditions set forth in the Participation Agreement by and between Seller and Buyer, dated February 1, 1993, and incorporated by reference herein (“Agreement”) , and as part of the consideration for the performance of the Agreement, Seller hereby grants, bargains, transfers, sells and delivers unto Buyer, all of Seller’s right, title and interest in a l2.88~ undivided interest as a tenant in common in Trimble County Unit 1, as defined in the Agreement and as more particularly described in Appendix B to the Agreement, and pursuant to the terms of the Agreement.

Seller hereby represents, warrants and covenants, subject to any rights Illinois Municipal Electric Agency may have as an owner of a l2.l2% undivided ownership interest as tenant in common to the property transferred hereunder, that Seller is the owner of the property described in this Bill of Sale, and has full right, power and authority to sell and transfer the same.

IN WITNESS WHEREOF, the undersigned have executed this Bill of Sale by their duly authorized officers this 1st day of February, 1993.

	SELLER:
	LOUISVILLE GAS AND ELECTRIC COMPANY
Attest:	By:
		Chris Hermann,
		Vice President and General
		Manager, Wholesale Electric
		Business
	BUYER:
	INDIANA MUNICIPAL POWER AGENCY
Attest:	By:
		Frank R. Rudolph, Chairman

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APPENDIX B
Trimble County Unit 1

STRUCTURES

A.	Unit Structure
	1.	Concrete
		a.	Base Pad Foundation
		b.	Base Pad Finish Floor
		c.	Elevated Floors
		d.	Equipment Foundations
	2.	Steel Structures
		a.	Boiler and Air Preheater Room Steel
		b.	Turbine Room Steel
		c.	Stairways
		d.	Equipment Platforms
	3.	Enclosures
		a.	Partial Insulated Multi-Layer Metal Siding
		b.	Partial Uninsulated Metal Siding
		c.	Concrete & Built-Up Roof
B.	Draft Equipment
	1.	Concrete
		a.	Equipment Foundations
C.	Boiler Feed and Service Water Equipment
	1.	Concrete
		a.	Equipment Foundations
D.	Coal Mills
	1.	Concrete
		a.	Equipment Foundations
E.	Electrostatic Precipitator
	1.	Concrete
		a.	Foundations
		b.	Base Slab
	2.	Steel Structures

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		a.	Columns & Girders
		b.	Stairways
	3.	Enclosures
		a.	Metal Siding
		b.	ESP End Walls
F.	Sulphur Dioxide Removal System
	1.	Concrete
		a.	Foundations
		b.	Base Slab
		c.	Equipment Foundations
	2.	Steel Structures
		a.	Columns & Girders
		b.	Stairways
	3.	Enclosures
		a.	Insulated Metal Siding
		b.	Concrete & Built-Up Roof
G.	Bottom Ash Handling
	1.	Concrete
		a.	Equipment Foundations
H.	Turbine Generator
	1.	Concrete
		a.	Equipment Foundations
I.	Boiler
	1.	Steel Structures
		a.	Support Steel

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EQUIPMENT AND SYSTEM COMPONENTS

A.	Unit Structure
	1.	Masonry Blockwork
	2.	HVAC
	3.	Roof Drains
	4.	Passenger Elevator
	S.	Conduit & Cable Tray
	6.	Lighting
	7.	6900 Volt Equipment
	8	480 Volt Equipment
	9.	208/110 Volt Equipment
	10.	Control & Logic Room
	11.	Batteries & Chargers
	12.	Uninterruptible Power Supply
	13.	Station Fuel Oil Piping
	14.	Ignition Oil Piping
	15.	Main Steam Piping
	16.	Hot & Cold Reheat Piping
	17.	Condensate Piping
	18.	Gland Seal Piping
	19.	Attemperator Piping
	20.	Boiler Feed Suction Piping
	21.	Extraction Steam Piping
	22.	Auxiliary Cooling Piping
	23.	Closed Cooling Piping
	24.	Compressor and Instrument Air Piping
	25.	House Air Piping
	26.	Condensate Makeup Piping
	27.	Fire Protection
	28.	Turbine Room Gantry and House Cranes
	29.	Coal Silos
B.	Draft Equipment
	1.	Inducted Draft Fans
	2.	Forced Draft Fans
	3	Primary Air Fans
	4	Air & Gas Ducts
	5	Air Heater
C.	Boiler Feed and Service Water Equipment

63

	1	Motor Driven Feed Pumps
	2	Turbine Driven Feed Pumps
	3.	Feedwater Heaters
	4.	Cooling Pumps
D.	Coal Mills
	1.	Coal Mills
	2.	Feeders
E.	Electrostatic Precipitator
	1.	Precipitator
		a.	Elements
		b.	Hoppers
		c.	Vibrations
	2.	HVAC
	3.	Fire Protection Equipment
	4.	Insulation
	5.	480 Volt Equipment
	6.	208/110 Volt Equipment
	7.	Conduit & Cable Tray
	8.	Lighting
	9.	Communications
	10.	Control Building
	11.	Piping Systems
F.	Sulphur Dioxide Removal System
	1.	Inlet & Outlet Ducts
	2.	Absorber
	3.	Demister Wash Equipment
	4.	Seal Water Tank
	5.	Control Building
	6.	Electrical Building
	7.	Horizontal Pumps
	8.	Seal Air Fans
	9.	Air Compressors
	10.	Heat Exchangers
	11.	Cranes & Hoists
	12.	Piping Systems
	13.	6900 Volt Equipment
	14.	480 Volt Equipment
	15.	208/110 Volt Equipment
	16.	Lighting
	17.	Communications

64

	18.	Multiplex System
G.	Bottom Ash Handling
	1.	Hoppers
	2.	Ash Sluicing Equipment
	3.	Piping System
	4.	Bottom Ash Equipment
H.	Turbine Generator
	1.	Turbine Generator
	2.	Piping Systems
	3.	Seal Oil Unit
	4.	Hydrogen Coolers
	S.	Turbine Oil System
	6.	Electro Hydraulic Control
	7.	Multiplex System
	8.	Isolated Phase Bus
I.	Boiler
	1.	Boiler *
	2.	Economizer
	3.	Superheat/Reheat Panels
	4.	Water Walls
	5.	Heater Drains & Vents
	6.	Sootblowers
	7.	Burners

65

APPENDIX C

LICENSE AGREEMENT

THIS AGREEMENT made and entered into as of this 1st day of February, 1993, by and between LOUISVILLE GAS AND ELECTRIC COMPANY, a Kentucky corporation, having its principal office at 220 West Main Street, P.O. Box 32010, Louisville, Kentucky 40202, (“Louisville or Licensor”) and Indiana Municipal Power Agency, a body corporate and politic and a political subdivision of the State of Indiana, having its principal offices at 11610 North College Avenue, Cannel, Indiana 46032 (“IMPA or Licensee~)

WITNESSETH:

WHEREAS Louisville is the owner of the Trimble County Plant which includes Trimble County Unit 1, the Trimble County General Plant Facilities and the Trimble County Site; and

WHEREAS Illinois Municipal Electric Agency (“IMEA”) owns an undivided 12.12 percent interest in Trimble County Unit 1; and

WHEREAS pursuant to the Participation Agreement dated February 1, 1993, by and between Louisville and IMPA (the “Participation Agreement”), the terms of which are incorporated by reference herein, Louisville has sold to IMPA, and IMPA has purchased from Luisville a 12.88% undivided ownership interest in Trimble County Unit 1 as tenants in common; and

WHEREAS IMPA desires to obtain a nonexclusive license to use the Trimble County General Plant Facilities on the Trimble County Site in a manner consistent with IMPA’s ownership interest and so long as it may hold its interest in Trimble County Unit 1.

NOW THEREFORE, in consideration of the mutual covenants and promises herein contained, the parties agree as follows:

1.DEFINITIONS:

The terms Trimble County Unit 1, Trimble County General Plant Facilities, Trimble County Site and Trimble County Plant as used herein shall be defined as set forth in the Participation Agreement.

2.GRANT:

Upon the terms, payments and conditions set forth in the Participation Agreement, incorporated herein by reference, Louisville hereby grants to IMPA a nonexclusive license to use the Trimble County General Plant Facilities to the extent necessary for efficient and full use by IMPA of its proportional ownership interest in Trimble County Unit 1. Louisville shall retain full ownership of the Trimble County General Plant Facilities.

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3.USE

a)IMPA covenants that its use of the Trimble County General Plant Facilities pursuant to the license granted herein will be consistent with the Participation Agreement and otherwise in full compliance with all applicable laws, ordinances, statutes, codes, easements and restrictions.

b)IMPA acknowledges that this nonexclusive license shall in no way restrict or prohibit Louisville from constructing additional units or facilities or expanding present units or facilities in a manner consistent with the Participation Agreement.

4.DURATION AND TERMINATION

Unless otherwise terminated by mutual agreement of the parties, this Agreement and the license granted herein shall continue in full force and effect until the expiration or termination of the Participation Agreement.

5.NOTICES

All notices, requests and demands and other communications given or made in connection with this Agreement, shall be given or made pursuant to and, in accordance with, the Participation Agreement.

6.CONSTRUCTION AND ASSIGNMENT

a)This Agreement shall be binding on and inure to the benefit of the Licensor, its legal representatives, successors, heirs and assigns.

b)This Agreement shall be binding on and inure to the benefit of the Licensee, but shall not be transferable or assignable by the Licensee except as permitted by and consistent with the Participation Agreement.

c)This Agreement shall be deemed to be a contract made under the laws of the Commonwealth of Kentucky, and shall be construed and interpreted according to the laws of said state.

7.MODIFICATION:

This Agreement and the Participation Agreement embody all the understandings and obligations between the parties with respect to the subject matter hereof. No amendment or modification of this Agreement shall be valid or binding upon the parties unless made in writing and signed on behalf of each of the parties by their respective proper officers, duly authorized.

IN WITNESS WHEREOF, the parties caused this Agreement to be executed as of the date first written above.

67

LOUISVILLE GAS AND ELECTRIC COMPANY
By:
	Chris
	Vice President and General Manager,
	Wholesale Electric Business
INDIANA MUNICIPAL POWER AGENCY
By
	Frank R. Rudolph,
	Chairman

68

List of Trimble County General Plant Facilities

STRUCTURES

A.	Service Building
	1.	Concrete
		a.	Foundations
		b.	Base Slab
		c.	Elevated Floors
		d.	Unloading Ramps
	2.	Steel Structures
		a.	Columns & Girders
	3.	Enclosures
		a.	Insulated Metal Siding
		b.	Glass Curtain Wall
		c.	Concrete & Built-Up Roof
B.	As Fired Sample House
	1.	Concrete
		a.	Foundations
		b.	Base Slab
		c.	Elevated Floors
	2.	Steel Structures
		a.	Columns & Girders
		b.	Stairways
		c.	Grating
	3.	Enclosures
		a.	Insulated Metal Siding
		b.	Concrete & Built-Up Roofing
C.	Screenwell
	1.	Piles
		a.	Sheet Piles
		b.	H-Piles
	2.	Concrete
		a.	Walls
		b.	Elevated Floors
	3.	Steel Structures
		a.	Columns & Girders
		b.	Miscellaneous Platforms
	4.	Enclosures
		a.	Insulate Metal Siding
		b.	Concrete & Built-Up Roof
D.	Stack
	1.	Concrete

69

		a.	Foundations
		b.	Base Slab
		c.	Concrete Shell & Liner
E.	Coal Handling
Barge Unloader
	1.	Piles
		a.	Sheet Piles
		b.	H-Piles
	2.	Steel Structures
		a.	Columns & Girders
		b.	Stairways
Transfer House
	1.	Concrete
		a.	Foundations
		b.	Base Slab
	2.	Steel Structures
		a.	Columns & Girders
	3.	Enclosures
		a.	Uninsulated Metal Siding
		b.	Concrete & Built-Up
As Delivered Sample House
	1.	Concrete
		a.	Foundations
		b.	Base Slab
		c.	Elevated Floors
		d.	Equipment Foundations
	2.	Steel Structures
		a.	Columns & Girders
	3.	Enclosures
		a.	Uninsulated Metal Siding
		b.	Concrete & Built-Up Roofing
	Coal Dock Electrical Service Building
	1.	Concrete

70

		a.	Foundations
		b.	Base Slab
	2.	Steel Structures
		a.	Pre-Engineered Building
Radial Stacker
	1.	Concrete
		a.	Base Slab Rail
Reclaim Hopper & Tunnel
	1.	Concrete
		a.	Foundations
		b.	Base Slab
		c.	Wails
		d.	Elevated Slab
		e.	Access Stairway
Crusher House
	1.	Concrete
		a.	Foundations
		b.	Base Slab
		c.	Elevated Floors
		d.	Equipment Foundations
	2.	Steel Structures
		a.	Columns & Girders K Stairways
	3.	Enclosures
		a.	Uninsulated Metal Siding Crusher House Electrical Building
	1.	Concrete
		a.	Foundations
		b.	Base Slab
	2.	Steel Structures
		a.	Pre-Engineered Building
Coal Maintenance Building
	1.	Concrete
		a.	Foundations

71

		b.	Base Slab
	2.	Steel Structures
		a.	Pre-Engineered Building
Conveyors A, B, C, D, E, & S
	1.	Piles
		a.	Bearing Piles
	2.	Concrete
		a.	Foundations
	3.	Steel Structures
		a.	Steel Trusses
		b.	Conveyor Bents
		C.	Stairways
	4.	Enclosures
		a.	Conveyor Uninsulated Metal Siding
Conveyors Fl, F2, Gi, and G2
	1.	Concrete
		a.	Foundations
	2.	Steel Structures
		a.	Steel Trusses
		b.	Conveyor Bents
		c.	Stairways
		d.	Gallery Steel Enclosure
	3.	Enclosures
		a.	Gallery Uninsulated Metal Siding
F.	Reactant Handling Barge Unloader
	1. Piles
		a.	Sheet Piles
		b.	H-Piles
	2.	Steel Structures
		a.	Columns & Girders
		b.	Stairways
	3.	Enclosures

72

		a.	Uninsulated Metal Siding
Transfer House
	1. Concrete
		a.	Foundations
		b.	Base Slab
		c.	Elevated Floors
	2.	Steel Structures
		a.	Columns & Girders
	3.	Enclosures
		a.	Insulated Metal Siding
Live Action Pile Enclosure
	1.	Concrete
		a.	Foundations
		b.	Base Slab - Rail
	2.	Steel Structures
		a.	A-Frame Structural Steel
	3.	Enclosures
		a.	Uninsulated Metal Siding
Dead Storage Pile
	1.	Concrete
		a.	Foundations
		b.	Base Slabs
		c.	Walls
		d.	Elevated Slab
		e.	Access Stairway
Conveyors A, B, and C
	1.	Concrete
		a.	Foundations
	2.	Steel Structures
		a.	Steel Trusses
		b.	Conveyor Bents
		c.	Stairways

73

Reactant Prep. Building
	1.	Concrete
		a.	Foundations
		b.	Base Slab
		c.	Elevated Floors
		d.	Equipment Foundations
	2.	Steel Structures
		a.	Columns & Girders
		b.	Stairways
	3.	Enclosures
		a.	Insulated Metal Siding
		b.	Concrete & Built-Up Roofing
Reactant Live Storage Tanks
	1.	Concrete
		a.	Foundations
	2.	Steel Structures
		a.	Carbon Steel Tanks
G.	Water Treatment Building
	1.	Concrete
		a.	Foundations
		b.	Base Slabs
		c.	Walls
		d.	Equipment Foundations
	2.	Steel Structures
		a.	Columns & Girders
		b.	Stairways
		c.	Equipment Platforms
	3.	Enclosures
		a.	Insulated Metal Siding
H.	Cooling Tower
	1. Concrete
		a.	Foundations
		b.	Base Slabs
		c.	Poured Hyperbolic Natural Draft Tows

74

I.	Station Auxiliary
1. Concrete
	a.	Equipment Foundations

EQUIPMENT AND SYSTEM COMPONENTS
A.	Service Building
	1.	Masonry Blockwork
	2.	Fire Protection Equipment
	3.	Restrooms, Lockers, and Showers
	4.	HVAC
	5.	Roof Drains and Plumbing
	6.	Lighting
	7.	Communications
	8.	Office, Lab, and Kitchen Equipment
	9.	Maintenance Shop Equipment
	10.	Material Storage Bins and Shelves
	11.	Freight Elevator
	12.	Passenger Elevator
B.	As Fired Sample House
	1.	HVAC
	2.	Building Drains
	3.	Fire Protection
	4.	Lighting
	5.	Communications
	6.	Coal Silos
	7.	Piping Systems
C.	Screenwell
	1.	Masonry Blockwork
	2.	Multiplex System
	3.	HVAC
	4.	Horizontal Pumps
	5.	Vertical Pumps
	6.	Traveling Water Screens
	7.	Stop Log Gates and Screens
	8.	Bridge Crane
	9.	Strainers
	10.	480 Volt Equipment

75

	11.	208/110 Volt Equipment
	12.	Conduit and Cable Tray
	13.	Lighting
	14.	Communications
	15.	Multiplex System
	16.	Roof Drains and Plumbing
D.	Stack
	1.	Communications
E.	Coal Handling
	1.	Coal Barge Unloader
	2.	Conduit and Cable Tray
	3.	Lighting
	4.	Communications
Transfer House
	1.	Barge Unloader Bin
	2.	Feeders and Chutes
	3.	Dust Collection/Suppression Equipment
	4.	Sprinkler System
	5.	Monorail and Trolley Hoist
	6.	Conduit and Cable Tray
	7.	Lighting
	8.	Communications
As Delivered Sample House
	1.	Feeders and Chutes
	2.	Dust Collection/Suppression Equipment
	3.	As Delivered Sampling System
	4.	Sprinkler System
	5.	Control Room - Static Wall Siding
	6.	Fire Protection System
	7.	Conduit and Cable Tray
	8.	Lighting
	9.	Communications
Coal Dock Electrical Service Building
	1.	Masonry Blockwork
	2.	Suspended Ceiling
	3.	Static Wall Siding

76

	4.	HVAC
	5.	Fire Protection System
	6.	Domestic Piping
	7.	Conduit and Cable Tray
	8.	Lighting
	9.	Communications
	10.	4160 Volt Equipment
	11.	480 Volt Equipment
	12.	208/110 Volt Equipment
	13.	Multiplex System
Radial Stacker
	I.	Radial Stacker
	2.	HVAC Equipment
	3.	Unit Substation
	4.	Motor Control Centers
Reclaim Hopper and Tunnel
	1. Hopper
	2.	Feeders and Chutes
	3.	Vertical Pumps
	4.	Conduit and Cable Tray
	5. Lighting
Crusher House
	1.	Feeders and Chutes
	2.	Crusher Bin
	3.	Dust Collection/Suppression Equipment
	4.	Magnetic Separators and Scales
	5.	Crusher
	6.	Conduit and Cable Tray
	7.	Lighting
	8.	Communications
	9.	Piping Systems
Crusher House Electrical Building
	1.	Masonry Walls
	2.	Static Wall Siding
	3.	Fire Protection Equipment
	4.	Domestic Water
	5.	Conduit and Cable Tray
	6.	Lighting
	7.	Communications

77

	8.	Piping Systems
	9.	4160 Volt Equipment
	10.	480 Volt Equipment
	11.	208/110 Volt Equipment
	12.	Multiplex System
Coal Maintenance Building
	1.	Masonry Blockwork
	2.	Suspended Ceiling
	3.	Dry Wall Partitions
	4.	HVAC
	5.	Sprinkler System
	6.	Hoist and Lifts
F.	Reactant Handling Barge Unloader
	1.	Limestone Barge Unloader
	2.	Conduit and Cable Tray
	3.	Lighting
	4.	Communications
Transfer House
	1.	Feeders
	2.	Hoppers
	3.	Piping Systems
	4.	Conduit and Cable Tray
	5.	Lighting
Live Active Pile Enclosure
	1.	Reclaimer
	2.	Conduit and Cable Tray
	3.	Lighting
Dead Storage Pile
	1.	Hopper
	2.	Chutes and Feeders
	3.	Sump Pumps
	4.	Conduit and Cable Tray
	S.	Lighting
Reactant Prep. Building

78

	1.	Masonry Blockwork
	2.	HVAC Equipment
	3.	Fire Protection Equipment
	4.	Piping Systems
	5.	Limestone Crushers and Hoppers
	6.	Compressors
	7.	Lube Oil Systems
	8.	Feeders and Chutes
	9.	Bridge Crane
	10.	4160 Volt Equipment
	11.	480 Volt Equipment
	12.	208/110 Volt Equipment
	13.	Conduit and Cable Tray
	14.	Lighting
	15.	Communications
	16.	Multiplex System
Reactant Live Storage Tanks
	1.	Tank Agitators
G.	Water Treatment Building
	1.	Masonry Blockwork
	2.	Static Wall Siding
	3.	HVAC
	4.	Fire Protection Equipment
	S.	Monorail
	6.	Piping Systems
	7.	Sanitary Waste Treatment Equipment
	8.	Water Treatment Equipment
	9.	Condensate Storage Tank
	10.	Conduit and Cable Tray
	11.	4160 Volt Equipment
	12.	480 Volt Equipment
	13.	208/110 Volt Equipment
	14.	Lighting
	15.	Communications
	16.	Multiplex System
	17.	Motor Driven Fire Pump
	18.	Chemical Injection Equipment
	19.	Demineralizer Water System
H.	Cooling Tower
	1.	Cooling Tower Pumps

79

	2.	Circulating Water Lines
	3.	Condenser
	4.	480 Volt Equipment
	5.	Lighting
	6.	Communications
I.	Station Auxiliary
	1.	138 Volt Equipment
	2.	6900 Volt Equipment
	3.	480 Volt Equipment
	4.	208/110 Volt Equipment
	5.	Sprinkler System
OTHER EQUIPMENT, SYSTEMS, AND STRUCTURES
1.		Fuel Oil Tanks, Piping, Pump House, and Electrical Building
2.		Ash Pond, Pipe Rack, and Pipe
3.		Emergency Ash Pond
SITE IMPROVEMENTS
1.	General Site Grating and Drainage
2.	Helicopter Pad
3.	Monitoring Wells
4.	Roadways
5.	Guard Facilities
6.	Underground Electrical Ducts
7.	Sanitary Sewer Lines
8.	Shoreline Protection
9.	Fire Protection Lines
10.	Potable Water Lines
11.	Cathodic Protection

80

APPENDIX D

KNOWN DEFECTS AT CLOSING

The attached list of known defects for Trimble County Unit I and the Trimble County General Plant Facilities as they pertain to Trimble County Unit 1 includes items for which construction is not complete as well as items where a deficiency is noted, and to the best of Louisville’s knowledge, information, and belief the attached list is current as of Closing.

LOUISVILLE GAS AND ELECTRIC COMPANY
By:
	Chris Hermann
	Vice President and General Manager
	Wholesale Electric Business

81

KNOWN DEFECTS AND OPEN WARRANTY CLAIMS AT CLOSING

Known design defects:

•Replace boiler penthouse roof and sidewalls. Original roof was installed with non-specification material.

Open warranty claims:

•Replace FGD module purge air and vent dampers. (ABB)

•Modify demister wash lance seals. (ABB)

•Redesign precipitator high voltage insulator compartment heater/blower system. (ABB)

•Replace generator field breaker. (GE)

•Replace boiler feed pump turbine turning gears. (GE)

•Modify FGD pump bay trolley system. (ABB)

•Modify induced draft fan variable-frequency drive speed-control circuit. (Ross Hill)

•Backcharge for repair work on induced draft fan motors (Buffalo Forge)

82

APPENDIX E

DEED

THIS DEED is made and entered into this 1st day of February, 1993, by and between LOUISVILLE GAS AND ELECTRIC COMPANY, a Kentucky corporation, of 220 West Main Street, P.O. Box 32010, Louisville, Kentucky 40232 (“Grantor”) and INDIANA MUNICIPAL POWER AGENCY, a body corporate and politic and a political subdivision of the State of Indiana, of 11610 North College Avenue, Carmel, Indiana 46032 (“Grantee”).

WITNESSETH:

That for and in consideration of the sum of Seven Million Two Hundred Eight Thousand Seven Hundred and Fifty~Nine Dollars ($7,208,759.00) and other good and valuable consideration, the receipt of which is hereby acknowledged, Grantor has bargained and sold and does hereby grant and convey to Grantee in fee simple with covenant of GENERAL WARRANTY, the following described property located in Trimble County, Kentucky, being a 12.88~ undivided interest as tenants in common in the real property beneath Trimble County Unit 1 (“the Property”):

Being a certain parcel of land located to the north of Kentucky Highway 754 and to the west of Kentucky Highway 1838, north of Wise’s Landing in Trimble County, Kentucky and being more particularly described as follows:

Beginning at a 3 inch x 3 inch concrete monument in the northwest right-of-way line of Kentucky Highway 754 at its intersection with the west right-of-way of Wise’s Landing road; thence North 17° 30’ 19” West, 1925.28 feet to an iron pin being the True Point of Beginning Also known as plant grid coordinate N 32+50.00, E17+82.00; thence North 29° 02’ 25” West, 176.00 feet to a scribe mark in concrete and being plant grid coordinate N 34+26.00, E 17÷82.00, said line being Column Line N; thence North 60° 57’ 35” East, 42.00 feet to a scribe mark in concrete and being plant grid coordinate N34+26.00, E 18+24.00; thence North 4° 38’ 59” West, 42.27 feet to plant grid coordinate N 34+62.00, E 18+48.00; thence North 60° 57’ 35” East, 759.17 feet to plant grid coordinate N 34÷62.00, E 26+07.17, said line being Column Line 9, common line between Unit No. 1 and Unit No. 2 (Future); thence South 29° 02’ 25” East, 55.25 feet to a R R spike being plant grid coordinate N 34÷06.75, E 26+07.17; thence South 60° 57’ 35” West, 57.17 feet to plant grid coordinate N 34+06.75, E 25+50.00; thence South 29° 02’ 25” East, 156.75 feet to plant grid coordinate N 32÷50.00, E 25÷50.00, said line being Column Line A; thence South 60° 57’ 35” West, 768.00 feet to the True Point of Beginning, said line being Column’s Line 17, common column line between Unit No. 1 and the Service Building. Said tract containing 3.766 acres. Being a part of the same conveyed to Grantor by deed of record in the office of the Trimble County Clerk in Deed Book No. 49, Page No. 602.

TO HAVE AND TO HOLD the Property, with all appurtenances and privileges thereunto belonging, unto the Grantee, its successors and assigns.

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Grantor covenants that it is lawfully seized of fee simple title to the Property and has full right and power to convey same, subject to the rights of Illinois Municipal Electric Agency (“IMEA”) which owns a 12.12% undivided interest as tenants in common and subject to the Participation Agreement dated February 28, 1991 by and between Grantor and IMEA and the Participation Agreement dated February 1, 1993, by and between Grantor and Grantee and incorporated by reference herein, memoranda of which are on file in the Office of the Trimble County Clerk, which contain, among other things, certain restrictions on resale of the Property, the right Q~ first refusal upon transfer of the Property, the right of IMEA and Grantee to participate in the ownership of the next generating unit built at the Trimble County Site, and waiver of the right of partition of the Property, and otherwise the Property is free and clear of all encumbrances except those relating to the IMEA sale that are of record and all ad valorem taxes and assessments assessed against the Property for 1993 • and all subsequent years which Grantee assumes and agrees to pay.

IN TESTIMONY WHEREOF, witness the signature of the Grantor as of the day, month and year first above-written.

LOUISVILLE GAS AND ELECTRIC COMPANY
By:
	Chris Hermann
	Vice President and General Manager
	Wholesale Electric Business

84

CONSIDERATION CERTIFICATE

Grantor and Grantee hereby certify that the consideration reflected in the foregoing Deed is the full consideration paid for the Property.

LOUISVILLE GAS AND ELECTRIC COMPANY
By:
		Chris
		Vice President and General Manager,
		Wholesale Electric Business
INDIANA MUNICIPAL POWER AGENCY
By
	Frank R. Rudolph,
	Chairman

COMMONWEALTH OF KENTUCKY	)
	)(SS
COUNTY OF JEFFERSON	)

The foregoing Deed and Consideration Certificate were signed, acknowledged and sworn to before me on this 29th day of January, 1993, by Chris Hermann , Vice President and General Manager, Wholesale Electric Business of LOUISVILLE GAS AND ELECTRIC COMPANY, a Kentucky corporation, on behalf of the corporation.

My Commission expires:
	Notary Public
	State of Kentucky at Large

85

STATE OF INDIANA	)
	)SS
COUNTY OF HAMILTON	)

The foregoing Consideration Certificate was signed, acknowledged and sworn to before me on this 29th day of January , 1993 , by Frank R. Rudolf, as Chairman of Indiana Municipal Power Agency, a body corporate and politic and a political subdivision of the State of Indiana, on behalf of the corporation.

My Commission expires:
	Notary Public
	State of Indiana

(AFFIX SEAL]

THIS INSTRUMENT PREPARED BY:

C. Kent Hatfield

John M. Franck II

MIDDLETON & REUTLINGER

2500 Brown & Williamson Tower

Louisville, Kentucky 40202

Telephone (502) 584-1135

86

APPENDIX F

EASEMENT

THIS EASEMENT dated the 1st day of February, 1993, by and between LOUISVILLE GAS AND ELECTRIC COMPANY, a Kentucky corporation located at 220 West Main Street, P.O. Box 32010, Louisville, Kentucky 40232, (the “Grantor”) , and INDIANA MUNICIPAL POWER AGENCY, a body corporate and politic and a political subdivision of the State of Indiana, located at 11610 North College Avenue, Carmel, Indiana 46032 (the “Grantee”).

FOR A VALUABLE CONSIDERATION, the receipt of which is hereby acknowledged, Grantor does hereby grant and convey unto Grantee, its successors and assigns, a nonexclusive easement to use the Trimble County Site to the extent necessary for use by Grantee with respect to its proportional ownership of Trimble County Unit 1 as defined in the Participation Agreement by and between Grantor and Grantee dated February 1, 1993 (“Participation Agreement”) . The Trimble County Site is located in Trimble County, Kentucky (the “Burdened Property” ) , as shown on Exhibit “A” attached hereto and made a part hereof. The Burdened Property was conveyed to Grantor by Deeds referenced on Exhibit “B” attached hereto and made a part hereof.

Grantor grants this easement upon the following terms and conditions:

1.Participation Agreement. Grantee will at all times abide by the terms of the Participation Agreement.

2.Use by Grantee. The Burdened Property may be used by Grantee only for the purposes consistent with the terms of the Participation Agreement.

3.Use by Grantor. Grantor reserves the right to fully use and enjoy the Burdened Property as well as to transfer or convey portions thereof for any use or purpose which does not unreasonably interfere with the exercise by Grantee of the rights granted by the Participation Agreement. Should Grantee’s release of this Easement be requested as to such portions transferred or conveyed, such release shall not be unreasonably withheld. Grantee acknowledges that this nonexclusive easement shall in no way restrict or prohibit Grantor from constructing additional generating units or facilities or expanding present units or facilities which shall also have a nonexclusive use of the Trimble County Site, to the extent necessary and as determined in Grantor’s sole discretion.

4.Indemnification. Grantee will indemnify and hold Grantor harmless from and against any and all losses, liabilities, costs, expenses, damages, claims, and causes of action whatsoever, including reasonable attorney’s fees, arising from this Easement.

5.Binding Effect. This Easement shall be binding upon and inure to the benefit of Grantor and Grantee, and their respective successors and assigns, but shall not be transferable or assignable by Grantee except as permitted by and consistent with the Participation Agreement.

6.Termination. This Easement shall terminate (i) upon the mutual agreement of Grantor and Grantee, or (ii) if Trimble County Unit 1 ceases to be used or is abandoned, or (iii)

87

upon the failure by Grantee to remedy any default in the performance of any term or condition of the Participation Agreement, or (iv) upon termination of the Participation Agreement .

7.Release. Upon termination of this Easement, Grantee shall execute and deliver to Grantor within ten (10) days of written demand therefor, a good and sufficient quitclaim deed to all rights granted hereby. If Grantee fails or refuses to deliver such deed, written notice by Grantor reciting the failure or refusal of Grantee and terminating this grant, shall after thirty (30) days from the date of recording be conclusive evidence against Grantee and all persons claiming under Grantee, of the termination of this Easement.

8.Matters of Record. This Easement is subject to all easements, restrictions and other matters of record.

IN WITNESS WHEREOF, the parties hereto have executed this Easement on the date above set forth.

GRANTOR
LOUISVILLE GAS AND ELECTRIC COMPANY
By:
	Chris
	Vice President and General Manager, Wholesale Electric Business
GRANTEE
INDIANA MUNICIPAL POWER AGENCY
By
	Frank R. Rudolph,
	Chairman

88

COMMONWEALTH OF KENTUCKY	)
	)(SS
COUNTY OF JEFFERSON	)

The foregoing Deed and Consideration Certificate were signed, acknowledged and sworn to before me on this 29th day of January, 1993, by Chris Hermann , Vice President and General Manager, Wholesale Electric Business of LOUISVILLE GAS AND ELECTRIC COMPANY, a Kentucky corporation, on behalf of the corporation.

My Commission expires:
	Notary Public
	State of Kentucky at Large

STATE OF INDIANA	)
	)SS
COUNTY OF HAMILTON	)

The foregoing Consideration Certificate was signed, acknowledged and sworn to before me on this 29th day of January , 1993 , by Frank R. Rudolf, as Chairman of Indiana Municipal Power Agency, a body corporate and politic and a political subdivision of the State of Indiana, on behalf of the corporation.

My Commission expires:
	Notary Public
	State of Indiana

(AFFIX SEAL]

THIS INSTRUMENT PREPARED BY:

C. Kent Hatfield

John M. Franck II

MIDDLETON & REUTLINGER

2500 Brown & Williamson Tower

Louisville, Kentucky 40202

Telephone (502) 584-1135

89

EXHIBIT A

Property Plat

90

EXHIBIT B

The following list of references are the sources of title wherein Louisville Gas and Electric Company acquired properties located in Trimble County as they pertain to the Trimble County Site. Deeds are of record in the Office of the Clerk of Trimble County, Kentucky.

1.DB 49 Page 602 Deed dated 4-30-1974 From Thomas Manby, Jr. Trustee. (Original Plant Site)

2.DB 51 Page 769 Deed Dated 4-16-1976 From Thomas Manby Jr. Trustee. (Part of Original Plant Site, located on North End of Site)

3.DB 58 Page 321 Deed Dated 11-29-1982 From Allison Schlegel Dickey & Dianna Dey Dickey. (Located on North End of Site)

4.DB 65 Page 424 Deed Dated 1-22~199O From Allison Schlegel Dickey & Dianna Dey Dickey. (Located on North End of Site)

5.DB 63 Page 615 Deed Dated 4-2O~-1988 From Charles G. Middleton III, Trustee. (Ravine Site)

91

APPENDIX G

EASEMENT

THIS EASEMENT dated the 1st day of July, 19 9 3 , by and between INDIANA MUNICIPAL POWER AGENCY, a body corporate and politic and a political subdivision of the State of Indiana, with its offices located at 11610 North College Avenue, Carmel, Indiana 46032 (the “Grantor”) and LOUISVILLE GAS AND ELECTRIC COMPANY, a Kentucky corporation, located at 220 West Main Street, P.O. Box 32010, Louisville, Kentucky 40232, (the “Grantee”)

FOR VALUABLE CONSIDERATION, the receipt of which is hereby acknowledged, Grantor does hereby grant and convey unto Grantee, its successors and assigns, a nonexclusive easement to use any real property owned by Grantor on the Trimble County Site to the extent necessary for use by Grantee and other owners with respect to their proportional ownership of Trimble County Unit 1 as defined in the Participation Agreement by and between Grantor and Grantee dated February 1, 1993 (“Participation Agreement”) . The property owned by Grantor at the Trimble County Site is located in Trimble County, Kentucky as shown on Exhibit “A” attached hereto and made a part hereof (the “Burdened Property”) . A 12.88 percent undivided interest as tenants in common of the Burdened Property was conveyed to Grantor by Deed dated February 1, 1993, of record in Deed Book       , Page       , in the Office of the Clerk of Trimble County, Kentucky.

Grantor grants this easement upon the following terms and conditions:

1.Participation Agreement.  Grantee will at all times abide by the terms of the Participation Agreement.

2 .Use by Grantee and Grantor .  The Burdened Property may be used only for the purposes consistent with the terms of the Participation Agreement.

3.Indemnification. Grantee will indemnify and hold Grantor harmless from and against any and all losses, liabilities, costs, expenses, damages, claims, and causes of action whatsoever, including reasonable attorney’s fees, arising from Grantee’s use of this Easement.

4.Binding Effect. This Easement shall be binding upon and inure to the benefit of Grantor and Grantee, and their respective successors and assigns, but shall not be transferable or assignable by Grantee except as permitted by and consistent with the Participation Agreement.

5.Termination. This Easement shall terminate (i) upon the mutual agreement of Grantor and Grantee, or (ii) if Trimble County Unit 1 ceases to be used or is abandoned or (iii) upon the failure by Grantee to remedy any default in the performance of any term or condition of the Participation Agreement, or (iv) upon termination of the Participation Agreement.

6.Release. Upon termination of this Easement, Grantee shall execute and deliver to Grantor within ten (10) days of written demand therefor, a good and sufficient quitclaim deed to all easement rights granted hereby. If Grantee fails or refuses to deliver such deed, written notice by

92

Grantor reciting the failure or refusal of Grantee and terminating this grant, shall after thirty (30) days from the date - - of recording be conclusive evidence against Grantee and all persons claiming under Grantee of the termination of this Easement.

7.Matters of Record. This Easement is subject to all easements, restrictions and other matters of record.

IN WITNESS WHEREOF, the parties hereto have executed this Easement on the date above set forth.

GRANTOR
LOUISVILLE GAS AND ELECTRIC COMPANY
By:
	Chris
	Vice President and General Manager, Wholesale Electric Business
GRANTEE
INDIANA MUNICIPAL POWER AGENCY
By
	Frank R. Rudolph,
	Chairman

93

COMMONWEALTH OF KENTUCKY	)
	)(SS
COUNTY OF JEFFERSON	)

The foregoing Deed and Consideration Certificate were signed, acknowledged and sworn to before me on this 29th day of January, 1993, by Chris Hermann , Vice President and General Manager, Wholesale Electric Business of LOUISVILLE GAS AND ELECTRIC COMPANY, a Kentucky corporation, on behalf of the corporation.

My Commission expires:
	Notary Public
	State of Kentucky at Large

STATE OF INDIANA	)
	)SS
COUNTY OF HAMILTON	)

The foregoing Consideration Certificate was signed, acknowledged and sworn to before me on this 29th day of January , 1993 , by Frank R. Rudolf, as Chairman of Indiana Municipal Power Agency, a body corporate and politic and a political subdivision of the State of Indiana, on behalf of the corporation.

My Commission expires:
	Notary Public
	State of Indiana

(AFFIX SEAL]

THIS INSTRUMENT PREPARED BY:

C. Kent Hatfield

John M. Franck II

MIDDLETON & REUTLINGER

2500 Brown & Williamson Tower

Louisville, Kentucky 40202

Telephone (502) 584-1135

94

EXHIBIT A

Being a certain parcel of land located to the north of Kentucky Highway 754 and to the west of Kentucky Highway 1838, north of Wise’s Landing in Trimble County, Kentucky and being more particularly described as follows:

Beginning at a 3 inch x 3 inch concrete monument in the northwest right-of-way line of Kentucky Highway 754 at its intersection with the west right- of -way of Wise “ s Landing road; thence North 17° 30’ 19” West, 1925.28 feet to an iron pin being the True Point of Beginning.  Also known as plant grid coordinate N 32+50.00, El7+82.00; thence North 29° 02’ 25” West, 176.00 feet to a scribe mark in concrete and being plant grid coordinate N 34+26.00, E 17+82.00, said line being Column Line N; thence North 60° 57’ 35” East, 42.00 feet to a scribe mark in concrete and being plant grid coordinate N34+26.00, E 18+24.00; thence North 4° 38’ 59” West, 42.27 feet to plant grid coordinate N 34+62.00, E 18+48.00; thence North 60° 57’ 35” East, 759.17 feet to plant grid coordinate N 34+62.00, E 26+07.17, said line being Column Line 9, common line between Unit No. 1 and Unit No. 2 (Future); thence South 29° 02’ 25” East, 55.25 feet to a R R spike being plant grid coordinate N 34+06.75, E 26+07.17; thence South 60° 57’ 35” West, 57.17 feet to plant grid coordinate N 34+06.75, E 25+50.00; thence South 29° 02’ 25” East, 156.75 feet to plant grid coordinate N 32+50.00, E 25+50.00, said line being Column Line A; thence South 60° 57’ 35” West, 768.00 feet to the True Point of Beginning, said line being Column Line 17, common column line between Unit No. 1 and the Service Building. Said tract containing 3.766 acres. Being a part of the same conveyed to Grantor by deed of record in the office of the Trimble County Clerk in Deed Book No.       , Page No.      .

95

EX-10.44

EXHIBIT 10.44

PARTICIPATION AGREEMENT

BY AND AMONG

LOUISVILLE GAS AND ELECTRIC COMPANY
220 West Main Street
Post Office Box 32010 (40232)
Louisville, Kentucky 40202

AND

KENTUCKY UTILITIES COMPANY
220 West Main Street
Post Office Box 32010 (40232)
Louisville, Kentucky 40202

AND

INDIANA MUNICIPAL POWER AGENCY
11610 North College Avenue
Carmel, Indiana 46032

AND

ILLINOIS MUNICIPAL ELECTRIC AGENCY
919 South Spring Street
Springfield, Illinois 62704

TABLE OF CONTENTS

ARTICLE 1. DEFINITIONS AND INTERPRETATION
	1.1	Definitions.
	1.2	Rules of Interpretation.
ARTICLE 2. OWNERSHIP
	2.1	Ownership.
	2.2	Additional Generating Units.
	2.3	Modification of Existing Property.
ARTICLE 3. DEVELOPMENT CLOSING
	3.1	Development Closing.
	3.2	Development Costs.
	3.3	Deliveries of Louisville at the Development Closing.
	3.4	Effect of Development Closing on Article 15 Rights.
ARTICLE 4. REPRESENTATIONS AND WARRANTIES
	4.1	IMPA Representations and Warranties.
	4.2	Louisville Representations and Warranties.
	4.3	Kentucky Utilities Representations and Warranties.
	4.4	IMEA Representations and Warranties.
ARTICLE 5. DEVELOPMENT AND CONSTRUCTION
	5.1	Responsibility for Development.
	5.2	Responsibility for Permits.
	5.3	Development Schedule.
	5.4	Authorization to Construct.
	5.5	Responsibility for Construction.
	5.6	Construction Schedule.
ARTICLE 6. CONSTRUCTION CLOSING AND WITHDRAWAL
	6.1	Construction Closing.
	6.2	Closing Actions.
		6.2.1Payment to Louisville.
		6.2.2Conveyance of Real Property.
		6.2.3Licenses and Easements.
		6.2.4Transaction Documents.
	6.3	Conditions Precedent.
	6.4	Deliveries at Construction Closing.
		6.4.1Payment of Funds by IMPA.
		6.4.2Payment of Funds by IMEA.
		6.4.3Payment of Funds by Kentucky Utilities.
		6.4.4General Warranty Deeds.
		6.4.5Licenses to Trimble County General Plant Facilities.

		6.4.6Non-Exclusive Easements of Trimble County Site.
		6.4.7Reserved.
		6.4.8Representations and Warranties.
		6.4.9Conditions.
		6.4.10Release from Lien of Louisville’s Indenture.
		6.4.11Opinion of Counsel for Louisville.
		6.4.12Opinion of Counsel for Kentucky Utilities.
		6.4.13Opinion of Counsel for IMPA.
		6.4.14Opinion of Counsel for IMEA.
		6.4.15Transaction Documents.
		6.4.16Title Commitment.
		6.4.17Property Taxes.
	6.5	Withdrawal.
		6.5.1Withdrawal Prior to Construction Closing.
		6.5.2Withdrawal of IMPA or IMEA.
		6.5.3Withdrawal by the Companies or IMPA and IMEA.
		6.5.4No Withdrawal During Construction Phase.
		6.5.5Breach by IMPA or IMEA During the Construction Phase.
		6.5.6CCNs Not Filed.
ARTICLE 7. OPERATING ARRANGEMENTS
	7.1	Authority for Operation and Management.
	7.2	Electric Capacity Entitlements.
	7.3	Scheduling and Dispatching of Electric Generation.
		7.3.1Submittal of Schedules.
		7.3.2Scheduling Procedures
		7.3.3Utilization of Electric Capacity Entitlement and Companies’ System  Power.
		7.3.4Dispatching Procedures.
		7.3.5Ancillary Services.
		7.3.6Holidays.
		7.3.7Records.
		7.3.8Outage Schedules.
	7.4	Pre-Commercial Energy.
	7.5	Operations Management.
		7.5.1Administration of Operating Work and Incremental Capital Assets.
		7.5.2Purchasing Necessary Goods and Services.
		7.5.3Procurement of Fuel.
		7.5.4Expenditure of Funds.
		7.5.5Insurance.
		7.5.6Enforcement of Claims.
		7.5.7Processing Claims.
		7.5.8Delivery of Operating Data.
	7.6	Environmental Laws and Regulations.
	7.7	Environmental Fines and Penalties.
	7.8	General Facilities and Constraints.
	7.9	Rules and Regulations in Industry Practices.

ii

ARTICLE 8. INCREMENTAL CAPITAL ASSETS
	8.1	Estimate of Costs.
	8.2	Responsibility for Costs.
ARTICLE 9. EXPENSES
	9.1	Payment of Expenses and Charges Prior to the Commercial Operation Date.
	9.2	Monthly Expenses and Charges After the Commercial Operation Date.
		9.2.1Fuel/Reactant Operation Expenses.
		9.2.2Fixed Operation and Maintenance Expenses.
		9.2.3Non-Fuel Operating Component.
		9.2.4Working Capital Component.
ARTICLE 10. BILLING, PAYMENTS, AND RECORDS
	10.1	Payments before Commercial Operation Date.
	10.2	Billings by the Companies after the Commercial Operation Date.
	10.3	Payments after the Commercial Operation Date.
	10.4	Records.
	10.5	Timing of Certain Payments.
	10.6	Payment to Specified Account.
ARTICLE 11. INTERCONNECTION AND TRANSMISSION SERVICES
ARTICLE 12. TAXES
	12.1	Management of Tax Matters.
	12.2	Sharing of Taxes and Related Payments
	12.3	Payment of Title Taxes and Fees.
	12.4	Exclusion of Income Taxes.
	12.5	Non-creation of Taxable Entity.
ARTICLE 13. INSURANCE
	13.1	Procurement of Insurance.
		13.1.1Sharing of Insurance Costs.
		13.1.2The Parties Named as Insured.
		13.1.3Procurement of Additional Insurance for the Parties.
		13.1.4Sharing of Refunds from Insurance Premiums.
		13.1.5Sharing of Insurance Proceeds.
	13.2	Destruction.
		13.2.1Damage or Destruction Fully Covered By Insurance.
		13.2.2Damage or Destruction Not Fully Covered by Insurance.
ARTICLE 14. PARTITION OF OR TRANSFERS OF INTEREST
	14.1	Special Nature of Trimble County Unit 2 Project - Waiver of Right of Partition.
	14.2	Transfer of Ownership Interests.
		14.2.1Conditions of Transfer.
		14.2.2Further Conditions of Transfer.
		14.2.3Non-applicability of Certain Provisions.
		14.2.4Transfer of Associated Rights and Interests.

iii

		14.2.5Louisville and Kentucky Utilities.
ARTICLE 15. ASSIGNMENT
	15.1	Limitation of Assignability.
	15.2	Successors and Assigns.
ARTICLE 16. LIABILITY AND DEFAULT
	16.1	Liability to Third Parties.
	16.2	Liability Among the Parties; No Consequential Damages.
	16.3	Indemnification.
	16.4	Nature and Survival of Representations and Warranties.
	16.5	Default.
		16.5.1Events of Default.
		16.5.2Curing Event of Default in Regard to Paying Money.
		16.5.3Curing Event of Default for Other Than Failure to Pay Money.
		16.5.4Non-Applicability of Cure Provisions.
		16.5.5Appointment of a Receiver.
		16.5.6Additional Obligations.
		16.5.7Notice.
	16.6	Force Majeure.
ARTICLE 17. MANAGEMENT
	17.1	Coordination Committee.
	17.2	Coordination Committee Formation.
	17.3	Powers of Coordination Committee.
	17.4	Budget Approval.
		17.4.1Development Budget.
		17.4.2Construction Budget.
		17.4.3Annual Capital Budget.
		17.4.4Operation and Maintenance Budget.
	17.5	Vote by Coordination Committee.
	17.6	Meetings.
	17.7	Records.
	17.8	Amendments.
	17.9	Information.
ARTICLE 18. DISAGREEMENT
	18.1	Consultation.
	18.2	Disagreement.
	18.3	Arbitration.
	18.4	Obligations To Make Payments.
	18.5	Interest.
ARTICLE 19. REMEDIES
	19.1	All Remedies - Setoff.
	19.2	Injunctive Relief and Specific Performance.
	19.3	No Remedy Exclusive.

iv

	19.4	Failure to Participate in Incremental Capital Assets.
	19.5	Failure to Participate in Construction Costs.
ARTICLE 20. MISCELLANEOUS
	20.1	Governing Law.
	20.2	Notice to Parties.
	20.3	Article Headings Not to Affect Meaning.
	20.4	Counterparts.
	20.5	Emergency.
	20.6	Severability.
	20.7	Integration.
	20.8	Computation of Time.
	20.9	Waiver.
	20.10	Equal Opportunity Clause.
	20.11	Inflation.
	20.12	Condemnation.
	20.13	Americans with Disabilities Act.
	20.14	Amendments.
	20.15	No Agency or Third Party Beneficiary.
	20.16	Obligations Are Several.
	20.17	Cooperation.
	20.18	Intent.
	20.19	Approvals.
	20.20	Access.
	20.21	Further Assurances.
	20.22	Joint Effect.
	20.23	Certain Costs.
	20.24	Good Utility Practice.
	20.25	Affiliate Transactions.
ARTICLE 21. TERM AND TERMINATION
	21.1	Termination.
		21.1.1Retirement.
		21.1.2Construction Closing Does Not Occur.
		21.1.3Withdrawal of the Companies.
		21.1.4Withdrawal of IMPA and IMEA.
	21.2	Retirement of Property.
	21.3	Retirement Costs.
	21.4	Effect of Withdrawal or Transfer on Agent.

APPENDICES

Appendix A	Trimble County Unit 2
Appendix B	Trimble County General Plant Facilities
Appendix C	Form of License Agreement
Appendix D	Certain Development Costs
Appendix E	Form of Deed

v

Appendix F	Form of Easement
Appendix G	Estimated Interconnection Costs
Appendix H	Approved Development Budget
Appendix I	Interconnection and Operating Agreement

vi

PARTICIPATION AGREEMENT

This Participation Agreement, dated as of February 9, 2004, is among Louisville Gas and Electric Company, a Kentucky corporation (“Louisville” or a “Party”), Kentucky Utilities Company, a Kentucky corporation (“Kentucky Utilities” or a “Party”), Indiana Municipal Power Agency, a body corporate and politic and a political subdivision of the State of Indiana (“IMPA” or a “Party”), and Illinois Municipal Electric Agency, a body politic and corporate, municipal corporation and unit of local government of the State of Illinois (“IMEA” or a “Party,” and, collectively with Louisville, Kentucky Utilities and IMPA, the “Parties”).

WHEREAS, Louisville and Kentucky Utilities each are regulated public utilities that own and operate facilities for the generation, transmission, and distribution of electric power and energy in their respective service territories; and

WHEREAS, IMPA is a joint agency and is authorized to own and operate electric generation and transmission facilities to supply power and energy to its members; and

WHEREAS, IMEA is a joint action agency and is authorized to own and operate electric generation and transmission facilities to supply power and energy to its members; and

WHEREAS, Louisville and IMEA are party to that certain Participation Agreement, dated September 24, 1990 (the “IMEA Participation Agreement”), pursuant to which, among other things, IMEA acquired from Louisville: a twelve and twelve one-hundredths percent (12.12%) undivided ownership interest, as a tenant in common, in a four hundred ninety-five (495) megawatt coal-fired generating unit (“Trimble County Unit 1”) located at the Trimble County Generating Station operated by Louisville; a non-exclusive license to use certain of the general plant facilities; and a non-exclusive easement over a certain portion of the site on which the Trimble County Generating Station is located pertaining to IMEA’s use of Trimble County Unit 1; and

WHEREAS, Louisville and IMPA are party to that certain Participation Agreement (the “IMPA Participation Agreement”) dated February 1, 1993, pursuant to which, among other things, IMPA acquired from Louisville: a twelve and eighty-eight one-hundredths percent (12.88%) undivided ownership interest as a tenant in common in Trimble County Unit 1; a non-exclusive license to use certain of the general plant facilities; and a non-exclusive easement over a certain portion of the site on which the Trimble County Generating Station is located pertaining to IMPA’s use of Trimble County Unit 1; and

WHEREAS, the IMEA Participation Agreement and the IMPA Participation Agreement (collectively, the “Unit 1 Participation Agreements”) each provide certain rights of first refusal in favor of IMEA and IMPA, respectively, to participate in ownership in the event that Louisville shall apply to the Kentucky Public Service Commission for a certificate of public convenience and necessity for the installation at the Trimble County Site of a second coal-fired generating unit for use by its system as a base-load plant; and

WHEREAS, Louisville, together with Kentucky Utilities, is currently contemplating the design, procurement and construction of a second coal-fired base-load generating unit at the Trimble County Site and anticipates applying for CCNs therefor in calendar year 2004; and

WHEREAS, IMEA and IMPA desire to participate in the ownership of such second coal-fired generating unit.

NOW, THEREFORE, in consideration of the premises and of the mutual covenants herein set forth, and subject to the terms and conditions herein set forth, the Parties agree as follows:

ARTICLE 1.
DEFINITIONS AND INTERPRETATION

1.1Definitions.

Affiliate.  An “affiliate” of, or a Person “affiliated with” a specified Person, is a Person that directly or indirectly, through one or more intermediaries, controls, is controlled by, or is under common control with the Person specified.  The term “control” (including the terms “controlling,” “controlled by,” and “under common control with”) means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through the ownership of voting securities, by contract, or otherwise.

Affiliate Contract.  Affiliate Contract has the meaning specified in Article 20.25.

Agreed Rate.  The lesser of (i) two (2) percent per annum above the “Prime Rate” as published in the “Money Rates” table of The Wall Street Journal from time-to-time and (ii) the maximum rate of interest permitted by Applicable Law.

Agreement.  This Participation Agreement among Louisville, Kentucky Utilities, IMPA and IMEA dated as of the date set forth in the first paragraph of this Agreement.

Annual Capital Budget.  Annual Capital Budget has the meaning specified in Section 17.4.3.

Annual O&M Budget.  Annual O&M Budget has the meaning specified in Section 17.4.4.

Applicable Law.  Any applicable statute, law, treaty, rule, code, ordinance, regulation, permit, license, approval, interpretation, certificate or order of any Governmental Authority, or any judgment, decision, decree, injunction, writ, order or like action of any court, arbitrator or other Governmental Authority.

Applicable Transmission Provider.  The Midwest Independent System Operator, its successor or other applicable transmission provider or transmission arrangement applicable to a Party.

2

Attributes.  The attributes of Trimble County Unit 2 (e.g., capacity, ramp rate, ancillary services, etc.).

Authorization to Construct.  Authorization of the Coordination Committee pursuant to Article 17.3(x) for the Companies to commence the Construction Work (or to issue full releases under contracts pursuant to which limited Work has been released) on the date of the Construction Closing, and thereafter pursue the Construction Work, including executing (or releasing Construction Work under) final design, equipment and construction contracts authorizing equipment procurement and installation, and authorizing or performing all other necessary activities and procurements to commence and complete construction, start-up and interconnection of Trimble County Unit 2 and the Trimble County General Plant Facilities.  The Authorization to Construct shall specify the expected date of the Construction Closing, the expected Net Electric Generating Capacity, a description of the technology and unit configuration, major equipment specifications, fuel type, and the expected Construction Schedule.

Authorized Person.  An officer of Louisville; an officer of Kentucky Utilities; the President or a Vice President of IMPA; or the General Manager and CEO of IMEA.

Auxiliary Power.  Power required for operation of Trimble County Unit 2, a reasonable portion of the Trimble County General Plant Facilities, and a reasonable portion of any other shared Trimble County Site electric usage.

Available.  The state in which a unit is capable of providing service regardless of the capacity level that can be provided.

Best Efforts.  Best Efforts signify a diligent, good faith, and commercially reasonable level of effort to achieve the identified goal or result.  Such level of effort does not require efforts or actions that are not commercially reasonable under the circumstances faced by the Party obligated to employ Best Efforts.

Booked.  With respect to Development Costs owed to a non-Affiliate of the Companies, the date paid.  With respect to Development Costs to be reimbursed to Louisville, Kentucky Utilities or any Affiliate of the Companies, the date such Development Costs are recorded on the books of Louisville, Kentucky Utilities or any Affiliate of the Companies.

CCNs.  The certificates of public convenience and necessity to be sought by the Companies from the KPSC and by Kentucky Utilities from the VSCC for the installation at the Trimble County Site of a second coal-fired generating unit for use in their respective systems as a base-load plant.

Commercial Operation Date.  The date upon which Trimble County Unit 2 and the Trimble County General Plant Facilities (to the extent modifications or additions are necessary to accommodate Trimble County Unit 2) are determined by the Companies to be ready to enter commercial service.

Commission Approvals.  Licenses, certificates, approvals, consents, permits or other permissions of the FERC, SEC, ICC, IURC, KPSC, KSB or VSSC.

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Companies.  Except as provided in Articles 6.5.1 and 14.2.5, Louisville and Kentucky Utilities. 

Construction Budget.  Construction Budget has the meaning specified in Article 17.4.2.

Construction Closing.  The delivery of documents and certificates and the payment of money, all as contemplated in Article 6.

Construction Contractor(s).  Construction Contractor(s) has the meaning specified in Article 5.5.

Construction Contract(s).  The contract(s) entered into by the Companies, as agent for the Parties, with Construction Contractors.

Construction Costs.  The costs of Construction Work, including reasonably documented internal expenses of the Companies incurred in connection with the Construction Work and the costs described in the second sentence of Article 12.3.

Construction Phase.  The Construction Phase commences on the date of the Construction Closing and concludes on the Commercial Operation Date or such later date as is necessary to complete the original construction of Trimble County Unit 2 and the Trimble County General Plant Facilities.

Construction Schedule.  The schedule of Construction Work to be developed by the Companies prior to the Construction Closing, showing, to the extent then ascertainable, construction milestones and the expected Commercial Operation Date.

Construction Work.  Work performed during the Construction Phase.

Coordination Committee.  The committee established pursuant to Article 17.

Defaulting Party.  Defaulting Party has the meaning specified in Article 19.1.

Deferred Development Costs.  Deferred Development Costs has the meaning specified in Article 3.2.

Delivery Point.  The high side of the main step-up transformer adjacent to Trimble County Unit 2 at the Trimble County Plant.

Development Budget.  Development Budget has the meaning specified in Article 17.4.1.

Development Closing.  The delivery of documents as contemplated in Article 3.

Development Costs.  The costs of the Development Work, including reasonably documented internal expenses of the Companies incurred in connection with the Development Work and the costs described in the second sentence of Article 12.3.

Development Phase.  The Development Phase began on or about July 1, 2001, and ends on the date of the Construction Closing.

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Development Reasons.  Development Reasons means (i) Force Majeure, (ii) a decision by the Companies not to proceed with the development of the Trimble County Unit 2 Project because it cannot be developed on a commercially reasonable basis or (iii) a decision by the Companies not to proceed with the development of the Trimble County Unit 2 Project because Commission Approvals or other permits and approvals cannot be obtained from Governmental Authorities on a commercially reasonable basis.

Development Work.  Work performed during the Development Phase.

Dispatch, Dispatched or Dispatching.  Requesting, in accordance with the terms and conditions of this Agreement, the use of Electric Capacity Entitlement utilizing real-time generation control hardware and software that interfaces with the Companies’ generation control system.

Disputing Parties.  Disputing Parties has the meaning specified in Article 18.4.

Electric Capacity Entitlement.  The percentage of the Net Electric Generating Capacity to which a Party is entitled under Article 7.2 as it may be otherwise adjusted in accordance with Article 7.

Emergency.  A condition that, in the Companies’ reasonable opinion, does or may present a physical threat to persons or property on or near the Trimble County Site, does or may seriously interfere with the safety or operation of the interconnected power system, or may cause or contribute to an imminent disruption of electric service to customers of the Parties.

Energy Allocation.  Energy Allocation has the meaning specified in Article 7.3.

Escrow Account.  Escrow Account has the meaning specified in Article 18.4.

E.S.T.  Eastern Standard Time.

Event of Default.  Event of Default has the meaning specified in Article 16.5.1.

Execution Date.  The date as of which the Parties enter into this Agreement, which date appears at the beginning of this Agreement.

Expected Ramp Rate Capability.  The expected ramp rate capability of Trimble County Unit 2 as determined from time to time by the Coordination Committee with respect to various conditions (e.g., temperature, humidity, unit conditions, etc.).

FERC.  United States Federal Energy Regulatory Commission.

Filing Date.  The later of (i) the date on which both petitions for the CCNs are filed by the Companies or (ii) the date on which the last of the two (2) petitions for the CCNs is filed by the Companies.

Fixed Operation and Maintenance Expenses.  Fixed Operation and Maintenance Expenses are calculated as the sum of the following expenses as they directly relate to the

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operation and maintenance of the Trimble County Unit 2 Project, as recorded in the accounting records for the Trimble County Unit 2 Project under the Uniform System of Accounts:

(i)Operation supervision and engineering (Account 500)

(ii)Steam expenses (Account 502 except for scrubber reactant)

(iii)Electric expenses (Account 505)

(iv)Miscellaneous steam power expenses (Account 506)

(v)Rents (Account 507)

(vi)Allowances (Account 509)

(vii)Maintenance supervision and engineering (Account 510)

(viii)Maintenance of structures (Account 511)

(ix)Maintenance of boiler plant (Account 512)

(x)Maintenance of electric plant (Account 513)

(xi)Maintenance of miscellaneous steam plant (Account 514)

Expenses in Account 509 shall not be allocated to IMPA or IMEA except to the extent the Companies obtain allowances on behalf of IMPA or IMEA pursuant to Article 7.6.

Force Majeure.  Any cause beyond the reasonable control of a Party, and which by using its Best Efforts the Party is unable to overcome, including the following: acts of God; strikes, lockouts, or other industrial disturbances; acts of public enemies; acts, orders, or the absence of necessary orders and permits of any kind, from any Governmental Authority; delay in transportation; unforeseen soil conditions; equipment, material, supplies, labor, or machinery shortages; epidemics; landslides; lightning; earthquakes; fire; hurricanes; tornadoes; storms; floods; washouts; drought; arrest; war; civil disturbances; insurrections; riots; acts of terrorism; explosions; breakage or accident to machinery, equipment, transmission lines, pipes, or canals; partial or entire failure of utility service; breach of contract by any supplier, contractor, subcontractor, laborer, or materialman; sabotage; injunction; blight; famine; blockage; quarantine; or any other similar or dissimilar cause or event not reasonably within the control of the Party.

Fuel/Reactant Operation Expenses.  Fuel/Reactant Operation Expenses are calculated as the sum of the following expenses as they relate to the operation of the Trimble County Unit 2 Project as recorded in the accounting records for the Trimble County Unit 2 Project under the Uniform System of Accounts:

(i)Fuel (Account 501)

(ii)Scrubber reactant expenses in Steam Expenses (Account 502)

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(iii)Ammonia (Account 512)

Good Utility Practice.  At a particular time, any of the practices, methods, or acts, which, in the exercise of reasonable judgment in the light of the facts known at the time the decision was made, would reasonably have been expected to accomplish the desired result or further the possibility of achieving such result, at a reasonable cost consistent with reliability and safety and in accordance with Applicable Law pertaining to the Trimble County Unit 2 Project.  Such practices, methods, or acts shall include any of the practices, methods, or acts generally engaged in or approved by other members of the electric utility industry at, prior to, or subsequent to the time the decision was made, provided, however, practices, methods or acts that have previously been engaged in by members of the electric utility industry but, at the time the decision was made, have been generally discredited will not be considered Good Utility Practice.  Good Utility Practice is not intended to be limited to the optimum practice, method, or act to the exclusion of all others, but rather to encompass a range of reasonable practices, methods, or acts.

Governmental Authority.  Any United States federal, state or local governmental entity, authority or agency, court, tribunal, regulatory commission or other body, whether legislative, judicial or executive, civilian or military (or a combination or permutation thereof).

ICC.  Illinois Commerce Commission.

IMEA.  IMEA has the meaning specified in the first (1^st) paragraph of this Agreement.

IMEA Participation Agreement.  The IMEA Participation Agreement has the meaning specified in the fourth (4^th) Whereas clause of this Agreement.

IMPA.  IMPA has the meaning specified in the first (1^st) paragraph of this Agreement.

IMPA Participation Agreement.  IMPA Participation Agreement has the meaning specified in the fifth (5^th) Whereas clause of this Agreement.

Incremental Capital Assets.  All assets of the Trimble County Unit 2 Project that are not included in Accounts 101, 106, or 107 of the Uniform System of Accounts on the Commercial Operation Date or such later date as is necessary to complete the original construction of Trimble County Unit 2 or the Trimble County General Plant Facilities and which, over the life of Trimble County Unit 2, are necessary or desirable for the continued reliable, economical operation of Trimble County Unit 2.

Initial Capital Assets.  All assets of the Trimble County Unit 2 Project that are included in Accounts 101, 106, or 107 of the Uniform System of Accounts on the Commercial Operation Date, or such later date as is necessary to complete the original construction of the Trimble County Unit 2 Project.

Initial Construction Budget.  Initial Construction Budget has the meaning specified in Article 17.4.2.

Interconnection and Operating Agreement.  An agreement, a copy of which is attached hereto as Appendix I, pursuant to which Trimble County Unit 2 will be interconnected to the

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grid, by and among the Applicable Transmission Provider and one or more of the Companies, in its or their capacities as “Transmission Owner” and “Generator” as such terms are therein defined.

IURC.  Indiana Utility Regulatory Commission.

KPSC.  Kentucky Public Service Commission.

KSB.  Kentucky State Board on Electric Transmission and Generating Siting.

Kentucky Utilities.  Kentucky Utilities has the meaning specified in the first (1^st) paragraph of this Agreement.

Louisville.  Louisville has the meaning specified in the first (1^st) paragraph of this Agreement.

Major Change.  Major Change has the meaning specified in Article 17.4.2.

Minimum Generation.  Minimum Generation means (i) the level of generation below which Trimble County Unit 2 cannot operate in a stable manner without stabilization fuel while in compliance with the standard of conduct established in Article 20.24, (ii) such greater level as may be appropriate from time to time consistent with the standard of conduct established in Article 20.24 (e.g., for required or recommended testing, etc.), or (iii) during the ramp from synchronization to the level described in clause (i) and any ramp up to the level described in clause (ii), the actual level of generation from time to time during the ramp.

NERC.  North American Electric Reliability Council.

Net Electric Generating Capacity.  The maximum continuous ability to produce electric energy that Trimble County Unit 2 can be ramped up to at any particular time, less Auxiliary Power, taking into account all relevant conditions and factors affecting or limiting the capability of the unit to produce electric power at such time, including availability and quality of fuel, any mechanical or other defects, breakdowns, malfunctions, and environmental and permit limitations then existing.

Net Normal Operating Capacity.  The amount, measured in kilowatts, designated from time to time by the Coordination Committee as the steady hourly output, less Auxiliary Power, which Trimble County Unit 2 can produce under normal, day-to-day conditions of unit operations that allow reliable long-term operation, adjusted due to seasonal variations in ambient temperature, condensing water availability and/or temperature and other factors that vary seasonally.

Net Seasonal Capacity.  The capacity of Trimble County Unit 2 as determined according to testing criteria defined in the East Central Area Reliability Coordination Agreement’s Document No. 4 entitled, “Criteria and Method for the Uniform Rating of Generating Equipment” or any successor document.

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Non-Defaulting Parties.  Non-Defaulting Parties has the meaning specified in Article 19.1.

O&M.  O&M has the meaning specified in Article 17.4.4.

Offered Interest.  Offered Interest has the meaning specified in Article 14.2.

Operating Work.  All engineering, contract preparation or contract negotiation, purchasing, repair, supervision, recruitment, training, expediting, inspection, accounting, testing, protection, operating, management, maintenance, and all other work and activities associated with operating the Trimble County Unit 2 Project that are not included in Development Work or Construction Work, but excluding all work on any Incremental Capital Assets.

Ownership Interest.  The interests of a Party in the Trimble County Unit 2 Project.

Party or Parties.  Party or Parties has the meaning specified in the first (1^st) paragraph of this Agreement.

Percentage.  Each Party’s Percentage is a percentage equal to that Party’s percentage ownership interest in Trimble County Unit 2 and the Trimble County Unit 2 Site.

Person.  Any individual, corporation, partnership, joint venture, association, joint stock company, trust, limited liability company, unincorporated organization, Governmental Authority or any other form of entity.

Plant Subjects.  Plant Subjects has the meaning specified in Article 18.2.

Ramping Request.  A Request by a Party with respect to a period of time for an amount of that Party’s Electric Capacity Entitlement that is greater than or less than that Requested by that Party for the immediately preceding period of time.

Refund Amount.  Refund Amount has the meaning specified in Article 6.5.6.

Return Notice.  Return Notice has the meaning specified in Article 14.2.

Request, Requested or Requesting.  The act of requesting the use of Electric Capacity Entitlement by Scheduling or Dispatching in accordance with the terms of this Agreement.

Schedule, Scheduled or Scheduling.  The act of requesting, in accordance with the terms and conditions of this Agreement, the use of a fixed megawatt amount of Electric Capacity Entitlement in each hour.  The megawatt amount that is Scheduled may vary from hour to hour in accordance with Article 7.

SEC.  United States Securities and Exchange Commission.

Taxes.  Taxes has the meaning specified in Article 12.1.

Transaction Documents.  Those documents referenced in Article 6.2.4.

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Transferring Party.  Transferring Party has the meaning specified in Article 14.2.

Transmission Service Arrangement.  Transmission Service Arrangement means the respective agreement or arrangement between each Party and the Applicable Transmission Provider for the transmission of its Electric Capacity Entitlement to such Party’s points of delivery.

Trimble County General Plant Facilities.  Facilities on the Trimble County Site identified in Appendix B that are necessary for use by IMPA and IMEA with respect to their respective Ownership Interest, for which IMPA and IMEA shall each be granted a non-exclusive license pursuant to Article 6.2.3.

Trimble County Plant.  The generating and ancillary facilities at a site along the Ohio River at river mile 571.4 at Wises Landing in Trimble County, Kentucky, which include Trimble County Unit 1, the Trimble County General Plant Facilities (as defined in the Unit 1 Participation Agreements) and other generating facilities located thereon; and will include Trimble County Unit 2, the Trimble County General Plant Facilities and other generating facilities to be constructed on the site in the future.

Trimble County Site.  Certain land, consisting of approximately 2,200 acres, and certain rights in land owned by Louisville, including:

(i)that portion of the land underlying Trimble County Unit 1 in which undivided interests were conveyed to IMPA and IMEA under the Unit 1 Participation Agreements (the “Trimble County Unit 1 Site”), respectively; and

(ii)Trimble County Unit 2 Site.

Trimble County Unit 1.  Trimble County Unit 1 has the meaning specified in the fourth (4^th) Whereas clause of this Agreement.

Trimble County Unit 1 Site.  Trimble County Unit 1 Site has the meaning specified in clause (i) of the definition of Trimble County Site.

Trimble County Unit 2.  The nominal seven hundred fifty (750) net megawatt coal-fired unit expected to be located at the Trimble County Site as more particularly described in Appendix A, as supplemented from time to time by the Parties.

Trimble County Unit 2 Project.  The Trimble County Unit 2 Project shall consist of Trimble County Unit 2, Trimble County General Plant Facilities and the Trimble County Unit 2 Site.

Trimble County Unit 2 Site.  Trimble County Unit 2 Site has the meaning specified in Article 6.2.2.

Uniform System of Accounts.  The FERC’s “Uniform System of Accounts Prescribed for Public Utilities and Licensees (Class A and Class B),” in effect as of the Execution Date, as such Uniform System of Accounts may be modified from time to time.  References in this Agreement

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to any specific account number shall mean the account number in effect as of the Execution Date or to any successor account.

Unit 1 Participation Agreements.  Unit 1 Participation Agreements has the meaning specified in the sixth (6^th) Whereas clause of this Agreement.

VSCC.  Virginia State Corporation Commission.

Withdrawal Event.  Withdrawal Event has the following meaning as it applies to the specified Parties:  with respect to the Companies, an Event of Default that is the responsibility of the Companies has occurred and is continuing, any applicable cure period associated with such Event of Default has expired, and such Event of Default has resulted or will result in the cancellation, termination, or suspension of the construction of Trimble County Unit 2 for a period of at least ninety (90) calendar days.  With respect to IMPA or IMEA, an Event of Default has occurred and is continuing for failure to make a payment of Construction Costs (or the supervisory fee thereon) otherwise due and owing hereunder and any applicable cure period associated with such Event of Default has expired.

Withholding Party.  Withholding Party has the meaning specified in Section 18.4.

Work.  All necessary or desirable work, services, equipment, materials and supplies arising out of or in connection with the development or completion of the Trimble County Unit 2 Project, its integration into the Trimble County Plant, and its interconnection with the Louisville 345 kV system at the Trimble County Plant switchyard as determined in accordance with the Interconnection and Operating Agreement, including site preparation, acquisition of interconnection transmission right-of-way, design, engineering, permitting, procurement, construction, training, start-up, commissioning, testing, management, administration, expediting, inspecting and other services, all items, materials (including, all water, utilities, chemicals, reactants, lubricating and fuel oils and other consumables), and equipment whether or not such items, services, materials, or equipment are expressly specified herein, as recorded in the accounting records for the Trimble County Unit 2 Project under the Uniform System of Accounts.  Work shall include work, services, items, materials or equipment provided or undertaken directly by one or both of the Companies or their Affiliates or performed under contracts, including the preparation, negotiation, and administration of such contracts, and shall include and the services of consultants, experts and attorneys in connection therewith.  Work shall not include any efforts or expenses made or incurred by a Party to negotiate this Agreement, obtain the approval of Boards of Directors, Boards of Commissioners, members, parent companies or any of their Affiliates in planning for or in anticipation of participation in the Trimble County Unit 2 Project as well as any Commission Approvals.  Notwithstanding the foregoing, work related to obtaining a siting permit for Trimble County Unit 2 whether such permit is part of the process of obtaining the CCNs or any other permit or approval of the KPSC shall constitute part of the Work.

1.2Rules of Interpretation.

(i)The terms defined above have the meanings set forth above for all purposes, and such meanings are equally applicable to both the singular and plural forms of the terms defined.

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(ii)The words “include,” “includes,” and “including” shall be deemed to be followed by “without limitation” whether or not they are in fact followed by such words or words of like import.

(iii)Any agreement, instrument or Applicable Law defined or referred herein means such agreement or instrument or Applicable Law as from time to time amended, modified, or replaced, restated or supplemented, including (in the case of agreements or instruments) by waiver or consent and (in the case of Applicable Law) by succession of a comparable successor Applicable Law and includes (in the case of agreements or instruments) references to all attachments thereto and instruments incorporated therein.

(iv)References to a Person are also deemed to include references to its successors and assigns permitted by Article 14 or Article 15.

(v)Any term defined above by reference to any agreement, instrument or Applicable Law has such meaning whether or not such agreement, instrument or Applicable Law is in effect.

(vi)“Hereof,” “herein,” “hereunder” and comparable terms refer, unless otherwise expressly indicated, to the entire agreement or instrument in which such terms are used and not to any particular article, section or other subdivision thereof or attachment thereto.  References in an instrument to “Article,” “Section,” “Subsection” or another subdivision or to an attachment are, unless the context otherwise requires, to an article, section, subsection or subdivision of or an attachment to such agreement or instrument.  All references to exhibits or appendices in any agreement or instrument are to exhibits or appendices attached to such instrument or agreement.

(vii)The word “or” will have the inclusive meaning represented by the phrase “and/or.”

(viii)“Shall” and “will” have equal force and effect.

ARTICLE 2.
OWNERSHIP

2.1Ownership.

Trimble County Unit 2 shall be owned by the Parties as tenants in common.  The undivided ownership interest of each Party shall be free and clear of the lien of any indenture or mortgage, deed of trust, bond resolution, or other instrument (hereinafter called “indenture”) establishing a lien upon some or all of the property of the other Parties.  The Percentages of the Parties shall be:  the Companies, seventy-five percent (75.0%); IMPA, twelve and eighty-eight one hundredths percent (12.88%); and, IMEA twelve and twelve one-hundredths percent (12.12%), respectively.  On or before the tenth (10^th) calendar day prior to the Construction Closing, the Companies will notify the other Parties in writing of the exact Percentages of Louisville and of Kentucky Utilities in Trimble County Unit 2.  Louisville shall retain ownership of the Trimble County General Plant Facilities as described in Appendix B attached hereto, provided, however, Louisville shall grant non-exclusive licenses to use such facilities in accordance with Article 6.2.3.  Louisville retains ownership of the Trimble County Site except

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for those portions of the Trimble County Site to be conveyed to IMPA, IMEA and Kentucky Utilities pursuant to Article 6.2.2, and except for that portion of the Trimble County Site previously conveyed to IMPA and IMEA pursuant to the Unit 1 Participation Agreements.

The Parties acknowledge that various items of property included in the Trimble County Unit 2 Project may be leased from time-to-time in lieu of purchasing such items.  Nothing in this Agreement shall preclude the Parties from leasing such items.  Such leased property shall be held by the Parties in an undivided leasehold as tenants in common.

2.2Additional Generating Units.

The Companies shall have the sole and exclusive right to own, install, enlarge, modify and operate any generating unit or units other than Trimble County Unit 2, as well as any other facility, including necessary appurtenances thereto, on the Trimble County Site, provided, however, such other units or facilities shall not be so installed, enlarged, modified, and operated, as the case may be, as to unreasonably impair (economically or operationally) the operation of Trimble County Unit 2, and provided, further, that with respect to Trimble County Unit 1, the rights of Louisville, IMPA and IMEA shall be determined in accordance with the Unit 1 Participation Agreements.

2.3Modification of Existing Property.

Subject to the approval of the Coordination Committee, and in accordance with the terms of this Agreement, the Companies shall have the right to use, enlarge, modify or relocate any facilities installed as a part of Trimble County Unit 2 or the Trimble County General Plant Facilities in connection with the installation, enlargement, modification, or operation, as the case may be, of such other unit or units or facilities described in Article 2.2, provided, however:

(i)Such use, enlargement, modification, or relocation of Trimble County Unit 2 facilities or Trimble County General Plant Facilities shall not unreasonably impair (economically or operationally) the operation of Trimble County Unit 2; and

(ii)The cost of such use, enlargement, modification or relocation of Trimble County Unit 2 facilities or Trimble County General Plant Facilities, in connection with such other unit or units or facilities, shall be borne by the Companies (except that if such use, enlargement, or relocation of Trimble County Unit 2 facilities or Trimble County General Plant Facilities is in connection with the installation, enlargement, modification of any additional unit or units or facilities that are owned or to be owned by the Parties in common, then the cost of such use, enlargement, modification, or relocation of said Trimble County Unit 2 facilities or Trimble County General Plant Facilities shall be shared by the Parties in proportion to their respective ownership interests in such additional unit or units or facilities), provided, however, that for the purposes of this Article 2.3(ii), subject to Article 14 or Article 15, and so long as Louisville and Kentucky Utilities are Affiliates, the Ownership Interest of Kentucky Utilities herein shall be deemed to be an interest of Louisville when assessing whether facilities are owned by the Parties in common; and

(iii)Such action shall not enlarge or diminish the respective Ownership Interests of the Parties in any part of the Trimble County Unit 2 Project; and

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(iv)Such action shall not enlarge or diminish the Parties’ respective obligations to share in the costs of any part of the Trimble County Unit 2 Project; and

(v)Where modification of existing property and rights requires revisions to existing documents setting forth the respective rights and interests of the Parties, or where new conveyances are required to properly effectuate the modifications to property and rights made hereunder, the Parties shall cooperate to promptly execute and deliver such documents.

ARTICLE 3.
DEVELOPMENT CLOSING

3.1Development Closing.

The Development Closing shall occur simultaneously with the execution of this Agreement at such location and time as may be selected by the Parties, on such date as mutually agreed upon by the Parties.

3.2Development Costs.

On April 1, 2004, IMPA and IMEA shall each pay to the Companies, in immediately available funds, their proportionate share of the sum (the “Deferred Development Costs”) of (i) the aggregate Development Costs (based on their respective Percentages) incurred by the Companies prior to such date, (ii) interest at the Agreed Rate computed from the date that each such Development Cost was Booked to April 1, 2004, and (iii) the supervisory fee thereon as described in Article 9.1.  Such sums shall be wired to a single account that is specified by the Companies not less than ten (10) calendar days prior to April 1, 2004.  The Parties agree that the aggregate amount of Development Costs incurred by the Companies to and until the last day of December 2003, is as set forth in Appendix D.  After the Development Closing, invoicing and payment of Development Costs shall be as provided in Article 9.1.

3.3Deliveries of Louisville at the Development Closing.

Louisville shall deliver to IMPA, IMEA and Kentucky Utilities a title insurance commitment of Commonwealth Land Title Insurance Company, dated within ten (10) calendar days of the date of the Development Closing, with respect to that portion of the Trimble County Site on which Trimble County Unit 2 is likely to be constructed, which commitment shall be in form and substance satisfactory to each of IMPA and IMEA.

3.4Effect of Development Closing on Article 15 Rights.

Upon execution of this Agreement, IMEA and IMPA each waive any rights it may have pursuant of Article 15 of the Unit 1 Participation Agreement to which it is a Party, subject to the reinstatement of such rights only to the extent expressly provided in this Agreement.

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ARTICLE 4.
REPRESENTATIONS AND WARRANTIES

4.1IMPA Representations and Warranties.

IMPA hereby represents and warrants to the Companies and IMEA as follows:

(i)IMPA Organization.  IMPA is a body corporate and politic and a political subdivision of the State of Indiana, duly organized, validly existing and in good standing under the laws of the State of Indiana, has the full power, legal capacity, and authority to enter into this Agreement and related agreements, to carry out the transactions contemplated by this Agreement, and to carry on its business as it is now being conducted.  IMPA has delivered to the other Parties a true and complete copy of the Contract Creating the IMPA and its by-laws as amended to date.

(ii)Authority Relative to This Agreement.  The execution, delivery, and performance by IMPA of this Agreement have been duly authorized by all necessary corporate action on the part of IMPA.  The execution, delivery, and performance by IMPA of this Agreement do not contravene any Applicable Law, applicable to IMPA or its properties, or the Contract Creating the IMPA or its by-laws and do not and will not contravene the provisions of, or constitute a default under, any indenture, mortgage, contract, or other instrument to which IMPA is a party or by which IMPA is bound, and this Agreement constitutes a legal, valid, and binding obligation of IMPA, enforceable in accordance with its terms, except as limited by applicable bankruptcy, insolvency, reorganization, or similar laws at the time in effect.

(iii)Approvals and Consents.  Any consent or approval of, giving of notice to, registration with, or taking of any other action by any applicable Governmental Authority in connection with the execution, delivery, and performance of this Agreement by IMPA required to be obtained by IMPA on or before the date hereof have been obtained.

(iv)Legal Proceedings.  There is no materially adverse legal action, suit, arbitration, governmental investigation, or other legal or administrative proceeding, or any order, decree, or judgment in progress, pending or in effect, or to the knowledge of IMPA threatened in writing against or relating to IMPA in connection with or relating to the transactions contemplated by this Agreement, and IMPA does not know or have any reason to be aware of any basis for the same.

4.2Louisville Representations and Warranties.

Louisville hereby represents and warrants to IMPA, IMEA and Kentucky Utilities as follows:

(i)Louisville Organization.  Louisville is a corporation duly organized and validly existing under the laws of the Commonwealth of Kentucky, and has corporate power to carry on its business as it is now being conducted and as it is contemplated to be conducted.  Louisville has delivered to the other Parties a true and complete copy of its articles of incorporation and by-laws as amended to date.

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(ii)Authority Relative to This Agreement.  The execution, delivery, and performance by Louisville of this Agreement have been duly authorized by all necessary corporate action on the part of Louisville, do not contravene any Applicable Law, applicable to Louisville or its properties, or the articles of incorporation or by-laws of Louisville and do not and will not contravene the provisions of, or constitute a default under, any indenture, mortgage, contract, or other instrument to which Louisville is a party or by which Louisville is bound, and this Agreement constitutes a legal, valid, and binding obligation of Louisville, enforceable in accordance with its terms, except as limited by applicable bankruptcy, insolvency, reorganization, or similar laws at the time in effect.

(iii)Approvals and Consents.  Any consent or approval of, giving of notice to, registration with, or taking of any other action by any applicable Governmental Authority in connection with the execution, delivery, and performance of this Agreement by Louisville required to be obtained by Louisville on or before the date hereof have been obtained.

(iv)Legal Proceedings.  There is no materially adverse legal action, suit, arbitration, governmental investigation, or other legal or administrative proceeding, or any order, decree, or judgment in progress, pending or in effect, or to the knowledge of Louisville threatened in writing against or relating to Louisville in connection with or relating to the transactions contemplated by this Agreement, and Louisville does not know or have any reason to be aware of any basis for the same.

4.3Kentucky Utilities Representations and Warranties.

Kentucky Utilities hereby represents and warrants to IMPA, IMEA and Louisville as follows:

(i)Kentucky Utilities Organization.  Kentucky Utilities is a corporation duly organized and validly existing under the laws of the Commonwealth of Kentucky, and has corporate power to carry on its business as it is now being conducted and as it is contemplated to be conducted.  Kentucky Utilities has delivered to the other Parties a true and complete copy of its articles of incorporation and by-laws as amended to date.

(ii)Authority Relative to This Agreement.  The execution, delivery, and performance by Kentucky Utilities of this Agreement have been duly authorized by all necessary corporate action on the part of Kentucky Utilities, do not contravene any Applicable Law, applicable to Kentucky Utilities or its properties, or the articles of incorporation or by-laws of Kentucky Utilities and do not and will not contravene the provisions of, or constitute a default under, any indenture, mortgage, contract, or other instrument to which Kentucky Utilities is a party or by which Kentucky Utilities is bound, and this Agreement constitutes a legal, valid, and binding obligation of Kentucky Utilities, enforceable in accordance with its terms, except as limited by applicable bankruptcy, insolvency, reorganization, or similar laws at the time in effect.

(iii)Approvals and Consents.  Any consent or approval of, giving of notice to, registration with, or taking of any other action by any applicable Governmental Authority in connection with the execution, delivery, and performance of this Agreement by Kentucky

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Utilities required to be obtained by Kentucky Utilities on or before the date hereof have been obtained.

(iv)Legal Proceedings.  There is no materially adverse legal action, suit, arbitration, governmental investigation, or other legal or administrative proceeding, or any order, decree, or judgment in progress, pending or in effect, or to the knowledge of Kentucky Utilities threatened in writing against or relating to Kentucky Utilities in connection with or relating to the transactions contemplated by this Agreement, and Kentucky Utilities does not know or have any reason to be aware of any basis for the same.

4.4IMEA Representations and Warranties.

IMEA hereby represents and warrants to the Companies and IMPA as follows:

(i)IMEA Organization.  IMEA is a body politic and corporate, municipal corporation and unit of local government of the State of Illinois duly organized and validly existing under the laws of the State of Illinois, and has full power, legal capacity and authority to enter into this Agreement and related agreements, to carry out the transactions contemplated by this Agreement, and to carry on its business as it is now being conducted.  IMEA has delivered to the other Parties a true and complete copy of its Agency Agreement and by-laws as amended to date.

(ii)Authority Relative to This Agreement.  The execution, delivery, and performance by IMEA of this Agreement have been duly authorized by all necessary corporate action on the part of IMEA.  The execution, delivery, and performance by IMEA of this Agreement do not contravene any law, or any governmental rule, regulation, or order applicable to IMEA or its properties, or the Agency Agreement or by-laws of IMEA and do not and will not contravene the provisions of, or constitute a default under, any indenture, mortgage, contract, or other instrument to which IMEA is a party or by which IMEA is bound, and this Agreement constitutes a legal, valid, and binding obligation of IMEA, enforceable in accordance with its terms, except as limited by applicable bankruptcy, insolvency, reorganization, or similar laws at the time in effect.

(iii)Approvals and Consents.  Any consent or approval of, giving of notice to, registration with, or taking of any other action by any applicable Governmental Authority in connection with the execution, delivery, and performance of this Agreement required to be obtained by IMEA on or before the date hereof have been obtained.

(iv)Legal Proceedings.  There is no materially adverse legal action, suit, arbitration, governmental investigation, or other legal or administrative proceeding, or any order, decree, or judgment in progress, pending or in effect, or to the knowledge of IMEA threatened in writing against or relating to IMEA in connection with or relating to the transactions contemplated by this Agreement, and IMEA does not know or have any reason to be aware of any basis for the same.

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ARTICLE 5.
DEVELOPMENT AND CONSTRUCTION

5.1Responsibility for Development.

The Parties agree to jointly develop the Trimble County Unit 2 Project.  Trimble County Unit 2 is intended to consist of a single coal-fired steam-electric generating unit of a super-critical design and associated facilities with a Net Electric Generating Capacity of approximately seven hundred fifty (750) megawatts, generally as described in the “Trimble County Unit 2 Project Approach” prepared by Burns & McDonnell Engineering Company, dated September 30, 2002, as further described in Appendix A and Appendix B, and as further developed and refined during the Development Phase.  The Parties will use their respective Best Efforts to complete the Development Phase by December 1, 2005, subject to Article 6.5.

Subject to the provisions of Article 6.5, the Companies, as agent of the Parties, shall have the authority and obligation to manage, control, administer, enter into contracts, perform services and make all decisions necessary and appropriate for the performance of the Development Work.  The Companies shall discharge such obligations in accordance with the provisions of this Agreement, including the standard of conduct established in Article 20.24 and Article 17.  IMPA and IMEA do hereby appoint the Companies to be their attorneys-in-fact, which appointment is coupled with an interest, to act in their names, places and steads in the negotiation, execution and administration of contracts with Affiliates and non-Affiliates of the Companies in connection with the Development Work.  Such appointment shall not be revocable during the Development Phase.

5.2Responsibility for Permits.

Except for Commission Approvals required to be obtained by IMEA or IMPA, the Companies shall be responsible for obtaining all environmental, land use and other licenses, permits and approvals for construction and operation of the Trimble County Unit 2 Project.  IMPA shall be responsible for obtaining any Commission Approvals or other approvals of Governmental Authorities applicable to its ownership or participation in the Trimble County Unit 2 Project or the execution, delivery and performance of this Agreement by IMPA.  IMEA shall be responsible for obtaining any Commission Approvals or other approvals of Governmental Authorities applicable to its ownership or participation in the Trimble County Unit 2 Project or the execution, delivery and performance of this Agreement by IMEA.

5.3Development Schedule.

The Parties expect to complete the Development Phase of the Trimble County Unit 2 Project by December 31, 2005.  The Parties recognize that there are and will likely be uncertainties relating to the obtaining of necessary licenses, permits and approvals for the Trimble County Unit 2 Project, some of which are beyond the control of some or all of the Parties.  Notwithstanding such uncertainties, during the Development Phase, the Parties shall exercise their respective Best Efforts to seek and obtain according to the following milestone schedule, the joint and individual decisions, approvals and commitments necessary to achieve Construction Closing:

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(i)Agreement by each Party and the Applicable Transmission Provider of a Transmission Service Arrangement by July 1, 2004;

(ii)Execution of the Interconnection and Operating Agreement with the Applicable Transmission Provider by December 1, 2003;

(iii)Decisions from applicable Governmental Authorities with respect to necessary Commission Approvals by July 1, 2005;

(iv)Receipt of final major environmental permits, not subject to appeal, rehearing or review by February 1, 2005;

(v)Final authorization, including arrangements for project funding by each Party by November 1, 2005; and

(vi)Construction Closing by December 31, 2005.

5.4Authorization to Construct.

At least thirty (30) calendar days prior to the conclusion of the Development Phase and the Construction Closing, the Parties, acting through the Coordination Committee, shall undertake consideration and issuance of the Authorization to Construct and determine whether or not to proceed to the Construction Closing.  The Parties currently expect to achieve a Commercial Operation Date between October 1, 2009, and March 1, 2010, which date range is subject to adjustment based on the facts and circumstances that arise during the Development Phase and the Construction Phase.

5.5Responsibility for Construction.

The Companies, as agent for the Parties, shall have the authority and obligation to manage, control, administer, perform services and make all decisions necessary and appropriate for the supervision of the Construction Work, including the supervision of the design, procurement and construction of the Trimble County Unit 2 Project.  The Companies shall discharge such obligations in accordance with the provisions of this Agreement, including the standard of conduct established in Article 20.24 and Article 17.  The Companies, as agent of the Parties, shall be entitled to contract with one or more Persons (the “Construction Contractors”) for the performance of the Construction Work in a good and workmanlike manner and in all material respects in accordance with Applicable Laws.  IMPA and IMEA do hereby appoint the Companies to be their attorneys-in-fact, which appointment is coupled with an interest to act in their names, places and steads in the negotiation, execution and administration of the Construction Contracts and the performance of their other obligations in connection with the Construction Work.  Such appointment shall not be revocable during the Construction Phase.

5.6Construction Schedule.

The Companies shall manage, administer and perform support services in aid of the construction effort in accordance with the standard of conduct established in Article 20.24, with

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the goal of achieving the expected Commercial Operation Date specified in the Authorization to Construct, within the Construction Budget, subject to Article 17.

ARTICLE 6.
CONSTRUCTION CLOSING AND WITHDRAWAL

6.1Construction Closing.

The Construction Closing shall occur on or before December 31, 2005 (as such date may be extended by the decision of the Coordination Committee or otherwise in accordance with Article 21.1.2), subject to the right of each Party to withdraw in accordance with and subject to the provision of Article 6.5, or this Agreement shall terminate as provided in Article 21.  The Construction Closing shall occur on such date and at such location and time as the non-withdrawing Parties shall agree.

6.2Closing Actions.

6.2.1Payment to Louisville.

At the Construction Closing, IMPA shall pay Louisville the sum of  twelve thousand eight hundred eighty dollars ($12,880), IMEA shall pay Louisville the sum of twelve thousand one hundred twenty dollars ($12,120), and Kentucky Utilities shall pay Louisville the sum calculated by multiplying one hundred thousand dollars ($100,000) by the Percentage of Kentucky Utilities, respectively, representing their proportionate share of the purchase price for the land and easements conveyed by Louisville pursuant to this Agreement.  Such payments shall be made to a single account that is specified by Louisville at least ten (10) calendar days prior to the Construction Closing.

6.2.2Conveyance of Real Property.

At the Construction Closing, Louisville shall sell and convey to IMPA and IMEA by general warranty deed, substantially in the form shown in Appendix E, an undivided ownership interest of twelve and eighty-eight one-hundredths percent (12.88%) and twelve and twelve one-hundredths percent (12.12%), respectively, in that portion of the real estate constituting the Trimble County Site underlying Trimble County Unit 2 (the “Trimble County Unit 2 Site”) to be held as tenants in common.  Prior to the Construction Closing, Louisville shall sell and convey to Kentucky Utilities by general warranty deed, substantially in the form shown in Appendix E, an undivided ownership interest in its Percentage of the Trimble County Unit 2 Site.  Upon such conveyances, the undivided percentage ownership interests of the Trimble County Unit 2 Site will be as follows:  the Companies — seventy-five percent (75.00%); IMPA — twelve and eighty-eight one-hundredths percent (12.88%); and IMEA — twelve and twelve one-hundredths percent (12.12%).

6.2.3Licenses and Easements.

Louisville shall grant to each IMPA, IMEA and Kentucky Utilities non-exclusive licenses, substantially in the form of Appendix C, to use the Trimble County General Plant Facilities and non-exclusive easements, substantially in the form of Appendix F, over that portion of the Trimble County Site owned by Louisville, as the Trimble County General Plant

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Facilities and the Trimble County Site pertain to IMPA’s, IMEA’s and Kentucky Utilities’ ownership and use of Trimble County Unit 2.  IMPA, IMEA and Kentucky Utilities acknowledge that the Trimble County General Plant Facilities to be licensed hereunder are also subject to the pre-existing non-exclusive licenses to IMPA and IMEA to all or a part of such facilities delivered in accordance with the Unit 1 Participation Agreements.

6.2.4Transaction Documents.

At the Construction Closing, the Parties shall execute and/or deliver the documents to be executed by them as contemplated by or referenced in Articles 6.3 or 6.4, together with such other documents and instruments as the Coordination Committee unanimously determines are necessary or desirable to confirm completion of the Development Phase and to enable and allow the Parties to proceed with the Construction Phase and the completion of the Trimble County Unit 2 Project.

6.3Conditions Precedent.

The following conditions constitute the conditions precedent to each Party’s participation in the Construction Closing.  If any such condition is not satisfied, each Party, in its sole discretion, is entitled to waive such condition with respect to its participation in the Construction Closing:

(i)The Coordination Committee shall have issued the Authorization to Construct in accordance with Article 17.3(x).

(ii)The Transaction Documents, including design, major, equipment and construction contracts are in substantially final form and have been approved by the Coordination Committee.

(iii)The Construction Budget and the Construction Schedule shall have been approved by the Coordination Committee.

(iv)The final major environmental permits for the construction of Trimble County Unit 2 have been duly issued, are in full force and effect and are not subject to appeal, reconsideration or review.

(v)All other necessary regulatory approvals, including Commission Approvals, necessary for the execution, delivery and performance of this Agreement, land use approvals, and other licenses, permits and approvals for the construction of the Trimble County Unit 2 Project (other than those, which in light of the status of the project as of the date of the Construction Closing, are not yet required to have been obtained pursuant to Applicable Law and can be obtained without substantial difficulty, expense or delay) have been duly issued, are in full force and effect and are not subject to appeal, reconsideration or review.

(vi)The Interconnection and Operating Agreement is in full force and effect and one or more of the Companies, in the capacity as “Generator” thereunder, shall have assigned a portion of its or their rights and obligations to IMPA and IMEA, as appropriate, such that the “Generator” constitutes all of the Parties to this Agreement in accordance with the Parties’

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respective Percentages.  IMPA and IMEA, as appropriate, also shall have assumed the assigned obligations under the Interconnection and Operating Agreement.

(vii)Each Party shall have tendered at the Construction Closing the documents, instruments and other items that it is required to deliver at the Construction Closing pursuant to Article 6.4, subject only to the delivery by the other Parties of the documents, instruments and other items that they are obligated to deliver at the Construction Closing pursuant to Article 6.4.

(viii)Each of the representations and warranties of Louisville, Kentucky Utilities, IMPA and IMEA, respectively, contained in Article 4 shall be true and correct as of the Construction Closing.

(ix)Each of the Parties shall have performed all obligations and complied with all covenants that are to be performed or complied with in all material respects necessary to be performed or complied with on or before the Construction Closing.

(x)Each of the Parties shall have entered into their respective Transmission Service Arrangement with the Applicable Transmission Provider and such arrangement shall be in full force and effect.

(xi)Each of the Parties shall have tendered at the Construction Closing written evidence of the approval of its Board of Directors or Board of Commissioners, as applicable, to proceed with the Construction Closing and the transactions contemplated herein.

6.4Deliveries at Construction Closing.

6.4.1Payment of Funds by IMPA.

The moneys required to be paid by IMPA to Louisville at the Construction Closing in accordance with Article 6.2.1 shall be paid in immediately available funds.

6.4.2Payment of Funds by IMEA.

The moneys required to be paid by IMEA to Louisville at the Construction Closing in accordance with Article 6.2.1 shall be paid in immediately available funds.

6.4.3Payment of Funds by Kentucky Utilities.

The moneys required to be paid by Kentucky Utilities at the Construction Closing in accordance with Article 6.2.1 shall be paid in immediately available funds.

6.4.4General Warranty Deeds.

Louisville shall deliver to IMPA, IMEA and Kentucky Utilities general warranty deeds in accordance with Article 6.2.2.

6.4.5Licenses to Trimble County General Plant Facilities.

Louisville shall deliver to IMPA, IMEA, and Kentucky Utilities licenses to use the Trimble County General Plant Facilities in accordance with Article 6.2.3.

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6.4.6Non-Exclusive Easements of Trimble County Site.

Louisville shall deliver to IMPA, IMEA, and Kentucky Utilities non-exclusive easements over a portion of the Trimble County Site in accordance with Article 6.2.3.

6.4.7Reserved.

6.4.8Representations and Warranties.

Each Party shall deliver a certificate executed by an Authorized Person of such Party to each of the other Parties certifying that the representations and warranties of such Party as contained in Article 4 are true and correct as of the date of the Construction Closing.

6.4.9Conditions.

Each Party shall deliver a certificate executed by an Authorized Person of such Party to each of the other Parties certifying that all of the conditions to its obligations to the Construction Closing have been satisfied or waived.

6.4.10Release from Lien of Louisville’s Indenture.

Louisville shall furnish to each of IMPA, IMEA, and Kentucky Utilities a properly executed release of that portion of the real property being conveyed to IMPA, IMEA and Kentucky Utilities at the Construction Closing from the lien of any and all indentures (other than indentures created by IMPA, IMEA or Kentucky Utilities).

6.4.11Opinion of Counsel for Louisville.

Louisville shall furnish to IMPA, IMEA, and Kentucky Utilities an opinion of counsel for Louisville, which may include counsel employed directly by Louisville, and which counsel shall be satisfactory to the Parties, in form and substance satisfactory to the Parties, dated the date of the Construction Closing, to the effect that:

(i)Louisville is a corporation duly organized and validly existing under the laws of the Commonwealth of Kentucky and has the corporate power and authority to carry on its business as presently conducted and to enter into and perform its obligations under this Agreement; and

(ii)The execution, delivery, and performance by Louisville of this Agreement have been duly authorized by all necessary corporate action on the part of Louisville, do not contravene any law, or any governmental rule, regulation, or order applicable to Louisville or its properties, or the articles of incorporation or by-laws of Louisville, and do not and will not contravene the provisions of, or constitute a default under, any indenture, mortgage, contract, or other instrument to which Louisville is a party or by which Louisville is bound; and

(iii)The documents executed by Louisville in connection with the Construction Closing have been duly authorized, executed, and delivered by Louisville; and

(iv)Any consent or approval of, giving of notice to, registration with or taking of any other action by, any Governmental Authority, including Commission Approvals, in connection

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with the execution, delivery, and performance of this Agreement required to be obtained by Louisville on or before the Construction Closing has been obtained; and

(v)There is no action, suit, or proceeding pending against Louisville that would materially adversely affect the ability of Louisville to perform its obligations under this Agreement.

6.4.12Opinion of Counsel for Kentucky Utilities.

Kentucky Utilities shall furnish to IMPA, IMEA, and Louisville an opinion of counsel for Kentucky Utilities, which may include counsel employed directly by Kentucky Utilities, and which counsel shall be satisfactory to the Parties, in form and substance satisfactory to the Parties, dated the date of the Construction Closing, to the effect that:

(i)Kentucky Utilities is a corporation duly organized and validly existing under the laws of the Commonwealth of Kentucky and has the corporate power and authority to carry on its business as presently conducted and to enter into and perform its obligations under this Agreement; and

(ii)The execution, delivery, and performance by Kentucky Utilities of this Agreement has been duly authorized by all necessary corporate action on the part of Kentucky Utilities, do not contravene any law, or any governmental rule, regulation, or order applicable to Kentucky Utilities or its properties, or the articles of incorporation or by-laws of Kentucky Utilities, and do not and will not contravene the provisions of, or constitute a default under, any indenture, mortgage, contract, or other instrument to which Kentucky Utilities is a party or by which Kentucky Utilities is bound; and

(iii)The documents executed by Kentucky Utilities in connection with the Construction Closing have been duly authorized, executed, and delivered by Kentucky Utilities; and

(iv)Any consent or approval of, giving of notice to, registration with or taking of any other action by, any Governmental Authority, including Commission Approvals, in connection with the execution, delivery, and performance of this Agreement required to be obtained by Kentucky Utilities on or before the Construction Closing has been obtained.

(v)There is no action, suit, or proceeding pending against Kentucky Utilities that would materially adversely affect the ability of Kentucky Utilities to perform its obligations under this Agreement.

6.4.13Opinion of Counsel for IMPA.

IMPA shall furnish to the Companies and IMEA an opinion of counsel for IMPA, which may include counsel employed directly by IMPA, and which counsel shall be satisfactory to the Parties, in form and substance satisfactory to the Parties, dated the date of the Construction Closing, to the effect that:

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(i)IMPA is a body corporate and politic and a political subdivision of the State of Indiana and has the corporate power, legal capacity, and authority to carry on its business as presently conducted and to enter into and perform its obligations under this Agreement; and

(ii)The execution, delivery, and performance by IMPA of this Agreement have been duly authorized by all necessary corporate action on the part of IMPA, do not contravene any law, or any governmental rule, regulation, or order, applicable to IMPA or its properties, or the Contract Creating the IMPA, or the by-laws of IMPA and do not and will not contravene the provisions of, or constitute a default under, any indenture, mortgage, contract, or other instrument to which IMPA is a party or by which IMPA is bound; and

(iii)This Agreement has been duly executed and delivered by IMPA and constitutes the legal, valid, and binding obligations of IMPA enforceable in accordance with its respective terms, except as limited by applicable bankruptcy, insolvency, reorganization, or similar laws at the time in effect; and

(iv)Any consent or approval of, giving of notice to, registration with, or taking of any other action by, any Governmental Authority, including Commission Approvals, in connection with the execution, delivery, and performance of this Agreement required to be obtained by IMPA on or before the Construction Closing has been obtained.

(v)There is no action, suit, or proceeding pending against IMPA that would materially adversely affect the ability of IMPA to perform its obligations under this Agreement.

6.4.14Opinion of Counsel for IMEA.

IMEA shall furnish to the Companies and IMPA an opinion of counsel for IMEA, which counsel shall be satisfactory to the Parties, in form and substance satisfactory to the Parties, dated the date of the Construction Closing to the effect that:

(i)IMEA is a body politic and corporate, municipal corporation and unit of local government of the State of Illinois and has the corporate power, legal capacity, and authority to carry on its business as presently conducted and to enter into and perform its obligations under this Agreement; and

(ii)The execution, delivery, and performance by IMEA of this Agreement have been duly authorized by all necessary corporate action on the part of IMEA, do not contravene any law, or any governmental rule, regulation, or order, applicable to IMEA or its properties, or the Agency Agreement, or the by-laws of IMEA and do not and will not contravene the provisions of, or constitute a default under, any indenture, mortgage, contract, or other instrument to which IMEA is a party or by which IMEA is bound; and

(iii)This Agreement has been duly executed and delivered by IMEA and constitutes the legal, valid, and binding obligations of IMEA enforceable in accordance with its respective terms, except as limited by applicable bankruptcy, insolvency, reorganization, or similar laws at the time in effect; and

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(iv)Any consent or approval of, giving of notice to, registration with, or taking of any other action by, any Governmental Authority, including Commission Approvals, in connection with the execution, delivery, and performance of this Agreement required to be obtained by IMEA on or before the Construction Closing has been obtained.

(v)There is no action, suit, or proceeding pending against IMEA that would materially adversely affect the ability of IMEA to perform its obligations under this Agreement.

6.4.15Transaction Documents.

The Parties shall execute and deliver the Transaction Documents in accordance with Article 6.2.4.

6.4.16Title Commitment.

Louisville shall deliver to IMPA and IMEA a title insurance commitment of Commonwealth Land Title Insurance Company, dated within ten (10) calendar days prior to the date of the Construction Closing, with respect to the Trimble County Unit 2 Site which commitment shall be in form and substance (other than specific metes and bounds) similar to the title commitment delivered by Louisville as a condition of the Development Closing in all material respects.

6.4.17Property Taxes.

Louisville shall deliver to IMPA and IMEA evidence that it has paid all property taxes that are assessed on the real property conveyed to IMPA and IMEA (as applicable) hereunder, except for property taxes assessed but not yet payable by the time of the Construction Closing.

6.5Withdrawal.

6.5.1Withdrawal Prior to Construction Closing.

If at any time, a Party determines that it will not participate in the Construction Closing, it shall give prompt written notice to the other Parties of its withdrawal from this Agreement, which notice shall specify the reasons for such withdrawal in reasonable detail.  Effective thirty (30) calendar days after giving such notice, the notifying Party shall cease to be a party to this Agreement.  Except as specifically provided herein, a Party that withdraws from this Agreement in accordance with this Article 6.5.1 shall remain liable for all of its obligations incurred hereunder prior to the date of withdrawal and shall not be entitled to a refund or return of any amounts paid or expended under this Agreement.  If either Louisville or Kentucky Utilities (but not both) gives notice of withdrawal under this Article 6.5.1 prior to the Construction Closing, the other shall automatically succeed to its withdrawing Affiliate’s Ownership Interest, assume the obligations related thereto and be entitled to exercise the rights of its withdrawing Affiliate hereunder.  Upon such withdrawal, the defined term “Companies” shall be deemed to refer only to such non-withdrawing Party.

6.5.2Withdrawal of IMPA or IMEA.

If, prior to the Construction Closing, either (but not both) IMPA or IMEA gives notice of its withdrawal in accordance with Article 6.5.1 above, the other Parties shall assume such Party’s

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Ownership Interest in proportion to their respective Percentages immediately prior to such assumption.  A Party withdrawing under this Article 6.5.2 shall have no further liability to the other Parties on account of such withdrawal, provided, however, such Party shall remain liable for all of its obligations incurred prior to date of its withdrawal and provided, further, such Party shall not be entitled to a refund or return of any amounts paid or expended under this Agreement.  The rights of such withdrawing Party pursuant to Article 15 of the applicable Unit 1 Participation Agreement shall not be thereafter reinstated.

6.5.3Withdrawal by the Companies or IMPA and IMEA.

If, on or prior to the Construction Closing, Louisville and Kentucky Utilities shall give notice of withdrawal in accordance with Article 6.5.1, then upon receipt of notice by the remaining Parties, this Agreement shall terminate in accordance with Article 6.5.6 or 21.1.3, as appropriate.  If, on or prior to the Construction Closing, IMPA and IMEA give notice of withdrawal in accordance with Article 6.5.1, then upon receipt of notice by the remaining Parties, this Agreement shall terminate in accordance with Article 21.1.4.

6.5.4No Withdrawal During Construction Phase.

No Party shall cause a Withdrawal Event to occur during the Construction Phase, provided, however, a Party may transfer its Ownership Interest during the Construction Phase on the following conditions:  If any Party (for purposes of this Article 6.5.4, a “Withdrawing Party”) shall desire to withdraw from this Agreement after the Construction Closing but prior to the Commercial Operation Date:  (i) the Withdrawing Party shall use its Best Efforts to expeditiously transfer its Ownership Interest to one or more third parties pursuant to the terms and conditions of Article 14.2; (ii) the Parties will continue the construction of Trimble County Unit 2 in an expeditious manner, and will otherwise continue to perform their respective obligations under this Agreement; (iii) the Withdrawing Party shall remain responsible for its proportionate share of all Construction Costs (and the supervisory fee thereon, as applicable) pursuant to this Agreement until the transfer of its Ownership Interest has been completed; and (iv) any costs incurred by the Withdrawing Party in connection with the transfer of its Ownership Interest shall be borne solely by the Withdrawing Party.

6.5.5Breach by IMPA or IMEA During the Construction Phase.

The Parties agree that it would be extremely difficult and impracticable under the presently known and anticipated facts and circumstances to ascertain and fix the actual damages that would be incurred if, during the Construction Phase, a Withdrawal Event occurs with respect to IMPA or IMEA.  Upon receipt of written notice by the Companies, as the exclusive remedy of the Companies for breach of Article 6.5.4 by IMPA or IMEA, all rights of the non-paying Party hereunder shall terminate and the non-paying Party shall transfer all of its right, title and interest in and to the Trimble County Unit 2 Project (free and clear of all liens, security interests, charges, claims and other encumbrances) to the remaining Parties in proportion to their respective Percentages.  The Parties agree to promptly undertake any and all reasonable actions, including the execution, delivery and filing of appropriate instruments, to effect the transactions contemplated by this Article 6.5.5.

Upon the conclusion of the Construction Work, the Companies shall determine the actual per kilowatt cost of the Trimble County Unit 2 Project.  In consideration of the transfer of all of

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its right, title and interest in and to the Trimble County Unit 2 Project (free and clear of all liens, security interests, charges, claims and other encumbrances) to the other Parties in proportion to their respective Percentages and in full and complete settlement and release of all claims, causes of action, liabilities, damages or expenses of the other Parties, direct or indirect, known or unknown, that such other Parties have or may have in the future against the non-paying Party arising out of such non-payment, the other Parties, as liquidated damages and not as a penalty, will pay to the non-paying Party an amount determined by the formula set forth below.  The amount to be paid by the paying Parties shall be in proportion to their respective Percentages.

X ÷Y = Z

A ÷ Z = N

N x $1000/kilowatt = P

where:

X =  Aggregate Development Costs and Construction Costs (plus the supervisory fees paid thereon) paid by all Parties to complete the Trimble County Unit 2 Project

Y =  Actual Net Normal Operating Capacity of Trimble County Unit 2, adjusted to 59°F on the Commercial Operation Date, measured in kilowatts

Z =  Actual per kilowatt Development Costs and Construction Costs (plus the supervisory fees thereon) of the Trimble County Unit 2 Project

A =  Aggregate Development Costs and Construction Costs (plus the supervisory fees paid thereon) actually paid by the non-Paying Party

N =  The number of kilowatts actually paid for by the non-paying Party

P =   Payment to non-paying Party

6.5.6CCNs Not Filed.

If the Companies (i) do not file petitions for the CCNs on or prior to December 31, 2004, or (ii) file petitions for the CCNs but exercise their rights to withdraw pursuant to Article 6.5.1 on or prior to the date that is one hundred eighty (180) days after the Filing Date, this Agreement shall terminate on the date of such withdrawal or December 31, 2004, if the Filing Date has not occurred, and no Party shall have any further liability, each to the other, on account of such termination, provided, however, the Companies shall refund to each of IMPA and IMEA an amount equal to the sum of Development Costs, the supervisory fee thereon and interest on the Deferred Development Costs paid by such Party to the Companies (the “Refund Amount”).  Upon such termination, the respective rights of each of IMPA and IMEA pursuant to Article 15 of the Unit 1 Participation Agreement to which it is a party shall be reinstated.

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ARTICLE 7.
OPERATING ARRANGEMENTS

7.1Authority for Operation and Management.

From and after the Commercial Operation Date and subject to the provisions of Article 17, the Companies shall have the sole obligation and authority to manage, control, maintain (including adding Incremental Capital Assets in accordance with Article 17.4.3) and operate the Trimble County Unit 2 Project, as agent for the Parties, giving due consideration to each Party’s respective interest of which the Companies are aware, and the Companies shall take all steps that they deem necessary or appropriate for that purpose.  The Companies shall discharge such obligation and authority in accordance with the standard of conduct established in Article 20.24 and the other provisions of this Agreement.  IMPA and IMEA do hereby appoint the Companies to be their attorney-in-fact for such purposes, which appointment is coupled with an interest, to act in their names, places and steads, and which appointment shall not be revocable during the term of this Agreement.  The Companies may not assign their obligation or authority to manage, control, maintain and operate the Trimble County Unit 2 Project without prior written consent of the Parties, which consent shall not be unreasonably withheld.

7.2Electric Capacity Entitlements.

Each Party’s Electric Capacity Entitlement at any one time shall be the Net Electric Generating Capacity at that time multiplied by that Party’s Percentage.  The Net Electric Generating Capacity shall not exceed the applicable Net Normal Operating Capacity except under criteria established by the Coordination Committee.  The Companies shall declare the Net Seasonal Capacity of Trimble County Unit 2 twice annually.

The Parties shall each be entitled to take up to their respective Electric Capacity Entitlement through Scheduled or Dispatched transactions in accordance with the standard of conduct established in Article 20.24.

Electric Capacity Entitlements and Energy Allocations shall begin at the Commercial Operation Date and continue until Trimble County Unit 2 ceases to be used for the generation of electric energy and is permanently retired from service.

7.3Scheduling and Dispatching of Electric Generation.

When Trimble County Unit 2 is Available, each Party shall have the right, in its sole discretion, to Schedule or Dispatch in accordance with provisions of this Agreement all or any part of its Electric Capacity Entitlement, provided, however, throughout all periods when Trimble County Unit 2 is being operated, each Party shall Schedule or Dispatch no less than its share of Minimum Generation from time to time.  Each Party’s share of Minimum Generation shall be that Party’s Percentage of Minimum Generation, provided, however, if one or more Parties have Scheduled or Dispatched for any one time in excess of their share of Minimum Generation, the other Parties share of Minimum Generation for that time will be reduced by the amount of such excess allocated among them in proportion to their Percentages.  If any Party fails to take its entire share of Minimum Generation, that Party will be responsible for all attendant costs and losses and the Companies may take appropriate corrective actions consistent

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with the standard of conduct established in Article 20.24.  If Trimble County Unit 2 is off line, but Available, the Companies shall cause Trimble County Unit 2 to start up and commence operating at the Request of any Party at any time.

The energy Scheduled or Dispatched by a Party with respect to any hour represents that Party’s requested energy delivery for that hour.  Except to the extent otherwise provided in the following paragraph regarding ramping, each Party will be allocated (its “Energy Allocation”) the actual Trimble County Unit 2 production (net of Auxiliary Power) pro rated to each Party in proportion to the amount of energy they each Requested for that hour.  The Requested energy delivery per hour and the current Energy Allocation per hour will be used every five (5) minutes to forecast each Party’s Energy Allocation for the hour.  Each Party will be provided the current forecast of its hourly Energy Allocation approximately every five (5) minutes through electronic means at such Party’s request and cost.

No Party may at any time submit a Ramping Request for a ramp rate greater than that Party’s Percentage of the then Expected Ramp Rate Capability.  If at any time for any reason Trimble County Unit 2 is unable to produce the aggregate ramp rate required to fulfill two or more Parties’ overlapping Ramping Requests, the then actual ramping capability of Trimble County Unit 2 will be allocated among such Parties in proportion to their respective Percentages, with no Party being thereby allocated a greater ramp rate than it Requested.  The ramping as provided by this paragraph will be reflected in the integrated Energy Allocation to each Party during ramping.

7.3.1Submittal of Schedules.

Unless and until it has elected to Dispatch pursuant to Article 7.3.4 by written notice to the Companies, each Party shall Schedule with the Companies’ generation dispatch staff the amount of electric energy to be delivered for each hour of each day.  The Schedule for each day shall be submitted prior to 12:00 noon E.S.T. of the day prior to that day (or if the day prior is a Saturday, Sunday or holiday recognized by the Companies, the last normal work day prior to the weekend and/or holiday) (or at such other time as is required or permitted by prevailing industry practices applicable to the Companies at the time such Schedule is made).  The Scheduling Party may change Schedules at any time after the deadline for submitting such Schedule only with the mutual consent of the Companies, which consent shall not be unreasonably withheld.

The Companies will endeavor to provide the Parties by telephonic, electronic or other means notice of any non-outage related occurrence expected to cause Trimble County Unit 2 to over or under produce more than ten (10) MWh integrated over any one (1) hour as soon as reasonably practicable after they become aware of such expected change.    IMEA and IMPA may contact the Companies’ designated contact person at any time for an update on unit conditions and expected changes in unit conditions.

7.3.2Scheduling Procedures.  Each Party shall be entitled to Schedule, in accordance with Article 7.3.1, up to the Net Normal Operating Capacity multiplied by its Percentage (with the result of that product rounded to the nearest whole applicable increment) in any hour, provided that, except as mutually agreed by the Parties, the change in any Party’s Schedule from hour to hour shall not exceed such Party’s Percentage of the Expected Ramp Rate Capability over the applicable ramping period.  Each Scheduling Party will be liable pursuant to Article

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7.3.3 for any energy imbalance services required as a result of (i) the portion of the actual ramp rate of Trimble County Unit 2 allocated to the Scheduling Party being different than the ramp rate Requested by the Scheduling Party and (ii) the Energy Allocation for that Scheduling Party being different from the energy Scheduled by that Scheduling Party.  A Scheduling Party may Schedule a ramp greater than its Percentage of the Expected Ramp Rate Capability if it has reached an agreement with the Companies to provide any necessary greater ramp rate and energy from the Companies’ system.  The availability and price of system ramping and energy will be determined at the sole discretion of the Companies and established by agreement between the Companies and the applicable Party prior to the Schedule change.

All Schedules shall be in increments of whole megawatts unless applicable industry rules permit smaller increments and may in no event exceed a Party’s Electric Capacity Entitlement.  Schedules shall show the requested output for each hour of the Schedule period, the beginning and end times of any required ramping and the requested ramp rate.

7.3.3Utilization of Electric Capacity Entitlement and Companies’ System Power.

No Party will deliberately (i) utilize more than its Electric Capacity Entitlement or any portion of another Party’s Energy Allocation or (ii) fail to take all of its Energy Allocation.  Parties will be required to change Schedules on an hourly basis after reserve-sharing energy is utilized within industry scheduling standards, or to change Dispatch signals in real-time to comply with this requirement.  Notwithstanding the preceding sentence, the Parties recognize that variations in the real time operations of Trimble County Unit 2 may result in unplanned variances between a Party’s Energy Allocation and the amount of energy Requested by that Party.  Such variances and the resulting inadvertent utilization by a Party of more or less electric energy on an integrated hourly basis than its Energy Allocation (the Party’s “energy imbalance”) will be rounded to the nearest whole megawatt hour (or such smaller increment that becomes customary in the industry ) and then will be treated as follows:

(x)For that portion of a Party’s energy imbalance that is within a deviation band of +/- 1.5% (or +/-2MW, if greater) of the Party’s Requested energy that hour (the “deviation band”), the amounts will be recorded and aggregated over each calendar month.  At the end of the month, the Companies and the Party will negotiate in good faith to eliminate any net balance for that month by in kind transfers of energy during the following thirty (30) days.  For any net balance not so eliminated by in-kind transfers within thirty (30) days, the Party will purchase or sell such energy from or to the Companies.  The price for such energy sold to the Companies will be ninety percent (90%) of the Companies’ average system lambda (based on fuel cost only) for the hours in the applicable month during which the Party inadvertently utilized less than its Energy Allocation.  The price for such energy purchased from the Companies will be the greater of (a) $100.00 per megawatt-hour, or (b) the Companies’ average actual incremental cost to supply that amount of energy for the hours in the applicable month during which the Party inadvertently utilized more than its Energy Allocation.

(y)For that portion of a Party’s energy imbalance that is outside the deviation band for that hour, that Party will purchase or sell such energy from or to the Companies.  The price for such energy sold to the Companies will be ninety percent (90%) of the Companies’ system lambda (based on fuel cost only) for that hour.  The price for such energy purchased from the

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Companies will be the greater of (a) $100.00 per megawatt-hour, or (b) the Companies actual incremental cost to supply such energy that hour.

(z)Each Party will remain responsible for all costs associated with the production of its Energy Allocation.

7.3.4Dispatching Procedures.

Any Party that elects to Dispatch its Electric Capacity Entitlement shall install and maintain (or otherwise obtain the necessary access and use of) the necessary generation control hardware and software that interfaces with the Companies’ generation control system at its own expense to implement such Dispatch.  At the request of IMEA or IMPA, the Companies will provide IMEA or IMPA with a not-to-exceed price from a vendor that is not an Affiliate of the Companies to accommodate IMEA’s or IMPA’s interfaces with the Companies’ generation control system.  At the completion of the installation, IMEA or IMPA, as applicable, will reimburse the Companies for the actual charges imposed by the vendor.  The Parties will agree in advance to the cost allocation of any future costs required to modify, upgrade or maintain the dispatch capability of Trimble County Unit 2 associated with the Companies’ generation control system.

A Dispatching Party shall be entitled to Dispatch up to its Electric Capacity Entitlement.  Each Party that is Dispatching its Electric Capacity Entitlement will have the right to change its desired output of its portion of Trimble County Unit 2 at any time, subject to the allocation of the unit’s ramping capability as provided in Article 7.3.  Real-time Dispatch shall be executed within the accuracy of the Companies’ generation control system. The real-time Dispatch signal from a Party will be integrated over each hour to determine the Requested energy delivery for that hour.  In the event of a failure of any Party’s generation control system to control the output of Trimble County Unit 2, Dispatching for the affected Party or Parties will be accomplished manually by the Parties coordinating the desired energy to be Dispatched through a contact person designated by the Companies for such purpose.

7.3.5Ancillary Services.

For Dispatching purposes, the Parties shall share in the Attributes of Trimble County Unit 2 in proportion to their respective Percentages as follows:

(i)Regulation.  Any Party that is Dispatching its Electric Capacity Entitlement may use such Dispatching provisions to provide, through Trimble County Unit 2, a reasonable degree of regulation services for its system through appropriate use of automatic real-time generation control equipment normally expected of control areas (including generation only control areas) or load balancing authorities as defined by the North American Electric Reliability Council (“NERC”) or other industry standard setting bodies.  If the Dispatching activities of any of the Parties is found to have an adverse impact on the performance of Trimble County Unit 2 by causing extreme ramping up or down of the output of the generator, the Coordination Committee will address the issue at the request of any Party and establish guidelines for appropriate load following behavior by all Parties.

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(ii)Operating Reserves.  When Trimble County Unit 2 is on line, any Party that is Dispatching may designate the difference between its Electric Capacity Entitlement and the amount of such Electric Capacity Entitlement that it is currently Dispatching as operating reserves to any industry entity that is obligated or permitted to monitor or require such reserves.

(iii)Var Output.  Each Party shall be entitled to its Percentage of the var capability of Trimble County Unit 2 and may utilize such vars itself or sell them to other entities, including the other Parties.  The Coordination Committee will establish the procedures for requesting vars and having such requests fulfilled, which procedures shall be comparable to those set forth in this Agreement for Electric Capacity Entitlement.  No Party will be obligated to buy vars from another Party.  No Party will utilize another Party’s var capability without the other Parties’ permission.  If industry practices permit, each Party may sell varhours to other entities.  If the Companies are compensated for providing var support with respect to IMPA’s and IMEA’s use of Trimble County Unit 2, the vars used to provide such support will be deemed to be IMEA’s and IMPA’s and the Companies will pass through such compensation to IMEA and IMPA as applicable.

(iv)Other Ancillary Services.  If, through changes in industry practices or otherwise, additional services can be derived or are required from Trimble County Unit 2, such services will be shared among the Parties in proportion to their respective Percentages.

7.3.6Holidays.

Prior to each calendar year, the Companies shall notify the Parties of the holidays to be recognized by the Companies for that year.  In the event the Companies fail to provide such notice, the holidays shall be the same as for the prior year.

7.3.7Records.

The Companies shall maintain records adequate to determine each Party’s energy utilization per hour.

7.3.8Outage Schedules.

The Companies shall submit to the Parties, as far in advance as practicable, schedules showing the expected start date and time (“Start”) and duration for planned outages of Trimble County Unit 2.  The Companies will adjust such plans to accommodate any Party’s request, where such adjustment would not harm any other Party and where, in the Companies’ sole judgment, it is practicable to do so in accordance with the standard of conduct established in Article 20.24.  The Companies shall seek the unanimous approval of the other Parties to change the Start of planned outages once the outage plan has been submitted by the Companies and accepted by the other Parties, provided, however, if such approval is not granted, the Companies shall have the right to change the Start of planned outages up to (and including) forty-five (45) days before then planned Start.  The Companies may change the Start of planned outages less than forty-five (45) days before the then scheduled Start only if they receive the unanimous consent of the other Parties (which consent shall not be unreasonably withheld) or if such change is required for protection of the Trimble County Unit 2 Project or the electric system for reasons consistent with the standard of conduct established in Article 20.24.

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For maintenance outages (and unplanned postponed outages, if possible), the Companies shall not change the Start within 48 hours prior to the then planned Start without the unanimous consent of the other Parties (which consent shall not be unreasonably withheld) unless such change is required for protection of the Trimble County Unit 2 Project or the electric system for reasons consistent with the standard of conduct established in Article 20.24.  Should any of the Parties desire a schedule for maintenance outages (or unplanned postponed outages, if possible) that the Companies believe is impracticable or which another Party believes is injurious to it, any Party shall be entitled to submit the scheduling issue to the Coordination Committee for resolution provided that adequate time (at least 48 hours) is available to convene the Coordination Committee and resolve the conflict.  The terms, “planned,” “maintenance” and “unplanned postponed,” when used to describe outages, are intended to have the meanings ascribed to them by the NERC Generation Availability Data System.

7.4Pre-Commercial Energy.

Any net electric energy output from Trimble County Unit 2 prior to the Commercial Operation Date shall be classified as pre-commercial energy.  Each Party shall be liable for and pay its Percentage of all costs associated with such energy production including fuel and reactant costs and any automatic reserve sharing or other similar charges imposed on the Companies as a result of fluctuations in the energy produced by Trimble County Unit 2.  Each Party shall also take and dispose of its Percentage of all pre-commercial energy and will be liable for applicable energy imbalance charges should it fail to do so; provided, IMEA and IMPA shall each have the option (which option may only be exercised by giving the Companies notice at least ninety (90) days prior to the first scheduled production of pre-commercial energy by Trimble County Unit 2) to sell all of its Percentage of such energy to the Companies at a price each month per megawatt hour equal to the average cost that month of fuel and reactant used to produce a megawatt hour of electric energy at Trimble County Unit 1.

7.5Operations Management.

7.5.1Administration of Operating Work and Incremental Capital Assets.

The Companies shall perform all work, or execute and enforce (including any renegotiation and settlement of) all contracts, contractual obligations and arrangements for Operating Work and Incremental Capital Assets, including any and all warranties on equipment, facilities, materials, and services furnished pursuant to any such contracts.  Warranties claims and other claims arising under this Article shall be administered in accordance with the provisions of Articles 7.5.6 and 7.5.7.

7.5.2Purchasing Necessary Goods and Services.

The Companies shall purchase and procure, through and from any source they may select, the equipment, apparatus, machinery, tools, services, materials and supplies, and spare parts necessary for the performance of Operating Work or as Incremental Capital Assets.

7.5.3Procurement of Fuel.

At all times, the Companies shall maintain an adequate supply of fuel in accordance with the standard of conduct established in Article 20.24.  At any time when the Companies determine

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to enter into fuel procurement negotiations for all or any part of the fuel requirements of Trimble County Unit 2, the Companies shall notify the other Parties in a reasonable and timely manner specifying the characteristics of the fuel being sought and the schedule for procurement.  During the Companies’ Trimble County Unit 2 fuel procurement negotiations, if IMPA or IMEA notify the Companies in a reasonable and timely manner and in accordance with the proposed procurement schedule, of alternative fuel supplies with equivalent or better quantities, quality, delivered cost, and/or other factors that affect Trimble County Unit 2 operation such that overall costs and reliability of Trimble County Unit 2 are improved, then such alternate supplies shall be considered by the Companies, in good faith, for Trimble County Unit 2 fuel procurement.  No such alternative fuel supplies shall be selected unless the alternative fuel supplies meet or exceed the fuel specifications for Trimble County Unit 2 as defined by the Companies and the delivered cost of the alternative fuels results in a decrease in total fuel cost for Trimble County Unit 2.

7.5.4Expenditure of Funds.

The Companies shall expend funds in accordance with the terms and conditions of this Agreement.

7.5.5Insurance.

The Companies shall arrange for the placement and maintenance of insurance, as provided in Article 13.

7.5.6Enforcement of Claims.

During the term of this Agreement, the Companies shall have the obligation to investigate, present and prosecute known claims with respect to the Trimble County Unit 2 Project, including claims against insurers and indemnitors providing insurance or indemnities with respect to any loss of or damage to any property of the Trimble County Unit 2 Project, or any interest of the Parties pertaining thereto, and with respect to any liability of the Parties covered by insurance or an indemnity agreement.  To the extent that such loss, damage, or liability is not covered by insurance or by an indemnity agreement, the Companies shall present and prosecute claims therefor against any Persons who may be liable therefor, provided, however, the Companies are not required to resort to litigation or an alternative resolution procedure against an Affiliate of the Companies or to initiate, present, or prosecute any claim which, in their sole judgment exercised in good faith, is without sufficient merit to warrant such enforcement, or otherwise is inconsistent with the Parties’ general business interests related to the Trimble County Unit 2 Project.  Nothing herein shall require the Companies to invoke any certain type of enforcement procedure, or to seek, or to continue to seek, enforcement of any claim, when in the Companies’ sole judgment, the Parties’ general business interests related to the Trimble County Unit 2 Project are better served by settling or withdrawing such claim.   If the amount of any such claim by the Parties against non-Affiliates of the Companies arising out of the (i) Development Phase or the Construction Phase exceeds five hundred thousand dollars ($500,000) or (ii) Operating Phase exceeds two hundred fifty thousand dollars ($250,000), the Companies shall notify the Parties of the existence and nature of such claim and shall also notify the Parties if and when any settlement of any such claim is accomplished by the Companies.

In the event that the Companies do not diligently attempt to settle or, failing settlement, prosecute a claim nothing herein shall prevent IMEA or IMPA from prosecuting such claim or

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demand in its own name, to the extent of, and as such claim or demand affects its interest, provided, however, with respect to material claims against Affiliates of the Companies, IMEA and IMPA shall refrain from prosecution or demands until the Companies have had a reasonable period to settle or resolve such claim as provided below.  Costs and expenses IMPA or IMEA incurs in prosecuting such claim shall be borne by IMPA or IMEA, as the case may be and the proceeds recovered are to be shared by the Parties prosecuting such claim in proportion to their respective Percentages.

The Companies shall provide prompt written notice to IMPA and IMEA of any material claim against any Affiliate of the Companies of which they have knowledge.  Invoices disputes or other claims involving amounts less than two hundred fifty thousand dollars ($250,000) shall not constitute “material claims” for purposes of this Article 7.5.6.  The Companies, on behalf of the Parties, shall be entitled to settle or resolve claims against their Affiliates, provided, however, the Companies shall not be entitled to settle or resolve a material claim without the prior consent of the Parties, which consent shall not be unreasonably withheld.  Other than settling or resolving claims against Affiliates in good faith and in accordance with this Article 7.5.6, the Companies shall neither take any action nor refrain from taking any action that might impair the ability of IMEA or IMPA to prosecute such claims as provided herein.

Any Party, at its own expense, may intervene in any proceeding on a claim pursuant to this Article as an additional party to assert or defend its respective Ownership Interest and rights.

7.5.7Processing Claims.

During the term of this Agreement, the Companies shall have the obligation, as appropriate, to investigate, adjust, defend and settle claims against the Parties, or any of them, arising out of or attributable to the Work, Incremental Capital Assets, or the past or future performance or nonperformance of the obligations and duties of the Parties under or pursuant to this Agreement, including any claim resulting from death or injury to persons or damage to property, when such claims are not covered by valid and collectible insurance carried by the Parties; and, whenever and to the extent reasonable, present and prosecute claims against any third party, including insurers, for any costs, losses, and damages incurred in connection with such claims.  If the amount of any such claim against the Parties by a non-Affiliate of the Companies exceeds one hundred thousand dollars ($100,000) and is not covered by valid and collectible insurance carried by the Parties, the Companies shall notify the Parties of the existence and nature of such claim and shall also notify the Parties if and when any settlement of any such claim is accomplished by the Companies.  Settlement of such claims in excess of two million dollars ($2,000,000) shall be reported to and approved in advance by the Coordination Committee.

In the event of (i) a claim by an Affiliate of the Companies or (ii) any other claim that the Companies have not diligently attempted to settle or defend, nothing herein contained shall prohibit IMEA or IMPA from defending such claim to the extent of and as such claim affects its interest.  Costs and expenses incurred in connection with any such defense or demand shall be borne by the defending Party or Parties, provided, however, if the resolution of such claim accrues to the benefit of non-defending Parties, such non-defending Parties shall share the defense costs and expenses incurred in accordance with their respective Percentages, but only to the extent of the fair value of the benefits received from such resolution.

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The Companies shall provide prompt written notice to IMPA and IMEA of all pending material claims by any Affiliate of the Companies.  Invoice disputes or other claims involving amounts less than two hundred fifty thousand dollars ($250,000) shall not constitute “material claims” within the meaning of this Article 7.5.7 (unless and until such claim is the subject of arbitration or litigation), and may be settled by the Companies.  Material claims by Affiliates of the Companies may also be settled by the Companies, subject to the consent of IMPA and IMEA, which consent shall not be unreasonably withheld.  Other than settling or resolving claims by their Affiliates in good faith and in accordance with this Article 7.5.7, the Companies shall neither take any action nor refrain from taking any action that might impair the ability of IMEA or IMPA to defend such claim.

Any Party, at its own expense, may intervene in any proceeding on a claim pursuant to this Article as an additional party to assert or defend as to its respective Ownership Interest and rights.

7.5.8Delivery of Operating Data.

As promptly as practicable after the end of each month, the Companies shall render to the Parties a statement setting forth mutually agreed upon operating data as may be needed for reports and records.

7.6Environmental Laws and Regulations.

Each Party shall be responsible for its share, in proportion to its Percentage, of any obligations, costs, or burdens of any kind, resulting from any federal, state, or local environmental law, regulation, or requirement, as amended from time to time.  Similarly, each Party shall be entitled to its share, in proportion to its Percentage, of any rights, credits, entitlements, or allowances associated with such law, regulation, or requirement, as amended from time to time.

Each Party’s rights to generation from Trimble County Unit 2 shall be conditioned upon such Party’s compliance with such environmental laws, regulations, or requirements and such Party’s possession of required environmental rights, credits, entitlements, or allowances needed for such generation.

Any Party, to the extent its rights, credits, entitlements or allowances are insufficient to allow the desired level of generation from that Party’s share of Trimble County Unit 2 may acquire such rights, credits, entitlements or allowances from another Party, if available, under terms and at prices agreeable to such Parties.

The Companies shall provide information to the other Parties regarding rights, credits, entitlements or allowances that have been used or consumed by those Parties.  Each Party shall keep the Companies informed as to that Party’s available rights, credits, entitlements, or allowances for use at the Trimble County Unit 2 Project and shall forecast that Party’s need for additions thereto.  On not less than ten (10) calendar days’ prior written notice to IMPA or IMEA, as appropriate, and provided that IMPA or IMEA, as appropriate, has not obtained such rights, credits, entitlements or allowances and provided written evidence thereof to the Companies within such ten (10) calendar day period, the Companies shall have the right to

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obtain such rights, credits, entitlements or allowances for IMPA or IMEA, at IMPA’s or IMEA’s respective cost, (including reasonable documented transaction costs), if necessary to ensure continued operation of Trimble County Unit 2.

7.7Environmental Fines and Penalties.

The Companies shall indemnify IMPA and IMEA against administrative fines and civil penalties arising out of the operation of the Trimble County Unit 2 Project imposed for violations of applicable environmental laws and regulations, resulting from acts or omissions inconsistent with the standard of conduct established in Article 20.24 of either of the Companies or any Affiliate of Louisville or Kentucky Utilities when acting in the capacity of plant operators.  Exclusions from this special indemnification shall include operation and maintenance costs incurred as a result of environmental Applicable Law, Incremental Capital Assets incurred in environmental compliance, occurrences from acts of IMPA, IMEA or third parties or from equipment failure or malfunction, remedial measures imposed by administrative agencies for environmental purposes, reimbursement of response costs under Comprehensive Environmental Response Compensation and Liability Act (“CERCLA”) and K.R.S. Chapter 224 and amendments thereto, or any similar or subsequently enacted legislation covering the same subject matter as CERCLA and K.R.S. Chapter 224, and any claims of personal injury or property damage.

7.8General Facilities and Constraints.

Subject to Articles 2.2 and 2.3, should a condition or circumstance exist that would constrain the full and simultaneous utilization of Trimble County Unit 2 and other then existing generating units at the Trimble County Site, the Companies shall allocate the available resources between or among such units (including Trimble County Unit 2).  If the Parties’ interests in the affected units are not uniform (i.e., one or more Parties have substantially different interests in one or more of the affected units than in others) and the allocation of resources made by the Companies does not result in generation from the affected units proportionate to their respective capacities, the Parties, to the extent possible, agree to make such economic adjustments among themselves, together with the owners of such other units, as to accomplish a fair economic result.  For the purposes of this Article 7.8, subject to Article 14 and Article 15, and so long as they are Affiliates of each other, the interest of Kentucky Utilities in Trimble County Unit 2 and any affected units shall be deemed to be an interest of Louisville when assessing whether the Parties’ interests in the affected units are uniform.

7.9Rules and Regulations in Industry Practices.

The Coordination Committee may, by unanimous agreement, adopt and amend rules from time to time to amend the operating arrangements set forth in this Article 7.  When unanimously adopted or amended, such rules shall supersede the applicable provisions of this Article 7. The Parties agree that they will cause the Coordination Committee to unanimously adopt and amend rules from time to time as necessary to reflect changes in industry standards, Applicable Law, and the rules and regulations of transmission organizations that apply to the Parties so that the following principles are maintained in a manner similar to the way this Article

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7 reflects these principles relative to the state of the industry, Applicable Law, and such rules and regulations as of the date of this Agreement:

(i)The Parties recognize that Trimble County Unit 2 is physically located in the control area operated by the Companies.  As such, IMPA and IMEA need the Companies’ cooperation to Schedule or Dispatch their respective Ownership Interests in Trimble County Unit 2.  So long as this remains the case, the rules shall provide for such cooperation.

(ii)The rules will be consistent with the standard of conduct established in Article 20.24.

(iii)At any one moment in time, each Party shall be entitled to the benefit of its Percentage share but not more than its Percentage share of any of the Attributes.

(iv)No Party will deliberately take any action that might result in its taking at any one moment a greater share of the Attributes than that to which it is entitled.

(v)Each Party is responsible for transmission and transmission costs for its Allocated Energy.

(vi)No Party will be entitled to be better situated than it would have been had it operated its own generating unit of a capacity equal to its Electric Capacity Entitlement.  Similarly, no Party shall be less favorably situated than it would have been had it operated its own generating unit of a capacity equal to its Electric Capacity Entitlement.

(vii)No Party shall have rights to services or attributes associated with another Party’s system of generation and transmission without paying fair compensation for such services or attributes in accordance with then current industry standards.

(viii)None of the Parties will vote against any proposed rule to amend the operating provisions set forth in Article 7 to the extent such rule is proposed by another Party to enable it to form a generation only control area containing that other Party’s Electric Capacity Entitlement or to use dynamic scheduling, so long as such rule does not involve (a) providing any Party more than its Percentage share of any of the Attributes at any time, or (b) allocating the costs and burdens of such rule to Parties that do not benefit from it.

ARTICLE 8.
INCREMENTAL CAPITAL ASSETS

8.1Estimate of Costs.

Prior to beginning work on any Incremental Capital Asset which the Companies expect to cost more than $2,000,000, an estimate of such work shall be furnished by the Companies in reasonable detail to the Coordination Committee for use by it in anticipating its financial requirements.  Such estimate shall be subject to revision periodically to reflect more current information on such Incremental Capital Asset.

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8.2Responsibility for Costs.

Subsequent to the Commercial Operation Date, the costs of each Incremental Capital Asset shall be borne by the Parties in proportion to their respective Percentages.  The amount incurred for Incremental Capital Assets during each month shall be included in the monthly billings provided for in Article 10.

ARTICLE 9.
EXPENSES

9.1Payment of Expenses and Charges Prior to the Commercial Operation Date.

The Parties will share all Development Costs and Construction Costs in proportion to their respective Percentages.  During the Development Phase (following the Development Closing) and the Construction Phase (or until such later date as payments remain due in respect of such phases), no later than the fifteenth (15^th) calendar day of each calendar month, the Companies shall provide to each Party an invoice of Development Costs (including Deferred Development Costs) or Construction Costs (and, in each case, the supervisory fees thereon) that have been incurred and, without duplication, that will be incurred and become payable by the Companies on or prior to the last calendar day of the next succeeding calendar month (“Future Amounts”).  In consideration for the undertaking of the Companies to supervise the Development Work and the Construction Work, the Companies shall be entitled to a supervisory fee equal to two percent (2%) of the aggregate amount of Development Costs and Construction Costs to be paid by each of IMPA and IMEA.  Each invoice prepared by the Companies for IMPA and IMEA under this Article 9.1 shall include such fee.  Payments of invoiced amounts are due on or before the fifteenth (15^th) calendar day of the month subsequent to the month in which the invoice is received provided, however, IMPA’s and IMEA’s respective share of Deferred Development Costs, shall be due and payable to the Companies on April 1, 2004.  It is the intent of the Parties that the issuance of invoices for payment by the Companies, and the subsequent payments to the Companies shall be made at such times as may be necessary to allow timely payment to the contractors by the Companies in accordance with the terms of payment of applicable contracts, including the Construction Contracts.  In the event the aforementioned payment procedures do not allow for receipt of payment from the Parties or timely payments by the Companies to contractors, including Construction Contractors, for amounts greater than $1,000,000 from time to time, the Companies may issue an additional invoice each month, in accordance with the foregoing terms of this paragraph, with payment due no sooner than fourteen (14) calendar days after receipt of such invoice.  To the extent amounts due in respect of an invoice include amounts to be paid under the Construction Contracts, each Party shall be provided with copies of the invoices under such contracts.  The Companies shall have the sole authority and obligation to determine the validity of such invoices.  Invoices shall be accompanied by reasonable documentation of all other amounts specified therein.  In the event that IMPA or IMEA incurs Development Costs or Construction Costs at the request of the Companies during the period subsequent to Development Closing and during the Development Phase or the Construction Phase, the Parties will aggregate such expenses and, at least once per quarter but not more often than monthly, make such inter-Party payments so that each Party pays its proportionate share of such costs.

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9.2Monthly Expenses and Charges After the Commercial Operation Date.

In addition to Development Costs and Construction Costs (and, in each case, the supervisory fee thereon) that are incurred and are invoiced pursuant to Article 9.1, following the Commercial Operation Date, the Parties will share all costs associated with the Trimble County Unit 2 Project in proportion to their respective Percentages.  These costs are set forth below in four (4) components for billing and accounting purposes.  The Parties intend that these components incorporate all costs that are or could be associated with the Trimble County Unit 2 Project.  Should any item or category of cost not fall within the technical definitions of any of the four components, the Parties agree to adjust the billing components so as to include such item or category.

Starting on the Commercial Operation Date, the Parties shall pay, in accordance with Article 10, a monthly amount equal to the sum of the four components delineated in Articles 9.2.1, 9.2.2, 9.2.3, and 9.2.4.

9.2.1Fuel/Reactant Operation Expenses.

All Fuel/Reactant Operation Expenses of Trimble County Unit 2 will be prorated to the Parties, according to the net electric energy delivered to the Delivery Point for each Party as compared to the total net energy delivered to the Delivery Point by Trimble County Unit 2.

9.2.2Fixed Operation and Maintenance Expenses.

A Fixed Operation and Maintenance Expenses component shall be shared by the Parties in proportion to their respective Percentages.  The Companies shall allocate a reasonable portion of all Fixed Operation and Maintenance Expenses shared among all generating and other assets or enterprises located on the Trimble County Site to Trimble County Unit 2 in its annual Operation and Maintenance Budget, pursuant to Article 17.4.4, and in accordance with procedures established by the Coordination Committee.

9.2.3Non-Fuel Operating Component.

A non-fuel operating component shall be shared by the Parties in proportion to their respective Percentages, calculated monthly as the sum of the following four (4) items as they relate to the operation and maintenance of Trimble County Unit 2:

(i)Taxes other than federal and state income taxes (Account 408.1), except that those categories of taxes, or payments in lieu thereof, that are directly billed to the Parties by the taxing authority and paid by the Parties, shall not be contained in this item.

(ii)Administrative and general expenses as recorded in Accounts 920 – 930 as recorded under the Uniform System of Accounts.

(iii)Lease payments, which result from a third-party-financed Incremental Capital Asset or lease payments for other items of property pursuant to Article 2.1.

(iv)Penalties (Account 426.3), except for those environmental penalties against which the Companies have agreed to indemnify IMPA and IMEA under Article 7.7.

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The Companies shall allocate a reasonable portion of all non-fuel operating costs shared among all generating and other assets or enterprises located on the Trimble County Site to Trimble County Unit 2 in its Annual O&M Budget, pursuant to Article 17.4.4, and in accordance with procedures established by the Coordination Committee.

9.2.4Working Capital Component.

A working capital component shall be shared by the Parties in proportion to their respective Percentages.  Prior to the Commercial Operation Date, at a date determined by the Coordination Committee, the Companies shall calculate the estimated amount of working capital necessary for the operations of the Trimble County Unit 2 Project.  IMPA and IMEA shall fund their respective share of working capital to the Companies prior to the Commercial Operation Date.  This component is composed of the items listed below, to the extent that each of these items relates to the Trimble County Unit 2 Project:

(i)Fuel stocks (Account 151)

(ii)Fuel stock expenses undistributed (Account 152)

(iii)Plant materials and operating supplies (Account 154)

(iv)Stores expense undistributed (Account 163)

(v)Prepayments (Account 165)

(iv)Miscellaneous deferred debits (Account 186)

After the Commercial Operation Date, the Companies, on a monthly basis, shall compute the additions or reductions in working capital by multiplying the beginning monthly balances of the above items by the respective Percentage of IMPA and IMEA.  Resulting changes in working capital shall be paid or credited monthly in accordance with the billing procedures set forth in Article 10.2.

The Companies shall allocate a reasonable portion of all working capital costs shared among all generating and other assets or enterprises located on the Trimble County Site to Trimble County Unit 2 in its Annual O&M Budget, pursuant to Article 17.4.4, and in accordance with procedures established by the Coordination Committee.

ARTICLE 10.
BILLING, PAYMENTS, AND RECORDS

10.1Payments before Commercial Operation Date.

During the Development Phase and the Construction Phase of the Trimble County Unit 2 Project, all payments will be made by the Parties pursuant to Article 3, Article 6, and Article 9, as each Article applies.

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10.2Billings by the Companies after the Commercial Operation Date.

As promptly as practicable, but in any event not more than twelve (12) working days after the end of each calendar month during the term of this Agreement following the Commercial Operation Date, the Companies shall prepare and send to each Party an invoice, in such detail and with such segregations as may be needed for operating and accounting records, to indicate monthly amounts due under this Agreement.

10.3Payments after the Commercial Operation Date.

After the Commercial Operation Date, amounts due by a Party as specified in invoices issued by the Companies pursuant to Article 10 shall be due and payable in immediately available funds on the thirtieth (30th) calendar day following the invoice date.  Amounts owed by any Party to another Party under this Agreement, other than under Articles 10.1 and 10.2, shall be settled in accordance with the procedures set forth in such provisions as give rise to the obligations.  In the absence of specific procedures, amounts shall be due by the thirtieth (30^th) calendar day following receipt of a written demand or invoice therefor.  Interest on unpaid amounts shall accrue at the Agreed Rate from the date due until the date upon which payment is made.  Payments by any Party to another Party based on over-billing shall bear interest at the Agreed Rate beginning on the thirty-first (31^st) calendar day after the invoice (or demand) date and running until such amount is repaid or credited.  Unless otherwise agreed upon, a calendar month shall be the standard monthly period for the purpose of settlements under this Agreement.

10.4Records.

The Companies will record their accounting information in accordance with generally accepted accounting principles, as modified by the requirements or permitted practices of applicable regulatory authorities.  For the purpose of this Agreement, all account references are to the Uniform System of Accounts.  In the event of any changes in FERC’s accounting procedures that might result in charges different from those contemplated by the Agreement, the Parties will agree upon the appropriate changes to the Agreement to achieve the original intent of the Parties, unless otherwise mutually agreed by the Parties.

The Parties shall keep and maintain such records as may be necessary or useful in carrying out this Agreement.  Each Party shall keep such records as may be needed to afford a clear history of all transactions under this Agreement and make copies of such records available to the other Parties upon request.  Each Party shall have the right during normal business hours, but no more than once each calendar year, at its own expense, to audit, or cause independent certified public accountants of its choice to audit, the accounting and other records relating to transactions under this Agreement and shall have the right to make copies of records as necessary, provided that neither IMPA nor IMEA shall be permitted to retain documents (whether hard copy or electronically) that one or both of the Companies has designated as confidential or proprietary where to do so would make such records open records under any “open records” or “public records” Applicable Law.  No Party shall make use of records of another Party without the express written consent of such Party, except for disclosure or use that is permitted by this Agreement or where required by Applicable Law, or for purposes of litigation or alternative dispute resolution procedures.  All such records shall be considered the

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confidential and proprietary business records of the Party that generated the particular record in question.  Any such consent shall not be withheld unreasonably.

10.5Timing of Certain Payments.

If the due date for any payment to be made to any Party pursuant to this Agreement falls on a Saturday, Sunday or other calendar day on which the Federal Reserve wire transfer system is not available, then such due date shall be deemed to be the next calendar day on which such wire transfer system is available.

10.6Payment to Specified Account.

All payments under this Agreement to a Party or Parties shall be made in immediately available funds to an account or accounts specified by such Party or Parties.  Such Party or Parties may change the account or accounts on no less than five (5) calendar days written notice to the other Parties.

ARTICLE 11.
INTERCONNECTION AND TRANSMISSION SERVICES

The Parties shall share proportionately the actual costs of interconnection of Trimble County Unit 2 in accordance with the Interconnection and Operating Agreement.  Such costs are estimated, as of the date hereof, in Appendix G.  Actual costs of interconnection include necessary transmission upgrades and additions required to reliably and safely connect Trimble County Unit 2 to the regional transmission grid, without facility upgrades or additions related to transmission delivery to particular points of delivery.  Ongoing costs of interconnection, as determined in accordance with the Interconnection and Operating Agreement, shall be borne by the Parties in proportion to their respective Percentages.  Although, as contemplated by Article 6.3(vi), IMPA and IMEA are expected to be parties to the Interconnection and Operating Agreement they will not be entitled to receive transmission credits from the transmission owners group of the Companies unless the Companies specifically receive transmission revenue from the Applicable Transmission Provider for IMPA’s and IMEA’s use of the interconnection upgrade.

Each Party covenants to use its respective Best Efforts to secure a Transmission Service Arrangement with the Applicable Transmission Provider in accordance with the schedule established in Article 5.3.  Each Party shall pay the costs and expenses associated with its Transmission Service Arrangement with the Applicable Transmission Provider and shall bear its individual system upgrade expenses required to deliver its proportionate share of Trimble County Unit 2 output to its respective points of delivery from the Trimble County Plant switchyard.  The Parties agree to cooperate and reasonably assist each other in the efforts of the individual Parties to secure their transmission needs.  Actual costs of requested cooperation shall be fairly allocated to and paid or reimbursed by the Party or Parties benefiting therefrom.

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ARTICLE 12.
TAXES

12.1Management of Tax Matters.

Except for any payments of taxes or payments in lieu thereof which are directly billed to IMPA or IMEA by any taxing authority and which IMPA and IMEA shall pay directly, and except for any rulings that IMPA or IMEA might require in connection with the issuance of tax-exempt bonds, the Companies shall have the authority and responsibility for administering, coordinating, filing returns, making property tax declarations, paying, seeking official tax rulings or determinations, and other related functions pertaining to all taxes, payments in lieu of taxes, assessments, impositions, charges, and related costs of every kind and nature, ordinary, or extraordinary, general or special, foreseen or unforeseen, settled or pending settlement, including property, sales, use, and payroll taxes, connected with or arising out of the development, construction, ownership, operation, maintenance, alteration, repair, rebuilding, use or retirement of the Trimble County Unit 2 Project or any part thereof, (collectively “Taxes”) which are or may be imposed by any taxing authority, whether federal, state, local, municipal, interregional, or quasi-governmental authority, provided, however, unless specifically authorized in writing by IMPA and/or IMEA, such authority shall not extend to any act or action affecting any exemption or special tax treatment arising out of the Trimble County Unit 2 Project to which IMPA or IMEA may be entitled.  IMPA and IMEA do hereby appoint the Companies to be their attorneys-in-fact, which appointment is coupled with an interest, to act in their names, places and steads for the purpose of exercising the tax authority described herein, filing returns, making property tax declarations, payment negotiating, seeking adjustments or revisions, protesting, seeking official tax rulings or determinations, contesting, making application for and claiming any and all exclusions, exemptions, deductions, credits and elections pertaining to all such taxes, payments in lieu of taxes, assessments, impositions, charges, and related costs. Such appointment shall not be revocable during the term of this Agreement.  IMPA, IMEA, their agents, or assigns shall promptly join in any action reasonably required which is consistent with the exercise by the Companies of the tax authority described herein and the status of IMPA and IMEA as governmental entities.

12.2Sharing of Taxes and Related Payments

All Taxes shall be shared and borne by the Parties in proportion to their respective Percentages, provided, however, IMPA and IMEA shall be entitled to the entire benefit to the extent of actual realizations, of their respective exemptions from and reductions of taxes, including property, sales, use, and payroll taxes, connected with or arising out of the ownership, operation, maintenance, alteration, repair, rebuilding, use, or retirement of the Trimble County Unit 2 Project or any part thereof, which may be realized because of the provisions of the Constitutions of the Commonwealth of Kentucky, the State of Indiana, the State of Illinois, or the United States of America, or statutes, ordinances, rules, regulations, or laws applicable to IMPA and/or IMEA but not to the Companies.

The portion of Taxes that are to be borne by IMPA and IMEA, respectively, as set forth in this Article 12.2 shall be billed to and paid by IMPA and IMEA in accordance with Articles 9

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and 10, as applicable, except for those which are paid by IMPA and IMEA, respectively, directly to the taxing authority.

12.3Payment of Title Taxes and Fees.

All Taxes, recording fees and other impositions relating to the transfer of real property, if any, incurred in connection with the conveyances contemplated in this Agreement shall be borne by the transferees of such real property.  Except as provided in the first sentence of this Article 12.3 or in Article 12.2, all Taxes arising out of the Development Work or the Construction Work shall be deemed to be Development Costs or Construction Costs, respectively.

12.4Exclusion of Income Taxes.

Notwithstanding the generality of Article 12.1 above, the Parties agree that the foregoing provisions of this Article 12 shall not apply to any tax on or measured by net income.

12.5Non-creation of Taxable Entity.

Notwithstanding any other provision of this Agreement, the Parties do not intend to create hereby at law any joint venture, partnership, association taxable as a corporation, or other entity for the conduct of any business for profit.  The Parties agree to elect under Section 761(a) of the Internal Revenue Code of 1986, as amended, to exclude the transactions created by this Agreement from the application of Subchapter K, Chapter 1 of the Code, and the Parties agree to revise the terms of this Agreement to the extent and in a manner necessary to permit such election.

ARTICLE 13.
INSURANCE

13.1Procurement of Insurance.

Except with regard to directors and officers liability insurance, the Companies shall maintain in force, for the benefit of the Parties as their interests in the Trimble County Unit 2 Project shall appear, such insurance and self-insurance as the Coordination Committee shall determine to be appropriate.

13.1.1Sharing of Insurance Costs.

The costs of insurance policies referenced in Article 13.1 shall be shared by the Parties in proportion to their respective Percentages.  IMPA and IMEA shall also pay any additional premium that results from IMPA and IMEA being named as an additional insured party on the Companies’ existing policies.  The Parties shall also bear proportionate responsibility for costs of and any losses incurred within the limits of any deductibles or self-insured retentions on policies of insurance.  The Parties’ share of such insurance costs and the costs arising from claims covered by self-insurance shall be shared by the Parties in proportion to their respective Percentages and shall be paid in accordance with Articles 9 and 10, as applicable.

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13.1.2The Parties Named as Insured.

IMPA and IMEA shall be named as either insureds or additional insureds on such insurance policies.  The Companies shall cause the insurance underwriters to furnish the Parties with a certificate of insurance of each such insurance policy.  In addition, the Companies shall have each of such policies endorsed to provide that IMPA and IMEA shall be given the same advance notice of cancellation or material change as is required to be given to the Companies.  Subject to the decisions of the Coordination Committee, a loss or claim, if any, under such insurance policies shall be adjusted and settled by the Companies with the insurance underwriters.

13.1.3Procurement of Additional Insurance for the Parties.

Any Party may obtain at its cost additional insurance beyond that provided for in this Article 13 to insure its interest in the Trimble County Unit 2 Project.  With respect to such additional insurance:

(i)the proceeds from any claim arising through such additional insurance shall be disbursed to the Party providing the insurance; and

(ii)the loss or claim, if any, under such additional insurance shall be adjusted and settled by the Party providing the insurance.

13.1.4Sharing of Refunds from Insurance Premiums.

Any refunds of insurance premiums shall be allocated among the Parties on the same basis as the premium payment allocation from which such refund was derived.

13.1.5Sharing of Insurance Proceeds.

In the event of damage to property insured under this Article 13, it is agreed that the proceeds from insurance obtained by the Companies on behalf of the Parties shall be shared by the Parties on a pro rata basis based on their relative payments of insurance premiums covering the damaged property.

13.2Destruction.

13.2.1Damage or Destruction Fully Covered By Insurance.

If property insured under this Article 13 or any portion thereof should be damaged or destroyed to the extent that the cost of repairs or reconstruction is estimated to be covered by the aggregate amount of insurance coverage (without regard to any deductible) carried by the Companies for the benefit of the Parties pursuant to Article 13, then the Companies shall cause such repairs or reconstruction to be made so that such property shall be restored to substantially the same general condition, character, or use as existed prior to such damage or destruction, provided, however, if the estimate is wrong, and the insurance proceeds are insufficient to pay the cost of repair or reconstruction, the Parties shall share the cost not reimbursed by such insurance in proportion to their respective Percentages.

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13.2.2Damage or Destruction Not Fully Covered by Insurance.

If Trimble County Unit 2, the Trimble County General Plant Facilities or any portion thereof as they pertain to Trimble County Unit 2, should be damaged or destroyed to the extent that the cost of repairs or reconstruction is estimated to be more than the aggregate amount of insurance coverage (without regard to any deductible) carried by the Companies for the benefit of the Parties or by one or more of the other Parties for the benefit of the Parties pursuant to Article 13 hereof and covering the cost of such repairs or reconstruction, then, if the Companies elect to repair and reconstruct such property and upon agreement of the Companies and the other Parties, the Companies shall cause such repairs or reconstruction to be made and the Companies and the other Parties shall share the costs of such repairs or reconstruction not reimbursed by such insurance, in proportion to their respective Percentages, provided, however:

(i)If IMPA or IMEA elects not to join the Companies in repairing and reconstructing such property, then, at the Companies’ election, the Parties shall determine the monetary amount to be paid by the Companies to IMPA or IMEA or by IMPA or IMEA to the Companies, as provided for in paragraph (ii) of this Article 13.2.2.  Upon payment of such monetary amount by the Companies to IMPA or IMEA or by IMPA or IMEA to the Companies, as the case may require as set forth in said paragraph (ii), IMPA or IMEA shall transfer its entire Ownership Interest in Trimble County Unit 2 and the Trimble County Unit 2 Site, its license to use the Trimble County General Plant Facilities, and its easement to the Trimble County Site, to the Companies free and clear of all liens, security interests, charges, claims and other encumbrances, and this Agreement shall be (a) appropriately amended if only one Party other than the Companies elects not to join the Companies in repairing and reconstructing such property or (b) deemed to have expired if IMEA and IMPA both elect not to so join the Companies.

(ii)The monetary amount to be paid to or received from IMPA or IMEA pursuant to the provisions of paragraph (i) of this Article 13.2.2 shall be determined in accordance with the following equation:

P=W*X

Where:

P   =the monetary amount to be paid to or received from IMPA or IMEA. If P is positive, the monetary amount shall be paid to IMPA or IMEA; and if P is negative, the monetary amount shall be received from IMPA or IMEA.

W   =IMPA’s/or IMEA’s Percentage before transfer of IMPA’s/or IMEA’s Ownership Interest.

X   =the fair market value (as determined by an independent appraiser selected jointly by the Parties) of (i) Trimble County Unit 2 and (ii) the Trimble County Unit 2 Site and the Trimble County General Plant Facilities as they pertain to IMPA’s or IMEA’s use of Trimble County Unit 2, at the time IMPA or IMEA elects not to join the

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Companies in repairing and reconstructing Trimble County Unit 2 or the Trimble County General Plant Facilities.  Fair market value shall be determined after taking into account all applicable costs of dismantling, demolishing, and removal of equipment, facilities, and structures; security; maintenance; disposing of debris; and any site work necessary to remove the effects of such damage or destruction.  Fair market value may be a negative figure where appropriate.

ARTICLE 14.
PARTITION OF OR TRANSFERS OF INTEREST

14.1Special Nature of Trimble County Unit 2 Project - Waiver of Right of Partition.

The Parties recognize that Trimble County Unit 2 is an integral part of the facilities required to provide adequate service in their respective service territories and that the physical partition of the Trimble County Unit 2 Project or any material part thereof would be impossible and impractical and wholly inconsistent with the purposes for which this Agreement is made.

Each of the Parties agrees that it will not take any action at any time by judicial proceedings or otherwise, to partition the Trimble County Unit 2 Project or any part thereof, in any way, whether by partition in kind or by sale and division of the proceeds thereof.  Each of the Parties further waives the right of partition and the benefit of all statutory or common law that may now or hereafter authorize such partition of the Trimble County Unit 2 Project or any part thereof.  In the event any such right of partition shall hereafter accrue, each Party shall from time-to-time upon the written request of the other Party execute and deliver such further instruments as may be necessary to confirm the foregoing waiver and release of its right to partition. The foregoing provisions of this Article 14.1 shall be binding upon and inure to the benefit of the Parties, their respective successors and assigns, including mortgagees, receivers, trustees, or other representatives and their respective successors and assigns, and shall run with the land.  The Parties agree to insert a similar covenant in any contract with another party, which acquires all or any portion of a Percentage, which covenant will be enforceable by any Party.

14.2Transfer of Ownership Interests.

If any Party (“Transferring Party”) shall desire to transfer (whether by sale, conveyance, assignment, lease, or otherwise) all or any portion of its Ownership Interest (the “Offered Interest”), it may only do so in a bona fide arm’s length transaction, subject to Articles 14.2.1, 14.2.2, 14.2.3, 14.2.4, and 14.2.5.  Prior to making any such transfer, the Transferring Party shall give not less than forty-five (45) calendar days’ written notice to the other Parties, of the proposed transaction and the identity of the proposed purchaser(s).  Any such transaction or transactions shall not be consummated until each of the other Parties has determined not to exercise its right of first refusal as set forth in this Article 14.2.  Such notice shall fully disclose the terms of the proposed transaction or transactions.  Upon receipt of such notice, each other Party shall have a right of first refusal to acquire the Offered Interest, upon the same terms and conditions that the Transferring Party and the proposed purchaser(s) have agreed upon.  If each

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Party agrees to exercise its right of first refusal, each such Party shall acquire the Offered Interest in proportion to its respective Percentage prior to the proposed transfer.  If a Party elects not to exercise its right of first refusal, the remaining Parties shall acquire the Offered Interest in proportion to their then existing Percentages.  If only one Party elects to exercise its right of first refusal, it must acquire the entire Offered Interest by the Transferring Party.  Within forty-five (45) calendar days following receipt of the notice from the Transferring Party, each of the other Parties shall give written notice to the Transferring Party stating whether or not it elects to acquire the Offered Interest (the “Return Notice”).  A failure to give the Return Notice shall be deemed to be an election not to acquire such interest.  If a Party or Parties elects or elect to exercise its or their rights to acquire such interest, the Transferring Party and such Party or Parties as soon as practicable, shall execute such instruments as may be necessary and appropriate to effectuate such sale, conveyance, transfer, assignment, lease, or other disposition, as the case may be, to such Party or Parties, free and clear of all liens, security interests, charges, claims, and other encumbrances for which the Transferring Party, as between the Parties, is responsible, including the indenture(s) of the Transferring Party.

14.2.1Conditions of Transfer.

If none of the Parties elects to acquire the Offered Interest in the Trimble County Unit 2 Project as provided in Article 14.2, the Transferring Party may consummate its proposed transaction and dispose of the Offered Interest, provided, however, the other Parties have approved the proposed purchaser(s) as suitable as a joint owner(s) of Trimble County Unit 2, although such approval may not unreasonably be withheld, conditioned or delayed, and provided, further, where one or more of the Companies is a Transferring Party, the other Parties’ rights to approve the prospective purchaser as suitable shall be limited to situations in which the proposed transfer reduces the Companies’ aggregate Percentage to less than fifty percent (50%) or where such proposed transfer conveys, in whole or in part, the Companies’ rights and obligations for the operation of Trimble County Unit 2 and the Trimble County General Plant Facilities under this Agreement to the proposed purchaser(s).  Grounds for withholding such approval may include financial condition, experience in the operation and management of coal-fired generation, if applicable, and other factors as may materially adversely affect the other Parties’ interests hereunder.  The Transferring Party shall require (as a condition of or in connection with the sale, conveyance, transfer, assignment, lease, or other disposition, and for the benefit of the other Party) the proposed purchaser(s) to assume and agree to be bound by the provisions of this Agreement and any amendments thereto, and in furtherance thereof the provisions of this Agreement shall be amended appropriately.

Upon consummation of the transfer, the Transferring Party shall be released from its obligations under this Agreement, and from any claims, liabilities or debts, that arise in respect of the transferred interest on or after the date of such transfer.  The consummation of any such transfer shall not release the Transferring Party from any of its debts or liabilities to the other Parties which, at the time of the consummation of the transaction, have accrued under this Agreement, unless the Parties shall agree in writing to the contrary.  Any purported or attempted transfer of an interest in violation of this Article 14 shall be void and of no effect.

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14.2.2Further Conditions of Transfer.

The right of the Transferring Party to dispose of the Offered Interest to one or more non-Affiliates of the Transferring Party, as set forth in Article 14.2, is subject to the further condition that the other Parties shall be given written notice thereof and shall have the further right of first refusal, to the same extent and by the same procedure described in Article 14.2 if the Transferring Party:

(i)undertakes to consummate its proposed transaction at a time subsequent to two hundred forty (240) calendar days following the other Parties’ receipt of the written notice first referred to in Article 14.2;

(ii)undertakes to, without the consent of the other Parties, which consent will not be unreasonably withheld, dispose of such Offered Interest to Persons other than those whose identity was disclosed in said notice; or

(iii)undertakes to dispose of the Offered Interest upon substantially different terms and conditions than were disclosed in said notice.

14.2.3Non-applicability of Certain Provisions.

The provisions of the foregoing Articles 14.2, 14.2.1 and 14.2.2 shall continue for the duration of this Agreement and shall be applicable to each and every occasion and whenever a Party desires to dispose of (whether by sale, conveyance, transfer, assignment, lease, or otherwise) all or any portion of its Ownership Interest, provided, however, such provisions  (excluding the last paragraph of Article 14.2.1) shall not be applicable to, and each of the Parties hereby consents to, the following:

(i)the transfer, sale, or assignment to a financially responsible Affiliate or successor of a Party;

(ii)the transfer, assignment, pledge, hypothecation, mortgage, or grant (by indenture of mortgage, deed of trust, or otherwise) by any Party of its Ownership Interest, together with all or substantially all of its other electric utility property, for the purpose of securing bonds or other obligations for borrowed money issued or to be issued by it, including the effect of any after-acquired property clause of any such indenture of mortgage, deed of trust, or other instrument now existing or hereafter created by such Party, or the realization on or enforcement of such security or the exercise by the trustee or the mortgagee, or as the case may be, or the beneficiaries of such security of any of the rights, powers, or privileges provided for with respect thereto;

(iii)the transfer by a Party to one or more third parties of its Ownership Interest, together with all or substantially all of its other electric generating assets, whether by sale or pursuant to or as a result of a merger, consolidation, or corporate reorganization; or

(iv)the transfer by the Companies of any interest in Trimble County Unit 2, which transfer would not reduce the Companies’ aggregate Percentage to a level below seventy-five percent (75%).

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All transfers of interest described in clauses (i) through (iv) of this Article 14.2.3 shall be conditioned upon the transferee, by written agreement or by operation of law, assuming the obligations of this Agreement, and any amendments thereto, of the Transferring Party; except that transferees under (ii) and (iii) above shall not be subject to this condition prior to any exercise of ownership, control, or possession by transferee over the interest transferred.  In furtherance of such transfer, the Parties shall amend this Agreement appropriately.

14.2.4Transfer of Associated Rights and Interests.

No transfer (whether by sale, conveyance, assignment, lease, or otherwise) of any Ownership Interest shall be permitted, or shall become effective, unless the interest transferred includes a corresponding and equivalent transfer of associated rights and interests under this Agreement, including its rights and interests in Trimble County Unit 2, the Trimble County General Plant Facilities, and the Trimble County Unit 2 Site (and the licenses and easements associated therewith), and unless such transfer is made in full compliance with this Article 14.

14.2.5Louisville and Kentucky Utilities.

In the event that Louisville and Kentucky Utilities cease to be Affiliates of each other, the agency established hereunder shall devolve upon either Louisville or Kentucky Utilities as specified by both of them in a written notice to the other Parties.  This Agreement shall thereupon also be amended and restated by the Parties to appropriately reflect such change and the severing of such affiliated relationship.

ARTICLE 15.
ASSIGNMENT

15.1Limitation of Assignability.

This Agreement shall not be assignable by any Party without the written consent of the other Parties, except that no such consent under this Article 15.1 shall be required for the assignment of this Agreement (i) as an incident to the disposition of Ownership Interests in accordance with Articles 14.2, 14.2.1, 14.2.2 or 14.2.3 hereof or (ii) as an incident to the disposition of its Ownership Interest to the trustee for the revenue bonds issued by IMPA or IMEA to pay the costs of the acquisition of IMPA’s or IMEA’s Ownership Interest.

15.2Successors and Assigns.

This Agreement shall inure to the benefit of and be binding upon the Parties and their respective successors and upon the assigns of the Parties when such assignment is made in accordance with the provisions of Article 15.1.

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ARTICLE 16.
LIABILITY AND DEFAULT

16.1Liability to Third Parties.

Subject to any express provision to the contrary in this Agreement, any liability or any payment, cost, expense, or obligation arising from a claim of liability (after application thereto of any insurance coverage or proceeds) to one or more third parties against one or more of the Parties and arising from the planning, engineering, design, licensing, procurement, construction, installation, completion, operation, use, management, control, maintenance, replacement, alteration, modification, renewal, rebuilding or repair, retirement, disposal, or salvaging of the Trimble County Unit 2 Project or any part thereof; or from any other action or failure to act by any Party (or its employees, agents, or contractors) in carrying out any of the provisions of this Agreement in regard to the Trimble County Unit 2 Project or any part thereof, shall be several and not joint and shall be shared by the Parties in proportion to their respective Percentages in all circumstances except where such liability or claim of liability is the result of gross negligence or intentional wrongdoing on the part of less than all of the Parties.  If, by reason of any such liability or claim of liability (after application thereto of any insurance coverage or proceeds) to one or more third parties, any Party shall be called upon to make any payment or to incur any cost, expense, or obligation in excess of that for which it is responsible under the provisions of the preceding sentence, then the other Parties shall reimburse the Party making such excess payment or incurring any such excess cost, expense, or obligation to the full extent of the excess.

16.2Liability Among the Parties; No Consequential Damages.

Except as stated in Articles 6.5.5, 6.5.6, 7.7, 13.2.2, 19.4, 19.5, and 21.1.3 a Party (or its employees, agents or contractors) shall not be liable to the other Parties for any loss, cost, damage, or expense incurred by the Parties as a result of any action or failure to act, under any circumstances, by that Party (or its employees, agents, or contractors) in carrying out any of the provisions of this Agreement, unless such loss, cost, damage, or expense is the result of (i) gross negligence or intentional wrongdoing on the part of that Party, (ii) a Withdrawal Event occurs with respect to that Party after the Construction Closing or (iii) the performance of Companies’ obligations during the Development Phase or Construction Phase falling below the standard of conduct established in Article 20.24.  For purposes of this paragraph “contractors” shall not be interpreted to mean Persons under contracts entered into by all of the Parties or by the Companies when acting as the agent of the Parties.

Notwithstanding any other provision of this Agreement, the maximum aggregate liability of the Companies to IMEA or IMPA in connection with any loss, cost, damage or expense arising under clause (iii) above shall be limited to the aggregate amount of the supervisory fee paid to the Companies by such Party pursuant to Article 9.1.

Notwithstanding any other provision of this Agreement, in no event shall any Party be liable to another Party with respect to any claim, whether based on contract, tort (including negligence), patent, trademark or service mark, or otherwise, for any indirect, special, incidental, or consequential damages.

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In no event shall any Party be excused from liability for its fraudulent acts.

16.3Indemnification.

Subject to Article 16.2 hereof, each Party (“breaching Party”) hereby agrees to indemnify and hold the other Parties (“non-breaching Parties”) harmless from, against, and in respect of and shall on demand reimburse the non-breaching Parties for:

(i)any and all loss, liability, or damage resulting from any untrue representation, breach of warranty, or non-fulfillment of any covenant or agreement by the breaching Party contained herein or in any certificate, document, or instrument delivered to the non-breaching Parties hereunder; and

(ii)any and all loss suffered by the non-breaching Parties due to the breaching Party’s failure to perform or satisfy any obligation assumed pursuant to this Agreement; or

(iii)any and all loss resulting from actions, suits, proceedings, claims, demands, assessments, judgments, costs, and expenses, including legal fees and expenses, incident to any of the foregoing or incurred in investigating or attempting to avoid the same or to oppose the imposition thereof, or in successfully enforcing this indemnity.  The provisions of this paragraph (iii) shall not apply unless it shall be finally adjudicated by a court having jurisdiction of the subject matter and the Parties that a Party has committed a breach identified in paragraph (i) or (ii) of this Article 16.3.

16.4Nature and Survival of Representations and Warranties.

Each representation, warranty, indemnity, covenant, and agreement made by the Parties in this Agreement or in any document, certificate, or other instrument delivered by or on behalf of the Parties pursuant to this Agreement or in connection herewith, shall survive the Development Closing and the Construction Closing, respectively.

16.5Default.

16.5.1Events of Default.

The following shall be an Event of Default under this Agreement:

(i)Failure to Make Payment.  Subject to Article 18.4, failure by any Party to make any payment to the other Parties required under this Agreement within sixty (60) calendar days after the date on which such payment becomes due, or failure by any Party to give any credit to the other Parties required under this Agreement for a period of sixty (60) calendar days after the date on which such credit becomes due, or failure by any Party to make payment for a period of sixty (60) calendar days after the date on which such payment becomes due, when failure to do so is likely to result in a lien on any of the property subject to this Agreement or otherwise adversely affects the interests of the other Parties, provided, however, that no Party shall be in default if the amount it owes hereunder can be, and is, offset in whole within sixty (60) calendar days after the date on which such amount became due and payable, by the Party to whom that sum is owed under this Agreement.

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(ii)Failure to Perform.  Failure by a Party to perform any material obligation, duty, or responsibility in accordance with the provisions of this Agreement.

16.5.2Curing Event of Default in Regard to Paying Money.

As to any Event of Default resulting from the failure to pay money, the defaulting Party may remedy its Event of Default (when such default is the failure to pay money) by paying to the non-defaulting Parties on or before ninety (90) calendar days from the date the payment becomes due:

(i)the sums due;

(ii)interest on the sums due at the Agreed Rate from the date due until paid; and

(iii)any other costs reasonably incurred by the non-defaulting Parties as a result of such Event of Default.

16.5.3Curing Event of Default for Other Than Failure to Pay Money.

An Event of Default other than the failure to pay money may be cured by the Party in default by performing such act as is necessary to cure the Event of Default and by paying the non-defaulting Parties on or before ninety (90) calendar days from the date such Event of Default occurred, any sums due under Article 16.3.

16.5.4Non-Applicability of Cure Provisions.

The cure periods set forth in Articles 16.5.2 and 16.5.3 are intended to allow a Party to have the opportunity to cure a specific Event of Default and, unless otherwise provided, do not otherwise extend the time required for the performance of any other obligation of a Party under this Agreement.

16.5.5Appointment of a Receiver.

If an Event of Default occurring after the Commercial Operation Date continues for a period of one hundred eighty (180) calendar days, then the non-defaulting Parties may have a receiver appointed by a state or federal court sitting in Louisville, Kentucky, to take control of and operate the defaulting Party’s interest in the Trimble County Unit 2 Project and perform in accordance with the terms of this Agreement.

16.5.6Additional Obligations.

With respect to any Party as to which an Event of Default has occurred, such Party shall use its Best Efforts to take any and all such further actions and shall execute and file where appropriate any and all such further legal documents and papers as may be reasonable under the circumstances in order to facilitate the carrying out of this Agreement or otherwise effectuate its purpose, including action to seek any required governmental or regulatory approval and to obtain any other required consent, release, amendment, or other similar document.

16.5.7Notice.

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To entitle a Party hereto to exercise any remedy conferred upon or reserved by it in this Article 16, notice shall be provided in accordance with Article 20.2 hereof.

16.6Force Majeure.

In no event shall any Party be liable to the other Parties for failure by such Party to perform any of its obligations under this Agreement because of Force Majeure.  Nothing contained herein shall be construed to require a Party to settle any strike, lockout, work stoppage, or other industrial disturbance or dispute in which it may be involved or to take an appeal from any action of a Governmental Authority.  Any Party rendered unable to fulfill any of its obligations under this Agreement by reason of Force Majeure shall exercise Best Efforts to remove such inability with all reasonable dispatch.  In the event any Party is unable, in whole or in part, to perform any of its obligations by reason of Force Majeure, other than obligations to make payments hereunder, the obligations of the Party relying thereon, insofar as such obligations are affected by such Force Majeure, shall be suspended during the continuance thereof but no longer.  The Party invoking Force Majeure shall notify the other Parties of the full particulars of the Force Majeure and the time and date when the Force Majeure occurred.  Notices given by telephone under this Article 16.6 shall be confirmed promptly by electronic mail or facsimile transmission.  When the Force Majeure ceases, the Party relying thereon shall give immediate notice thereof to the other Parties by electronic mail or facsimile transmission.  This Agreement shall not be terminated by reason of Force Majeure but shall remain in full force and effect.  Force Majeure does not include financial inability to pay, and shall not, in any event, excuse payment for obligations already incurred hereunder at the time a claim is made.

ARTICLE 17.
MANAGEMENT

17.1Coordination Committee.

From time to time various administrative, financial, and technical matters may arise in connection with the terms and conditions of this Agreement which will require the cooperation and consultation of the Parties and the exchange of information.  As a means of providing for such consultation, interchange, decision making, or ratification, a Coordination Committee is hereby established with functions as described in Article 17.3 below.  However, such committee shall not diminish in any manner the authority of the Companies as set forth in this Agreement

17.2Coordination Committee Formation.

Within thirty (30) calendar days after the Execution Date, each Party shall designate a representative and an alternate that are to serve on the Coordination Committee and shall give written notice to the other Parties of such designations.  In the event that any Ownership Interest of a Party, in whole or in part, shall be assigned or otherwise transferred to a replacement or an additional Party in accordance with the provisions of this Agreement, such replacement or additional Party shall designate a representative and an alternate to serve on the Coordination Committee.  Any change in the representative or alternate of a Party on the Coordination Committee shall be made by written notice to the other Parties.  Each Party shall be responsible for the personal expenses of its representatives.

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17.3Powers of Coordination Committee.

The Coordination Committee shall be responsible for and shall take actions, which it determines are necessary or advisable during the term of this Agreement.   The Coordination Committee shall address activities necessary or advisable to plan, license, acquire licenses, permits and approvals for, construct, acquire, complete, maintain, operate, assure the security of, and decommission the Trimble County Unit 2 Project, including:

(i)the making of such agreements and modifications of existing agreements and the taking of such other action as the Coordination Committee deems necessary or that may be required under the regulations or directives of any Governmental Authority having jurisdiction thereof, with respect to the development, construction, acquisition and completion of the Trimble County Unit 2 Project for commercial service; the procurement, replacement, modification, or renewal of all or any part thereof; the making of additions, betterments, or improvements thereto; the operation and maintenance thereof; and the retirement, decommissioning, storage, or salvaging of all or any part thereof;

(ii)the execution and filing with Governmental Authorities having jurisdiction of applications, amendments, reports, and other documents and filings required in connection with the licensing and other regulatory matters, including applications for extension or renewal of the terms of any licenses and permits required by any Governmental Authority;

(iii)the adjustment of losses and settlement of any losses covered by insurance on the Trimble County Unit 2 Project;

(iv)the pursuit and defense of claims and causes of action of any kind relating to the Trimble County Unit 2 Project, including the filing or defense of suits, appeals thereof, and settlement of claims and suits subject to the right of any Party to conduct its own action in any litigation in which it is a party or in which it is entitled to intervene pursuant to this Agreement;

(v)the establishment of such subcommittees as it believes appropriate and provide for membership, meetings, voting procedures and such other rules of procedure as it deems appropriate consistent with the provisions of this Article 17.

(vi)the determination from time to time of the Net Electric Generating Capacity and the Net Seasonal Capacity of Trimble County Unit 2;

(vii)the approval of budgets for development, construction, operation and maintenance, and Incremental Capital Assets, as described in Article 17.4;

(viii)acting upon any matter brought before the Coordination Committee by a Party;

(ix)performing such other duties as set forth in this Agreement; and

(x)prior to and as a condition of the Construction Closing, undertaking due consideration of and issuance of the Authorization to Construct.

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17.4Budget Approval.

17.4.1Development Budget.

Prior to the Development Closing, the Companies shall provide a budget of the total Development Costs, together with interest thereon in accordance with Article 3.2 and the supervisory fees thereon applicable to IMPA and IMEA in accordance with Article 9.1 (the “Development Budget”), which shall include all applicable charges incurred prior to Development Closing and to be paid in accordance with Article 9.1, and the Companies’ best estimates of all applicable charges from Development Closing to the Construction Closing, including a reasonable contingency.  The proposed Development Budget will include such level of detail as may be reasonably required by the Parties for their budgets, books and records, as well as estimated expenditures at certain milestones throughout the development of the Trimble County Unit 2 Project.  The Parties will share all Development Costs in proportion to their respective Percentages.

The Parties must approve, by unanimous vote, the Development Budget submitted by the Companies, with such changes as the Parties deem necessary or appropriate and such approved Development Budget will be attached hereto as Appendix H.  After the initial Development Budget is approved, the Companies are authorized to expend the amounts contained therein.

The Companies may submit a revised Development Budget to the Coordination Committee for approval or disapproval.

After the Development Closing and during the Development Phase, the Companies shall provide status reports on the Development Schedule, Development Work, Development Costs (and the supervisory fees thereon), Development Budget, Construction Schedule, and Construction Budget on a monthly basis and at such other times as the Companies believe elements thereof will change significantly.  Such reports shall disclose material developments affecting the Development Work (and the schedule impact thereof), the Development Costs, the Development Budget, the Construction Schedule or the Construction Budget.

17.4.2Construction Budget.

Not less than ninety (90) calendar days prior to the Construction Closing, the Companies will submit a proposed budget for Construction Costs (including the supervisory fees thereon in accordance with Article 9.1) (the “Construction Budget”) to the Coordination Committee.  The proposed Construction Budget will include all Construction Costs (including the supervisory fees thereon in accordance with Article 9.1) and a reasonable contingency established by the Companies.  The proposed Construction Budget will include such level of detail as may be reasonably required by the Parties for their budgets, books and records, as well as estimated expenditures at certain milestones throughout the construction of the Trimble County Unit 2 Project.  The proposed Construction Budget shall include an estimated cash flow of payments expected to be made by the Parties during the Construction Phase in accordance with Article 9.1.  The Coordination Committee shall approve the Construction Budget submitted by the Companies, with such changes as the Coordination Committee deems necessary or appropriate.  After the Construction Closing has occurred, the Companies will be authorized to expend the amounts authorized in the Construction Budget in effect as of the date of the Construction

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Closing (the “Initial Construction Budget”) contained therein.  IMPA and IMEA shall pay the Companies directly for their respective proportionate share of all approved Construction Costs (and the supervisory fees thereon in accordance with Article 9.1) on a monthly basis, in accordance with Articles 9 and 10.

After the Construction Closing has occurred, the Companies shall provide status reports thereon not less than monthly and such other times as they believe the costs of the Initial Capital Assets of the Trimble County Unit 2 Project will change significantly.  The Companies shall have the authority to approve change orders to the Construction Contracts whether initiated by the Companies or by a Construction Contractor, provided that Companies shall not direct discretionary changes that would be in excess of the then existing Construction Budget (including budgeted contingency) without the unanimous consent of the Coordination Committee.  If any individual change to the Initial Construction Budget (after utilizing all budgeted contingency) exceeds one percent (1%) of the Initial Construction Budget or any combination of change orders and changes to the Construction Budget results in a cumulative increase in the initial Construction Budget (after utilizing all budgeted contingency) by more than five percent (5%) of the Initial Construction Budget a (“Major Change”), the Companies will consult with the Coordination Committee and seek an amendment to the Construction Budget.  Any change orders to the engineering, equipment or other Construction Contracts that change the guaranteed performance, including the Net Electric Generating Capacity, major equipment, or the guaranteed completion dates of the Trimble County Unit 2 Project shall not be authorized by the Companies without prior consultation with and approval of the Coordination Committee.

The Companies will be authorized to expend the amounts in the Construction Budget as revised from time-to-time in accordance with this Article 17.4.2.  At any time, regardless of actual construction expenditures, the Companies may submit a revised Construction Budget for the Trimble County Unit 2 Project to the Coordination Committee for approval or disapproval.

After the Construction Closing and during the Construction Phase, the Companies shall provide status reports on the Construction Schedule, Construction Work, Construction Costs (together with the supervisory fees thereon in accordance with Article 9.1), and Construction Budget on a monthly basis.  Such reports shall disclose material developments affecting the Construction Schedule, the Construction Work, the Construction Costs or the Construction Budget.

17.4.3Annual Capital Budget.

For Incremental Capital Assets after completion of the original construction of the Trimble County Unit 2 Project, the Companies shall prepare and submit to the Coordination Committee an annual Trimble County Unit 2 Project capital budget (the “Annual Capital Budget”) no later than August 1 of each year for the subsequent year.  The Coordination Committee must approve the Annual Capital Budget submitted by the Companies with such changes as the Coordination Committee deems necessary or appropriate, after which the Companies will be authorized to expend the amounts contained therein.  After approval of the Annual Capital Budget, no further review by the Coordination Committee is required unless the actual, total capital expenditures are anticipated to exceed the approved Annual Capital Budget by fifteen percent (15%) or more.  In this event, the Companies will submit a revised Annual

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Capital Budget to the Coordination Committee for its approval or disapproval on a quarterly basis.  The Companies are not authorized to expend construction funds in excess of one hundred fifteen percent (115%) of the total amount approved by the Coordination Committee in the Annual Capital Budget (as revised) except in the event of an Emergency.  In the event an Emergency requires expenditure of funds in excess of the approved Annual Capital Budget, the Companies shall advise the Coordination Committee immediately and request timely approval or disapproval.  Such approval or disapproval may be obtained via a telephone or electronic meeting to be confirmed later in writing.  In the absence of timely approval, the Companies shall take whatever actions they deem necessary to support the continued safe and efficient operation of Trimble County Unit 2.

17.4.4Operation and Maintenance Budget.

For operation and maintenance (“O&M”) expenses, the Companies shall prepare and submit to the Coordination Committee an annual Trimble County Unit 2 Project O&M budget (the “Annual O&M Budget”) no later than August 1 of each year.  Such Annual O&M Budget shall include goals as to unit efficiency and availability for the ensuing year.  The Coordination Committee must approve the Annual O&M Budget submitted by the Companies with such changes as the Coordination Committee deems necessary or appropriate.  After the Annual O&M Budget is approved, the Companies will be authorized to expend the amounts contained therein.  Further, after approval of the Annual O&M Budget, no further review by the Coordination Committee is required unless the actual, total O&M expenditures are anticipated to exceed the budgeted amounts by fifteen percent (15%) or more.  In this event, the Companies will submit on a quarterly basis a revised Annual O&M Budget to the Coordination Committee for its approval or disapproval.  The Companies are not authorized to expend O&M funds in excess of one hundred fifteen percent (115%) of the total amount approved by the Coordination Committee in the Annual O&M Budget (as revised) except in the event of an Emergency.  In the event an Emergency requires the expenditure of funds in excess of the approved Annual O&M Budget, the Companies shall advise the Coordination Committee promptly and request timely approval or disapproval.  Such approval may be obtained via a telephone or electronic meeting to be confirmed later in writing.  In the absence of timely approval the Companies shall take whatever actions they deem necessary to support the continued safe and efficient operation of Trimble County Unit 2.

17.5Vote by Coordination Committee.

Except as provided otherwise in this Agreement or by agreement of all Parties, all actions taken by the Coordination Committee shall be by majority vote, with each Party entitled to vote in shares equal to its Percentage.

17.6Meetings.

The Chairman of the Coordination Committee shall rotate annually among the Parties on each anniversary of the Execution Date.  The Chairman shall be responsible for calling meetings, except as hereinbelow provided, and establishing the agenda.  Each Party, however, shall have the right to have items included on the agenda.  The Coordination Committee may also act without a meeting by telephone or electronic conference or voting by correspondence or electronic mail.  The Coordination Committee shall meet regularly, but not less often than once

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in each calendar quarter during development and construction of the Trimble County Unit 2 Project and not less than annually after the Commercial Operation Date, and at such other times as requested by any Coordination Committee member upon thirty (30) calendar days’ prior written notice.  Meetings may be attended by other representatives of the Parties in addition to the members of the Coordination Committee.

17.7Records.

The Coordination Committee shall keep written records of all meetings.

17.8Amendments.

The Coordination Committee shall have no authority to modify or amend the terms of this Agreement.

17.9Information.

The Companies shall use their Best Efforts to keep all members of the Coordination Committee informed of all significant matters with respect to the development, construction, operation and maintenance of the Trimble County Unit 2 Project including, plans, specifications, engineering studies, environmental reports, budgets, estimates and schedules.   Upon the request of any Coordination Committee member, the Companies shall furnish or make available any and all other information relating to the development, construction and operation and maintenance of the Trimble County Unit 2 Project.

ARTICLE 18.
DISAGREEMENT

18.1Consultation.

In accordance with the provisions of Article 18, the members of the Coordination Committee will consult in connection with any major matter arising under this Agreement.

18.2Disagreement.

If any disagreement arises on major development, construction or operation and maintenance matters pertaining to the Trimble County Unit 2 Project, major capital matters pertaining to the Trimble Unit 2 Project, or major retirement matters, or other matters arising under this Agreement, pertaining to the Trimble County Unit 2 Project (“Plant Subjects”), such matters shall be discussed by the Coordination Committee and timely mutual agreement sought in regard thereto.  If each of the members of the Coordination Committee agrees to the resolution of any Plant Subject, such agreement shall be reported in writing to and shall be binding upon the Parties within the authority of the Coordination Committee as provided in Article 17.  In the unlikely event that each of the members of the Coordination Committee is unable to reach agreement within a reasonable time (giving due cognizance to the operating and maintenance schedules of Trimble County Unit 2 and all other pertinent circumstances) with respect to any Plant Subject under consideration, a Vice President of Louisville, a Vice President of Kentucky

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Utilities, the President of IMPA or the General Manager and CEO of IMEA can, by written notice to the other members of the Coordination Committee, withdraw the matter from consideration by the Coordination Committee and submit the same for resolution to a Vice President of Louisville, a Vice President of Kentucky Utilities, the President of IMPA and the General Manager and CEO of IMEA. If these senior representatives of the Parties agree to a resolution of the matter, such agreement shall be reported in writing to and shall be binding upon the Parties; but if said senior representatives fail to resolve the matter within seven (7) calendar days after its submission to them, then the matter may proceed to resolution as provided in Article 18.3.

18.3Arbitration.

If a disagreement should arise with respect to any Plant Subject which is not resolved by the Coordination Committee or the senior representatives of the Parties as provided in Article 18.2 or any other disagreement concerning this Agreement, then such disagreement may be settled by arbitration by a single arbitrator as hereinafter provided, in accordance with the provisions of this Article 18.3. If, after the procedure for resolving such disagreement by the Coordination Committee or the senior representatives of the Parties as provided in Article 18.2 has been exhausted, a Party desires that such disagreement shall be settled by arbitration, it shall serve written notice upon the other Parties setting forth in detail such disagreement with respect to which arbitration is desired.  Such disagreement shall be settled by arbitration if, after receipt of such written notice, all of the Parties shall agree in writing that such disagreement shall be settled by arbitration.  Within a period of thirty (30) calendar days from the date of such agreement in writing to settle such disagreement by arbitration, the Parties shall mutually agree upon an arbitrator.  If the arbitrator is not so selected within the specified thirty (30)-calendar day period, either Party may, upon written notice to the other Parties, apply to the American Arbitration Association for the appointment of the arbitrator or arbitrators who have not been so selected and such association shall thereupon be empowered to select such arbitrator.

The arbitration proceedings shall be conducted in Louisville, Kentucky, unless otherwise mutually agreed.  The Arbitrator shall afford adequate opportunity to both of the Parties to present information with respect to the disagreement submitted to arbitration and may request further information from any Party.  Except as provided in the preceding sentence, the Parties may, by mutual agreement, specify the rules that are to govern any proceeding before the arbitrator and limit the matters to be considered by the arbitrator, in which event the arbitrator shall be governed by the terms and conditions of such agreement.  In the absence of any such agreement respecting the rules that are to govern any proceeding, the then current rules of the American Arbitration Association for the conduct of commercial arbitration shall govern the proceedings, except that if such rules shall conflict with the then current provisions of the laws of Kentucky relating to arbitration, such conflict shall be governed by the then current provisions of the laws of Kentucky relating to arbitration.

Procedural matters pertaining to the conduct of the arbitration and the award shall be made by the arbitrator.  The Parties shall, however, be entitled to all discovery provided for by the Kentucky Rules of Civil Procedure.  The findings and award of the arbitrator shall be final and conclusive with respect to the disagreement submitted for arbitration and shall be binding upon the Parties, except as otherwise provided by Applicable Law.  Each Party shall equally

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share the fee and expenses of the arbitrator and shall also be responsible forthe costs and expenses incurred by it in the preparation of its case to the arbitrators.  Judgment upon the award may be entered in any court having jurisdiction.  In the event all of the Parties do not agree to arbitrate, each shall have the right to take appropriate judicial action.

18.4Obligations To Make Payments.

If a disagreement should arise out of the Development Work, the Construction Work, the Operating Work, the construction or acquisition of any Incremental Capital Asset or from any Plant Subject which is not resolved by the Coordination Committee or the senior representatives of the Parties as provided in Article 18.2, then, pending the resolution of the disagreement by arbitration (if applicable) and/or litigation, the Companies shall continue to pursue the Development Work, the Construction Work, operate Trimble County Unit 2, or construct or procure necessary Incremental Capital Assets, as the case may be, in a manner consistent with this Agreement, and the Parties shall continue to make all payments required in accordance with the applicable provisions of this Agreement.  Notwithstanding the foregoing, a Party may, in good faith, withhold payment of amounts that it disputes are properly due and payable under this Agreement (a “Withholding Party”), provided, however, any such right to withhold payment is subject to the following conditions:  (i) the aggregate amount withheld will not, in the aggregate at any time, exceed $1,000,000, (ii) prior to the date on which the payment(s) to be withheld would otherwise be due, the Withholding Party shall (a) give a detailed written notice to the Party or Parties otherwise entitled to payment of the amount to be withheld and the basis on which the Withholding Party asserts that the amount withheld is not due and owing, (b) deposit the full amount of the withheld payment(s) in an interest-bearing escrow account (the “Escrow Account”) and (c) commence the dispute resolution process set forth in Article 18.2 by requesting a meeting of the Coordination Committee to resolve the dispute.  The Escrow Account shall be established by all Parties to the dispute (the “Disputing Parties”) in a reputable financial institution conducting fiduciary business in the United States, as agreed upon by the Parties.  The agreement establishing the Escrow Account shall provide that the escrowed sums are not to be released except upon the signature of all Disputing Parties, and shall contain such other provisions as the Disputing Parties and the escrow agent shall agree upon.  At such time that the dispute is decided in accordance with Article 18 or otherwise resolved, the Disputing Parties shall direct the escrow agent to release the escrowed sums, including interest earned thereon, in accordance with the decision or other resolution.  If the amount received by the receiving Party is less than the amount required in accordance with Article 18.5, the Withholding Party shall reimburse the difference to the Party or Parties entitled to payment.  The cost of establishing and maintaining the Escrow Account shall be initially borne by the Withholding Party, but shall be ultimately borne by the Disputing Parties in inverse proportion to their entitlement to the escrowed proceeds and interest thereon.  By way of example, if a Disputing Party is ultimately entitled to all of the proceeds of the Escrow Account, the other Disputing Parties shall bear the cost of establishing and maintaining the Escrow Account.

18.5Interest.

In the event that a Party withholds payment pursuant to Article 18.4 or otherwise fails to make a payment when due and it is determined in accordance with Article 18 or otherwise agreed that all or any portion of such funds should have been paid when invoiced or otherwise

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due, the Party that withheld such payment or otherwise failed to make full payment shall pay to the appropriate Parties the full amount overdue, together with interest thereon at the Agreed Rate from the date such sums were originally due to the date paid.  In the event that it is determined in accordance with Article 18 or otherwise agreed that a Party has received an overpayment under this Agreement, the Party that received such overpayment shall reimburse the overpaying Party the amount of such overpayment together with interest thereon at the Agreed Rate from the date such sum was overpaid to the date of such reimbursement.

ARTICLE 19.
REMEDIES

19.1All Remedies - Setoff.

In the event any Party (the “Defaulting Party”) fails to pay when due any amount owing by it to the other Parties (the “Non-Defaulting Parties”) under this Agreement or fails to perform or observe any covenant, condition, or agreement to be performed or observed under this Agreement or the Interconnection and Operating Agreement, each Non-Defaulting Party shall have available to it all remedies, legal and equitable, including those available in order to enforce payment of any such amount or performance or observance of any such covenant, condition, or agreement, subject to the defaulting Party’s rights to cure default under Article 16.5.  All overdue payments shall bear interest at the Agreed Rate.  Further, the Non-Defaulting Parties shall have the right to setoff against any amount owed to them by the Defaulting Party the amount of any payment which such Party has failed to pay when due under this Agreement or the Interconnection and Operating Agreement.  In addition, the Non-Defaulting Parties shall have the other rights and remedies available to them under this Article 19.

19.2Injunctive Relief and Specific Performance.

The Parties hereto agree and acknowledge that the failure to perform any of their respective obligations (except with respect to Article 6.5.4 hereof) under this Agreement, including the execution of documents which may be reasonably requested pursuant to this Agreement, would cause irreparable injury to the other Parties and that the remedy at law for any violation or threatened violation thereof would be inadequate, and further agree that the other Parties shall be entitled to a temporary or permanent injunction, specific performance or other equitable relief specifically to enforce such obligation without the necessity of proving the inadequacy of its legal remedies.

19.3No Remedy Exclusive.

Except as otherwise provided in this Agreement, no remedy conferred upon or reserved to the Parties hereto in this Agreement is intended to be exclusive of any other remedy or remedies available hereunder or now or hereafter existing at law, in equity, or by statute or otherwise, but each and every such remedy shall be cumulative and shall be in addition to every other such remedy.  The pursuit by any Party of any specific remedy shall not be deemed to be an election of that remedy to the exclusion of any other or others, whether provided hereunder or by law, equity, or statute.

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19.4Failure to Participate in Incremental Capital Assets.

If IMPA or IMEA fails to make any payment of its share of the cost of Incremental Capital Assets, the Companies shall have the right, at their election, to give written notice of such failure to the Party that has failed to make such payment.  In addition to the right to receive interest on such overdue payment, if such payment (with interest due thereon at the Agreed Rate) remains unpaid ninety (90) calendar days after the giving of the written notice first referred to in this paragraph, then (i) the non-paying Party’s rights to make any further payments of its share of the cost of the Incremental Capital Asset shall thereupon terminate, and (ii) the respective Ownership Interest shall be adjusted in accordance with the following formula:

ADD = ALGE*IPCT/(INP+ALGE)

where:

ADD	=	Additional Ownership Interest accruing to the Party or Parties as a result of making the additional investment to complete construction of Incremental Capital Assets (there shall be a corresponding reduction in the Ownership Interest of the non-paying Party.
INP	=	Investment made by the non-paying Party or Parties for its or their respective Ownership Interest to the time of the written notice first referred to in this Article 19.4.
ALGE	=	Additional investment made by the paying Party or Parties to complete construction of Incremental Capital Assets as aforesaid.
IPCT	=	The non-paying Party’s Percentage at the time of the written notice first referred to in this Article 19.4.

If either IMPA or IMEA fails to make a payment of its share of the cost of an Incremental Capital Asset, but not both, then the Companies will notify the other paying Party and such other paying Party shall fund its proportionate share (based on its relative Percentage) of the additional investment of the non-paying Party.  The Companies will then calculate the portion of the ADD to which they and the other Paying Party are entitled based on their respective additional investments.

19.5Failure to Participate in Construction Costs.

In the event that a Party votes in the Coordination Committee against an amendment to the Construction Budget that constitutes a Major Change, such Party shall give written notice to the other Parties, within five (5) calendar days of such vote, specifying whether it will or will not make payment of its share of the additional Construction Costs (and the supervisory fee thereon in accordance with Article 9.1) arising from such amendment to the Construction Budget.  If such Party gives notice that it will not make such payment or if such Party fails to make such payment, its rights to make such payment shall thereupon terminate and the Ownership Interests in the Trimble County Unit 2 Project shall be adjusted in accordance with the following formula:

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ADD = IINV/(NC*$1100/kW)

where:

ADD	=	Additional percentage of the Trimble County Unit 2 to be transferred from the nonfunding Party to the funding Parties in proportion to their respective Percentages.
IINV	=	Incremental investment made by the funding Party resulting from the nonfunding Party’s failure to pay.
NC	=	Nominal capacity of the unit at 59? F in kilowatts.

ARTICLE 20.
MISCELLANEOUS

20.1Governing Law.

The validity, interpretation, and performance of this Agreement and each of its provisions shall be governed by the laws of the Commonwealth of Kentucky, except that the power and authority of IMPA to enter into this Agreement shall be governed by the laws of the State of Indiana and the power and authority of IMEA to enter into this Agreement shall be governed by the laws of the State of Illinois.

20.2Notice to Parties.

Unless otherwise specifically provided in this Agreement, any notice, consent, or other communication required to be made under this Agreement shall be addressed to or made by such officer, agent, representative, or employee of a Party as such Party may, from time-to-time, designate in writing, provided, however, any written notices hereunder shall be delivered in person, by certified mail, or by recognized next working day carrier, to the named officer of the Party at the address listed below, provided, further that any Party may, from time-to-time, change such designated officer or the address thereof by giving written notice of such change to the other Parties.  Notice shall be deemed given when received.  Any requirement for notice in writing may be met by telecopy or other electronic means of communicating written or printed material, if promptly confirmed in writing in a manner permitted by the previous sentence.

To Louisville:

Vice President of Generation

LOUISVILLE GAS AND ELECTRIC COMPANY

220 West Main Street

Post Office Box 32010 (40232)

Louisville, Kentucky 40202

To Kentucky Utilities:

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Vice President of Generation

KENTUCKY UTILITIES COMPANY

220 West Main Street

Post Office Box 32010 (40232)

Louisville, Kentucky 40202

To IMPA:

President

INDIANA MUNICIPAL POWER AGENCY

11610 North College Avenue

Carmel, Indiana 46032

To IMEA:

General Manager & CEO

ILLINOIS MUNICIPAL ELECTRIC AGENCY

919 South Spring Street

Springfield Illinois 62704

20.3Article Headings Not to Affect Meaning.

The descriptive headings of the various articles of this Agreement have been inserted for convenience of reference only and shall in no way modify or restrict any of the terms or provisions hereof.

20.4Counterparts.

This Agreement (and any amendments hereto) may be executed simultaneously in four or more counterparts, each of which shall be deemed an original, but all of which together shall constitute one and the same instrument.

20.5Emergency.

Notwithstanding any other provision of this Agreement to the contrary, in the event of an Emergency, the Companies shall be entitled to take such action without consultation with the Coordination Committee as to best protect and promote the development, construction, completion operation, safety or security of the Trimble County Unit 2 Project.

20.6Severability.

In the event that any provision of this Agreement, or the application of any such provision to any Person or circumstance, shall be held invalid or unenforceable, the remainder of this Agreement, or the application of such provision to Persons or circumstances other than those as to which it is held invalid or unenforceable, shall not be affected thereby.

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20.7Integration.

The terms and provisions contained in this Agreement and the Interconnection and Operating Agreement constitute the entire agreement between the Parties in regard to the respective matters of said Agreement, and shall supersede all previous communications, representations, or agreements, either oral or written, between the Parties with respect to the respective subject matters of said agreements.

20.8Computation of Time.

In computing any period of time prescribed or allowed by this Agreement, the calendar day of the act, event, or default from which the designated period of time begins to run shall not be counted.  The last calendar day of the period so computed shall be counted, unless it is a Saturday, Sunday, or legal holiday recognized by the Companies, in which event the period shall run until the end of the next calendar day which is neither a Saturday, Sunday, nor legal holiday.

20.9Waiver.

Any waiver at any time, by any Party, of its rights with respect to another Party, or with respect to any other matter arising in connection with this Agreement, shall not be considered a waiver with respect to any subsequent default or matter.

20.10Equal Opportunity Clause.

During the performance of those parts of this Agreement relating to the construction by a Party of any Initial or Incremental Capital Assets, such Party agrees as follows:

(i)Such Party will not discriminate against any employee or applicant for employment because of any protected class status, such as race, color, religion, sex, age or national origin.  Such Party will take affirmative action to insure that applicants are employed, and that employees are treated, during employment, without regard to their protected class status.  Such action shall include, but not be limited to, the following:  employment, upgrading, demotion, or transfer; recruitment or recruitment advertising; layoff or termination; rates of pay or other forms of compensation; and selection for training, including apprenticeship.  Such Party agrees to post, in conspicuous places, available to employees and applicants for employment, notices setting forth the provisions of this non-discrimination clause;

(ii)Such Party will, in all solicitations or advertisements for employees place by or on behalf of such Party, state that all qualified applicants will receive consideration for employment without regard to race, color, religion, sex, age or national origin;

(iii)Such Party will send to each labor union or representative of workers with which it has a collective bargaining agreement or other contract or understanding, a notice, to be provided, advising the said labor union or workers’ representative of such Party’s commitments under this Article 20.10, and shall post copies of the notice in conspicuous places, available to employees and applicants for employment;

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(iv)Such Party will comply with all provisions of Executive Order No. 11246 of September 24, 1965, and of the rules, regulations, and relevant orders of the Secretary of Labor;

(v)Such Party will furnish all information and reports required by Executive Order No. 11246 of September 24, 1965, and by the rules, regulations, and orders of the Secretary of Labor, or pursuant thereto, and will permit access to its books, records, and accounts by the administering agency and the Secretary of Labor, for purposes of investigation, to ascertain compliance with such rules, regulations, and orders;

(vi)In the event of such Party’s non-compliance with the non-discrimination clauses of this Agreement, or with any of the said rules, regulations, or orders, this Agreement may be canceled, terminated, or suspended, in whole or in part, and such Party may be declared ineligible for further Government contracts or federally assisted construction contracts in accordance with procedures authorized in Executive Order No. 11246 of September 24, 1965, and such other sanctions may be imposed and remedies invoked as provided in said Executive Order or by rule, regulation, or order of the Secretary of Labor, or as otherwise provided by law;

(vii)Such Party will includes the words “During the performance of this contract, the contractor agrees as follows:” followed by the provisions of sections (i) through (vi) of this Article 20.10 in every subcontract or purchase order, unless exempted by rules, regulations, or orders or the Secretary of Labor issued pursuant to Section 204 of Executive Order No. 11246 of September 24, 1965, so that such provisions will be binding upon each subcontractor or vendor.  Such Party will take such action with respect to any subcontract or purchase order as the administering agency may direct as a means of enforcing such provisions, including sanctions for non-compliance; provided, however, that in the event such Party becomes involved in, or is threatened with, litigation by a subcontractor or vendor as a result of such direction by the administering agency, such Party may request the United States to enter into such litigation to protect the interests of the United States;

(viii)For purposes of this Agreement, the term “this Agreement,” as used in this Article 20.10 shall mean those parts of this Agreement relating to the construction by such Party of any additions, betterments, or improvements to the property.  Nothing in this Article 20 shall be construed to prevent such Party from resisting, challenging, contesting, or appealing any law, statute, regulation, or decision of any federal, state, or local government or agency which such Party claims to be in invalid, unlawful, arbitrary, or capricious.

20.11Inflation.

Monetary thresholds as expressed in this Agreement in Articles 7.5.6, 7.5.7, and 8.1, each shall be adjusted on each anniversary of the Execution Date hereof by the percentage change in the Producer Price Index Turbines and Turbine Generator Sets (PPI PCU 3511#(N), June 1982 = 100) during the immediately succeeding year.  Adjustments shall be made on final revised data.  If such index ceases to be published, a similar index shall be selected by the Parties in substitution thereof.  If such index is rebased, appropriate adjustments to this formula will be made by the Parties to carry out the original intention of the Parties.

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20.12Condemnation.

In the event any portion of the Trimble County Unit 2 Project shall be condemned and taken by exercise of any right of eminent domain or for public or quasi-public use, and the Parties hereto are able to continue their use and operation of the remaining portion thereof, this Agreement shall not terminate.  The proceeds of any payment of any award or compensation arising from such condemnation (net of any unrecovered expenses of any nature incurred by the Parties with respect thereto, which expenses shall be fully reimbursed to the Party or Parties incurring such expenses) shall be apportioned between the Parties on the basis of their respective Percentages.  In the event that all or substantially all of the Trimble County Unit 2 Project shall be condemned and taken by exercise of any right of eminent domain or for public or quasi-public use, this Agreement shall terminate as of the date of said taking and the proceeds of any award or compensation arising from such condemnation (net of any unrecovered expenses of any nature incurred by the Parties with respect thereto, which expenses shall be fully reimbursed to the Party or Parties incurring such expenses) shall be apportioned between the Parties on the basis of their respective Percentages.

20.13Americans with Disabilities Act.

In constructing, maintaining and operating the Trimble County Unit 2 Project, the Companies shall comply with the Americans with Disabilities Act.

20.14Amendments.

This Agreement may be amended only by a written instrument duly executed by the Parties.  When so amended, the Parties shall execute a conformed copy of the Agreement, which conformed copy shall contain all amendments to the Agreement and shall thereafter govern the Parties.

20.15No Agency or Third Party Beneficiary.

Except as expressly provided herein, nothing in this Agreement is intended to or shall create an agency whereby a Party becomes an agent for another Party in any relationship with any Person.  This Agreement is solely among the Companies, IMPA and IMEA and shall not be construed to create any third-party beneficiary relationship with any other Person.

20.16Obligations Are Several.

The duties, obligations and liabilities of the Parties are intended to be several and not joint or collective, and no Party shall be jointly and severally liable for the acts, omissions, or obligations of any other Party.

20.17Cooperation.

The Parties shall cooperate with each other and provide information as may be necessary to facilitate, among other things, the filing of applications for authorizations, permits, licenses, or financing and the execution of such other documents as may be reasonably necessary to carry out

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the provisions of this Agreement, subject to reasonable protections necessary to preserve each Party’s confidential or proprietary information.

20.18Intent.

The Parties agree that all discussions and negotiations related to this Agreement relate expressly to the Trimble County Unit 2 Project and do not amend and may not be used by any Party to interpret any provision or course of conduct arising out of the Unit 1 Participation Agreements.  Similarly, any similarity to or difference between the provisions of this Agreement and the provisions of the Unit 1 Participation Agreements shall not be used in any way, directly or indirectly, to interpret the meaning or intent of the parties to the Unit 1 Participation Agreements.

20.19Approvals.

The Parties shall use their respective Best Efforts to obtain as quickly as possible all requisite governmental, regulatory, and judicial approvals, including Commission Approvals, where applicable, of the consummation of the transactions contemplated herein.

20.20Access.

Official representatives of the Parties and their designees, including any Party’s bond trustee, shall have the right, upon sufficient advance notice to the Companies, to enter upon the Trimble County Unit 2 Project facilities subject to all safety, insurance, and industrial security requirements and the need for efficient operation of the Trimble County Unit 2 Project.

20.21Further Assurances.

The Parties shall execute such other instruments, if any, as may be necessary or appropriate to confirm the respective rights and interests of the Parties hereunder and to maintain their respective Ownership Interests.

20.22Joint Effect.

Preparation of this Agreement and its appendices has been a joint effort of the Parties and the resulting document (or any portion thereof) is not to be construed more severely against one of the Parties than against the others.

20.23Certain Costs.

In the course of undertaking the Development Work, the Construction Work, the Operating Work or the construction or procurement of Incremental Capital Assets, the Companies are entitled to take actions, that in their reasonable judgment are in the best interests of the Trimble County Unit 2 Project.  If such actions cause Louisville, Kentucky Utilities, or both of them to experience a cost or expense outside the Trimble County Unit 2 Project, a fair share of such cost or expense shall be allocated to the Trimble County Unit 2 Project to be shared by the Parties in proportion to their respective Percentages, provided that such actions have been

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presented to and approved unanimously by the Coordination Committee, which approval shall not be unreasonably withheld.

20.24Good Utility Practice.

Each Party hereby agrees to perform the Work and other obligations to be performed by it under this Agreement in accordance with Good Utility Practice.

20.25Affiliate Transactions.

The Companies shall be entitled to engage, contract with or otherwise arrange for the use of any of their employees, the employees of Affiliates, Affiliates or non-Affiliates in connection with the performance of the Companies’ obligations under this Agreement.  The cost of engaging, contracting with or otherwise arranging for the use of any employee, the employees of Affiliates, Affiliates or non-Affiliates shall be charged and allocated to the Parties on the same basis as such cost would be charged and allocated to any other generating station owned by either of the Companies when so engaging, contracting with or otherwise arranging for the use of its employees, employees of Affiliates, Affiliates or non-Affiliates.  If the Companies desire to enter into a contract or other arrangement with an Affiliate (each such contract or other arrangement an “Affiliate Contract”), such contract or arrangement shall be negotiated and administered in good faith, on a basis no less favorable than an arms’ length basis, have terms, when taken as a whole, at least as favorable to the Parties as those available in the market from non-Affiliates.  If any Affiliate Contract, amendment thereof, or any aspect of the work or obligations required thereunder is approved unanimously by the Coordination Committee, IMPA and IMEA shall be deemed to have waived any right to object to the terms and conditions of such Affiliate Contract, amendment or aspect to the extent so approved, including on grounds of the absence of good faith, lack of arms’ length negotiations or the presence of terms not at least as favorable to the Parties as those available in the market from non-Affiliates.

ARTICLE 21.
TERM AND TERMINATION

21.1Termination.

21.1.1Retirement.

This Agreement shall terminate at such time as those activities that are necessary to retire Trimble County Unit 2 from service have been completed.  Retirement from service shall include:  dismantling, demolishing, and removal of equipment, facilities, and structures; security; maintenance; disposing of debris; and any site work necessary to lawfully and responsibly effect such retirement.  Termination of this Agreement, however, shall not terminate or affect, as between the Parties, the continued liability, if any, of the Parties for environmental considerations or other obligations imposed by Applicable Law, nor shall it terminate or affect, as between the Parties, the receipt and pro rata sharing of benefits, if any, accruing to the Parties for environmental allowances or other entitlements provided by Applicable Law.

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21.1.2Construction Closing Does Not Occur.

Except as set forth in this Article 21.1.2 or Article 2.1.3, if the Construction Closing has not occurred on or before December 31, 2005 (as such date may be extended by the Coordination Committee or as provided in this Article 21.1.2), (i) this Agreement shall terminate and no Party shall have any further liability, each to the other, on account of such termination, (ii) each Party shall remain liable for all of its obligations incurred prior to the date of such termination and shall not be entitled to a refund or return of any amounts paid or expended under this Agreement, and (iii) the respective rights of IMPA or IMEA pursuant to Article 15 of the Unit 1 Participation Agreements shall not be reinstated.  Notwithstanding the foregoing, if the conditions to the participation of each of IMPA and IMEA in the Construction Closing as set forth in Article 6 have been satisfied or waived by IMPA and IMEA respectively and, IMPA and IMEA, in good faith, tender the payments required pursuant to Article 6.2.1, and are otherwise willing to close the transactions contemplated herein at the Construction Closing on or before December 31, 2005 (as such date may be extended by the Coordinating Committee), and the Companies are not able to close, but, in good faith, continue to pursue the development of the Trimble County Unit 2 Project or a substantially similar project based on the Development Work, then the last day for the Construction Closing to occur shall be extended from December 31, 2005, to and until the earlier of the date upon which the Companies withdraw pursuant to Article 6.5.1 or the Companies schedule a Construction Closing on no less than seven (7) days’ notice if such closing is scheduled to occur on or prior to January 31, 2006, or forty-five (45) days’ notice if such closing is scheduled to occur after January 31, 2006.  Should the Companies fail to pursue the development of the Trimble County Unit 2 Project or a substantially similar project based on the Development Work, the Companies shall be deemed to have withdrawn under Article 6.5.1 and the rights of each of IMPA and IMEA pursuant to Article 15 of the Unit 1 Participation Agreement to which it is a party shall be reinstated.

21.1.3Withdrawal of the Companies.

If the Companies withdraw from this Agreement pursuant to Article 6.5.1 after the period specified in clause (i) or (ii) of Article 6.5.6, and IMPA and IMEA do not withdraw and are then prepared to proceed in accordance with this Agreement to the Construction Closing, this Agreement shall terminate on the date of such withdrawal and no Party shall have further liability, each to the other, on account of such termination, except as provided below.  If such withdrawal by the Companies is primarily for Development Reasons, this Agreement shall terminate and each Party shall remain liable for its obligations incurred hereunder prior to the date of withdrawal and no Party shall be entitled to a refund or return for any amounts paid or expended under this Agreement.  If such withdrawal by the Companies is primarily for reasons other than Development Reasons, each Party shall be liable for its obligations incurred hereunder prior to the date of such withdrawal, provided, however, the Companies shall refund the Refund Amount to IMPA and IMEA.  Upon any withdrawal by the Companies under this Article 21.1.3, the rights of each of IMPA and IMEA pursuant to Article 15 the Unit 1 Participation Agreement to which it is a party shall be reinstated.

21.1.4Withdrawal of IMPA and IMEA.

If IMPA and IMEA shall both withdraw from this Agreement pursuant to Article 6.5 and the Companies then intend to proceed to develop the Trimble County Unit 2 Project, this

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Agreement shall terminate on the date of such withdrawal and no Party shall have further liability, each to the other, on account of such termination, provided, however, each Party shall remain liable for all of its obligations incurred prior to the date of such termination and shall not be entitled to a refund or return of any amounts paid or expended under this Agreement and, provided, further, the rights of each of IMPA and IMEA pursuant to Article 15 of the Unit 1 Participation Agreement to which it is a party shall not be reinstated.

21.2Retirement of Property.

The Coordination Committee shall have authority in decisions regarding the retirement from service of any and all property constituting a portion of Trimble County Unit 2 or the Trimble County General Plant Facilities which, in the Coordination Committee’s judgment, is damaged, worn out, uneconomic, unreliable, obsolescent, or otherwise unfit for use.  However, Trimble County Unit 2 shall not be retired from service as a generating unit without the written consent of the Parties prior to the earlier of:

(i)the expiration of thirty-five (35) years following the Commercial Operation Date of Trimble County Unit 2; or

(ii)the final maturity date of the project revenue bonds originally issued by IMPA or IMEA to finance their respective initial Ownership Interests or to pay the cost of any improvements or repairs issued thereafter, or the final maturity date of any bonds issued by IMPA or IMEA to refund such originally issued bonds.

21.3Retirement Costs.

All costs (less salvage credits, if any) associated with retirement of the Trimble County Unit 2 Project or portions thereof including:  dismantling, demolishing, and removal of equipment, facilities, and structures (including the cost of transportation and handling incidental thereto); security; maintenance; disposing of debris; and any site work necessary to lawfully and responsibly effect such retirement, shall be shared by the Parties in proportion to their respective Percentages.  Payments for these costs (less salvage credits, if any) as they are incurred, shall be made in accordance with the provisions of Article 10.  If such salvage credits exceed such costs, the difference shall be shared by the Parties in proportion to their respective Percentages.

21.4Effect of Withdrawal or Transfer on Agent.

Except as provided below, at such time as IMPA or IMEA withdraws from this Agreement or transfers all of its Ownership Interest in accordance with this Agreement, the agency granted to the Companies by IMPA and IMEA hereunder, as appropriate, shall be revoked prospectively and all prior acts shall remain valid and binding, subject to the conditions and limitations set forth in this Agreement.  Notwithstanding the foregoing, the appointment of the Companies as agent for the Parties hereunder shall continue (i) with respect to the agency granted pursuant to Article 12.1, for as long as necessary after such withdrawal or transfer for the Companies to fulfill their responsibilities under Article 12.1 in respect of periods during which IMPA or IMEA was a Party to this Agreement and (ii) as necessary to manage and administer executory contracts, real estate and permits and approvals of the agent or the Parties.  IMPA and IMEA each further agree that upon withdrawal or transfer of its Ownership Interest it will

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cooperate with the Companies and take any and all further actions and shall execute and file where appropriate any and all such further legal documents and papers as may be reasonable under the circumstances in order to facilitate such withdrawal or transfer and the continued development, construction or operation of the Trimble County Unit 2 Project, including action to seek any required governmental or regulatory approval and to obtain any other required consent, release, amendment, or other similar document.

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IN WITNESS WHEREOF, each of the Parties has caused this Agreement to be duly executed.

		LOUISVILLE GAS AND ELECTRIC COMPANY
Attest:		By:
	Secretary		Name:
			Title:
		KENTUCKY UTILITIES COMPANY
Attest:		By:
	Secretary		Name:
			Title:
		INDIANA MUNICIPAL POWER AGENCY
Attest:		By:
	Secretary		Name:
			Title:
		ILLINOIS MUNICIPAL ELECTRIC AGENCY
Attest:		By:
	Secretary		Name:
			Title:

EX-10.45

Exhibit 10.45

BARGE TRANSPORTATION AGREEMENT

This is a barge transportation agreement between LOUISVILLE GAS AND ELECTRIC COMPANY (LG&E) effective January 1, 2002 and between KENTUCKY UTILITIES COMPANY (KU) effective July 1, 2002, both Kentucky corporations, whose addresses are 220 West Main Street, Louisville, Kentucky, 40202 (collectively “Buyer”) and CROUNSE CORPORATION, a Kentucky corporation, whose address is 2626 Broadway, Paducah, Kentucky 42002-8109 (“Carrier”).

RECITALS

1.LG&E owns and operates a generating plant known as Mill Creek Station which is located on the Kentucky side of the Ohio River at Mile point 626.4 (“Mill Creek”). The coal barge unloader currently at Mill Creek is a clamshell type digger with an average dig rate of about one thousand (1,000) tons per hour. The limestone barge unloader currently at Mill Creek is an excavator equipped with a clamshell bucket with an average dig rate of about four hundred (400) tons per hour.

2.LG&E owns and operates a generating plant known as Trimble County Station which is located on the Kentucky side of the Ohio River at Mile point 571.4 (“Trimble County”). The coal barge unloader currently at Trimble County is a bucket-ladder style digger with an average dig rate of about three thousand and fifty (3,050) tons per hour. The limestone barge unloader currently at Trimble County is a clamshell type digger with an average dig rate of about four hundred and sixty-five (465) tons per hour.

3.LG&E owns and operates a generating plant known as Cane Run Station which is located on the Kentucky side of the Ohio River at Mile point 617.0 (“Cane Run”). The

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coal and limestone unloader will be an excavator that digs the material out of the barge as the barge passes beneath the excavator. The coal and limestone unloader is designed with an average dig rate of about one thousand and six hundred (1,600) tons per hour.

4.KU owns and operates a generating plant known as Ghent Station which is located on the Kentucky side of the Ohio River at Mile point 535.8 (“Ghent”). The coal and limestone unloader  is a bucket-ladder style digger with an average dig rate of about one thousand and eight hundred (1,800) tons per hour.

5.For purposes hereof, the term “Buyer” shall refer to LG&E relative to the coal and limestone that is delivered to LG&E, and shall refer to KU relative to the coal and limestone that is delivered to KU.

6.Jefferson County Riverport Authority is a transloading facility located on the Kentucky side of the Ohio River at Mile point 618.00 (“Riverport”). The barge unloader is a clamshell type digger with an average dig rate of about four hundred (400) tons per hour.

AGREEMENTS

The parties hereto agree as follows:

1.General.  Carrier will transport coal and limestone by barge to Mill Creek, Cane Run, Trimble County, Ghent, and Jefferson County Riverport. Buyer will compensate Carrier therefor, under all the terms and conditions of this Agreement.

2.Term. The term of this Agreement (the “Term”) shall commence January 1, 2002 for Louisville Gas and Electric Company and July 1, 2002 for Kentucky Utilities Company and shall continue through December 31, 2007 subject to the following. The rates and other terms and conditions set forth in this Agreement are subject to review for any reason, at the request of either party, for revisions to become effective on January 1, 2005. Either party may request such a review by giving the other party written notice of such

2

request by October 1, 2004. The parties shall then use their best efforts to negotiate in good faith an agreement on new rates and/or other terms and conditions between October 1, 2004 and November 30, 2004. If the parties do not reach an agreement on new rates and/or other terms and conditions by December 1, 2004, then this Agreement will terminate as of December 31, 2004 without liability due to such termination for either party.

3.Cargo.  Carrier will transport under the terms of this Agreement all solid fuel and limestone purchased by Buyer for delivery by barge (the “Cargo”), except for (a) distress Cargo already in barges belonging to other carriers, (b) Cargo purchased under spot contracts from suppliers having contracts with other carriers, (c) Cargo purchased from loading points not covered by Section 7 and (d) Cargo which is purchased FOB Destination, except that the Cargo transported by another carrier during any calendar month pursuant to exceptions (a) through (d) shall not exceed ten percent (10%) of the total Cargo (in tons) purchased by Buyer for delivery by barge during such calendar month. These restrictions shall not apply if Buyer requires more Cargo transportation than Carrier can provide within the time frame Buyer requires for loading, regardless of whether such non-performance is excused or unexcused, and regardless or whether Buyer’s delivery requirements are of an urgent or non-urgent nature. Buyer agrees to provide Carrier as much notice as practicable and Carrier agrees to confirm whether or not barges are available promptly. If barges belonging to another carrier are docked at the Buyer’s plant with Carrier’s barges, then Buyer shall pay demurrage to Carrier at the greater of (i) the same terms and conditions which would govern such other barge carrier’s right to recover demurrage or (ii) the terms of Section 8 herein. Notwithstanding any projections of Buyer’s barging requirements or any prior barging requirements of Buyer, Buyer has no obligation to have any Cargo transported under this Agreement at any time, but promises only that all Cargo actually delivered by

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barge to Buyer will be delivered under this Agreement, subject to the exceptions set forth above.

4.Delivery.

(a)Carrier will receive Cargo at the loading points listed in Section 7 hereof. Carrier will furnish empty barges at the Loading Points in adequate numbers and at such times as to permit loading of the Cargo in accordance with the Cargo suppliers’ reasonable operating schedules and Buyer’s supply requirements. Buyer’s contracts with its Cargo suppliers shall require them, at their own expense, to load the Cargo into the barges with due diligence and dispatch and otherwise comply with the reasonable requirements of Carrier’s barging operation. The Cargo suppliers shall have the right to refuse to load any barges they consider unseaworthy or any barges containing water or other foreign matter. In the case of limestone loading, Buyer’s limestone supplier shall be responsible for cleaning barges to its reasonable satisfaction. Carrier will deliver the loaded barges to Buyer’s unloading dock or other point designated by Buyer at such times as to permit the unloading of the Cargo in accordance with Buyer’s reasonable operating schedules.

(b)At Mill Creek, Ghent, Trimble County limestone, and Jefferson County Riverport, Carrier shall properly and securely moor the loaded barges at the unloading dock and notify the appropriate person(s) that such mooring has been completed in accordance with the provisions set forth in Appendix A, which is attached hereto. Buyer at its own expense shall have the Cargo unloaded out of the barges with due diligence and dispatch and otherwise comply with the reasonable requirements of Carrier’s barging operation.

(c)At Trimble County and Cane Run, the Carrier shall notify the appropriate person(s) of incoming barges at least six (6) hours prior to the arrival of each tow, in accordance with the provisions set forth in Appendix A. Carrier shall provide the designated

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plant personnel with periodic updates of the expected day of all tow arrivals. Carrier’s coal tows shall be unloaded on a stand-by basis, upon arrival, at Trimble County and Cane Run with Carrier being responsible for all placement, shifting and decking services at the plant. Buyer shall provide adequate shoreside personnel and equipment (including the shuttle barge) for the operation of the unloading system. The coal barges generally will be standby unloaded as follows: The Carrier shall provide a boat and all deck-hands and tying services and shall shuttle the coal barges to and away from the barge unloader; and shall leave with all empty coal barges. Carrier’s services shall be provided in accordance with the provisions set forth in Appendix A, which is attached hereto. After the barges are unloaded, Buyer shall notify Carrier that such unloading has occurred and Carrier shall remove the unloaded barges promptly. Buyer shall operate the unloader. When circumstances make standby unloading impractical in Buyer’s discretion or in the event Buyer claims that force majeure conditions prevent the unloading of a tow, then the Buyer shall have the option of: (1) reconsigning the tow to another of the Buyer’s plants, (2) having Carrier properly and securely moor the coal barges at the unloading dock and notifying the appropriate person(s) that such mooring has been completed and Buyer hiring a harbor boat to provide fleet security for the loaded tow, or (3) requesting Carrier remain at the plant with the tow and compensating Carrier at the applicable hourly rate of $225 per hour, subject to the same adjustments set forth in subsection 7(b).

(d)Except as otherwise expressly provided herein, Carrier shall supply at its own expense all labor, supervision, equipment and facilities, and shall pay all expenses and taxes whatsoever, incurred in connection with its performance under this Agreement.

5.Description of Barges.All barges used by the Carrier shall be in good and seaworthy condition, shall have two (2) interior side slope sheets, at least one (1) interior end

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slope sheet, shall not be wider than thirty-five (35) feet, and shall have a minimum capacity of fifteen hundred (1,500) tons of coal.

6.Compliance with Safety Procedures and Laws.

(a) Carrier represents and warrants that it is in the business of river barge transportation and that it possesses a high degree of professional expertise in all facets of river barge transportation and promises that it will exercise that degree of care of persons so skilled and that it will at all times provide adequate skilled personnel, equipment, facilities, and capital to transport Cargo safely in accordance with the terms of this Agreement.

(b) Without limiting the generality of the provisions of subsection (a) above, the Carrier will at all times in its performance under this Agreement comply with all applicable laws and regulations of any kind and all procedures and provisions set forth in Appendix A attached hereto.

7.Rates

(a)Subject to the adjustments set forth in subsections 6(b) and 6(c) hereof, Buyer shall pay to the Carrier the following rates per ton:

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CARGO – COAL

LOADING POINT		DESTINATION
River	Mile Point	Mill Creek	Cane Run	Trimble Co.	Ghent	Riverport
Monongahela	85 - 102	6.72	6.82	6.55	6.30	7.25
Monongahela	61.2-84.9	6.06	6.16	5.89	5.64	6.59
Monongahela	23.8-61.1	5.37	5.47	5.20	4.95	5.90
Monongahela	Below 23.7	4.68	4.78	4.51	4.26	5.21
Ohio	0-84.2	3.62	3.72	3.45	3.20	4.15
Ohio	84.3 - 126.5	3.22	3.32	3.05	2.80	3.75
Ohio	126.6 — 237.5	3.04	3.14	2.87	2.62	3.57
Ohio	237.6 - 279.3	2.67	2.77	2.50	2.25	3.20
Ohio	279.4 - 305.6	2.12	2.22	1.95	1.70	2.65
Ohio	305.7-317	2.02	2.12	1.85	1.60	2.55
Ohio	317.1-360	1.97	2.07	1.80	1.55	2.50
Ohio	TTI405.9	1.71	1.81	1.54	1.29	2.24
Ohio	470-531.5	1.60	1.70	1.43	1.18	2.13
Ohio	535.2-620	1.05	1.15	1.25	1.34	1.58
Ohio	620.1-720	1.19	1.29	1.54	1.63	1.72
Ohio	721 - 776.1	1.54	1.64	1.89	1.98	2.07
Ohio	Evansville 784.1	1.63	1.80	1.97	2.06	2.23
Ohio	785 - 846	1.98	2.18	2.33	2.42	2.61

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River	Mile Point	Mill Creek	Cane Run	Trimble Co.	Ghent	Riverport
Ohio	851.8	2.13	2.23	2.48	2.57	2.66
Ohio	853-918.5	2.16	2.35	2.50	2.58	2.78
Ohio	918.6-962	2.30	2.40	2.65	2.74	2.83
Big Sandy	All Origins	2.17	2.27	2.00	1.75	2.70
Kanawha	Above 82.8	3.92	4.02	3.75	3.50	4.45
Kanawha	67.7-82.7	3.77	3.87	3.60	3.35	4.30
Kanawha	Below 67.6	3.64	3.74	3.47	3.22	4.17
Green	Above 63.1	2.52	2.73	2.86	2.95	3.16
Green	0-63.0	1.92	2.10	2.26	2.35	2.53
Tennessee	0-25	2.35	2.45	2.70	2.79	2.88
Upper Miss.	98.5	3.99	4.09	4.34	4.43	4.52
Upper Miss.	125	4.86	4.96	5.21	5.30	5.39
Upper Miss.	161-185	6.07	6.17	6.42	6.51	6.60
Lower Miss.	Mobile Bay	9.05	9.15	9.40	9.49	9.58
Lower Miss.	55.3 - 57 *	7.36	7.46	7.71	7.80	7.89

* If shipped from Davant (Electro-Coal) Mile 55.3, Lower Mississippi, then deduct 50.35 per ton.

CARGO – LIMESTONE

	DESTINATION
LOAD POINTS	Mill Creek		Trimble Co.		Ghent
Cape Sandy (MP 674 Ohio River)	$	0.78	$	0.93	$	0.95
New Amsterdam (MP 653 Ohio River)	$	0.78	$	093	$	0.95

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DEMURRAGE

Mill Creek, Jefferson County Riverport, Trimble Co., & Ghent	$150/demurrage debit
Trimble Co. Coal and Cane Run	$225/demurrage debit

Rates do not include switching and fleeting charges at destinations (except Jefferson Riverport) or origins. Carrier shall not be responsible for such charges. In the event the harbor service charges at Jefferson Riverport are increased or decreased, the Carrier may increase or decrease its rates accordingly. Rates from loading points not listed above will be negotiated as required and shall be reasonably related to those set forth above, taking into account differences in distance, operating conditions and loading conditions. If Buyer and Carrier cannot agree on a rate from a particular loading point, then Buyer shall have the right to hire another carrier to transport Cargo from such loading point. Such tons transported by another carrier shall not be subject to the limitations set forth in Section 3a through 3d.

(b)The rates set forth in subsection 7(a) as adjusted per this section shall apply to Cargo loaded commencing January 1, 2002 for LG&E and commencing July 1, 2002 for KU. Rates will be adjusted each quarter thereafter as follows:

(1) Twenty percent (20%) of the base rate shall remain fixed for the Term of this Agreement.

(2) Fifty-five percent (55%) of the base rate (hereinafter the “55% component”) shall change in proportion to changes in the first published PPI Industrial Commodities Index Less Fuels and Related Products and Power found in Table 8 of the Producer Price Indexes, published monthly by the U.S. Department of Labor, Bureau of Labor Statistics (hereinafter the “PPI”). The change in this component shall be calculated by multiplying a fraction, the denominator of which shall be the average PPI for April, May, and June, 2001 (the average base index first published for the period is 143.6), and the

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numerator of which shall be the average PPI for the three-month period ending November 30, February 28, May 31, or August 31 (hereinafter the “calculation period”) times the initial fifty-five percent (55%) component. The effective date of the changes in this component shall be January 1, April 1, July 1, or October 1 as the case may be, for the remainder of the Term of this Agreement, commencing January 1, 2002 for LG&E and July 1, 2002 for KU.

(3) Twenty percent (20%) of the base rate (hereinafter the “20% Component”) shall change in proportion to changes in the average of (a) the posted price of #2 diesel fuel at Catlettsburg, Kentucky and (b) the Ohio Valley Marine Service posted price at the mouth of the Green River (together, the “Diesel Posted Prices”). The change in the 20% Component shall be calculated by multiplying a fraction, the denominator of which shall be the average Diesel Posted Prices on the first (1^st) day of each of the months of April, May, and June 2001(the average base Diesel Posted Prices for the period is 86.7 cents per gallon), and the numerator of which shall be the average Diesel Posted Prices on the first (1st) day of each of the months for the three (3) month periods beginning September, December, March and June (hereinafter the “Calculation Period”) times the initial 20% Component. The effective date of the changes in this component shall be the first day of the calendar quarter following the end of the Calculation Period (January 1, April 1, July 1, or October 1, as the case may be), for the remainder of the Term of this Agreement, beginning January 1, 2002 for LG&E and beginning July 1, 2002 for KU.

(4) Five percent (5%) of the base rate (the “5% Component”) represents federal taxes: the Inland Waterway Fuel Tax, Deficit Reduction Tax, and Leaking Underground Storage Tank Tax (collectively, the “Taxes”). The average base for the tax for the period is 24.4 cents per gallon, which amount is comprised of Inland Waterway taxes in the amount of 20.0 cents per gallon, Deficit Reduction taxes in the amount of 4.3

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cents per gallon, and Leaking Underground Storage Tank taxes in the amount of .10 cents per gallon). This 5% Component will change to the extent of any future changes in the amount of Taxes, and shall be adjusted effective on the first (1st) day of the calendar month following the effective date of any change that occurs on or after January 1, 2002, (except when such change is effective on the first (1st) day of such month, in which case the adjustment shall be made as of such date).

(c)Changes in the PPI.  The current index of 1982 = 100 applies to the PPI. Should this index be revised or a new one adopted, the parties shall make an appropriate adjustment, either in accordance with published instructions from the Bureau of Labor Statistics regarding such revision or, if no such instructions are published, by a proportionate revision which will fairly reflect such change in the index.

(d)Rates will be adjusted for the cost of any government-imposed tolls or other government charges (“Governmental Impositions”) enacted after the effective date of this Agreement which are assessed on river transportation and assessed against the Carrier for carrying Cargo under this Agreement. Such rate adjustments will be effective as of the effective date of such tolls or charges. Governmental Impositions shall not apply to: Taxes, as defined in the preceding section, changes in taxes on fuel, which changes shall be covered in sections 7(b)(3) and 7(b)(4) hereof, any noncompliance existing as of the effective date of this Agreement, financing costs and taxes, income tax or property taxes or related costs, any penalties, interest, fines, costs of arbitration, mediation, litigation, or any other type of dispute resolution through all stages of appeal, payment of judgments against Carrier or Carrier’s affiliates, or on instruments or documents evidencing the same or on the proceeds thereof, and wages, benefits and retirement. In order to constitute a Governmental Imposition, it must be imposed against the barging industry either on a regional, state or national basis. Carrier must notify Buyer in writing

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of the obligation to comply with such laws (if Carrier anticipates meeting the conditions that would require Carrier to comply with such laws) within thirty (30) days of the time Carrier becomes aware of such laws, setting forth the specific law or regulation and the anticipated actual or actual financial impact on Carrier’s delivery of Cargo hereunder, and the anticipated or actual effective date. Additionally, the applicable base price hereunder shall be increased only if the price adjustment is allocated evenly to all effected cargo transported by Carrier, so that Buyer is allocated only its proportionate share of such Governmental Imposition, and the base price shall be decreased for any savings resulting from changes in such Governmental Imposition. The base price can not be increased due to Governmental Impositions (a) on an annual basis, more than five percent (5%) per ton of the rates effective January 1, 2002; and (b) on a cumulative basis during the Term, more than fifteen percent (15%) per ton of the rates effective January 1, 2002. If (a) the annual increase of Governmental Impositions is more than five percent (5%) of the rates effective on January 1, 2002, or (b) if the total amount of Governmental Impositions is more than fifteen percent (15%) of the rates effective January 1, 2002, on a cumulative basis during the Term of this Agreement, Carrier may terminate this Agreement upon not less than sixty (60) days’ written notice to Buyer. Alternatively, Buyer may agree, by forwarding written notice to Carrier within sixty (60) days after receiving Carrier’s written notice of termination to accept the cumulative Base Rate increase of more than fifteen percent (15%). Carrier shall notify Buyer of any such changes within the time frames set forth above and supply sufficient documentation for Buyer to verify any such change. Either Buyer or Carrier may request a base price adjustment, which shall be comprised of no more than the reasonable actual costs directly associated with the effect of such change on the Cargo to be transported hereunder. Such adjustment shall be made effective on the first day of the calendar month following the effective date of any change,

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(except when such change is effective on the first day of the month, in which case the adjustment shall be made as of such date).

(e)The calculations for changes in the components of the base rate are to be made to three (3) decimal places, with the total being rounded to two (2) decimal places.

(f)The term “ton” as used herein shall mean a net ton of two thousand (2000) pounds avoirdupois weight.

8.Demurrage.

(a)Free Time At Mill Creek, Ghent, Jefferson County Riverport, and Trimble County Limestone Destinations. Buyer shall be allowed four (4) “Free Unloading Days” within which to unload each of the barges delivered to Buyer at Mill Creek (coal and limestone), Ghent (coal and limestone), Jefferson Riverport (coal and limestone) and Trimble County Limestone pursuant to this Agreement. An “Unloading Day” shall commence at 7:00 a.m. and continue until 7:00 a.m. on the next day. The calculation of “Free Unloading Days” for each barge, for purpose of the unloading demurrage accounts described in Sub-section c, below, shall commence at the first (1st) 7:00 a.m. following the delivery of such barge to Buyer and notification is given to Buyer that the first (1st) barge is moored to the Buyer’s dock and ready to unload, and shall run continuously thereafter for a period of ninety six (96) hours. “Actual Unloading Days” for each barge, for purpose of said demurrage accounts, shall commence concurrently with the commencement of the “Free Unloading Days” and shall continue until the first (1^St) 7:00 a.m. following the time that Carrier’s dispatcher has been notified that the barge is actually unloaded and ready for pick up (for a barge unloaded and said notification given before the first (1^st) 7:00 a.m. following delivery, the “Actual Unloading Days” would be zero).

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(b)Free Time At Trimble County Coal and Cane Run Destinations. Buyer shall be allowed per barge tow, one (1) hour per barge plus one (1) additional hour as “Free Unloading Hours” within which to unload the barge tow delivered to Buyer at Trimble County Coal and Cane Run Stations. For example, if a barge tow of six (6) barges is delivered, seven (7) free unloading hours shall be allowed Buyer within which to unload the six (6) delivered barges (one (1) hour per barge plus one (1) hour equals seven (7) hours). The calculation of “Free Unloading Hours” for the purpose of the unloading demurrage accounts described in Sub-section (d) below, shall commence when Buyer is notified that the first (1^St) barge is located under the unloader and is ready to unload, except that, if Buyer for any reason, except for force majeure, is not prepared to unload such barge or has another barge line’s barge under the unloader, then Free Unloading Hours shall begin when Carrier notifies Buyer that it has arrived and is ready to begin unloading. “Actual Unloading Hours” for each barge tow, for purpose of said demurrage accounts, shall commence concurrently with the commencement of the “Free Unloading Hours” and shall continue until Carrier is notified by Buyer that the barge tow is actually unloaded and ready for removal. Fractions of an hour shall be rounded up to the nearest one-half hour.

In the event a Crounse coal tow arrives at Trimble County within less than twelve hours after the completion of the free unloading time for the previous Crounse coal tow, the free time for the second coal tow shall not commence until the twelfth hour following completion of the free time for the first Crounse coal tow. For example, if a ten (10) barge Crounse coal tow arrives at 0200 hours, the free time would expire at 1300 hours (eleven hours later). If a second Crounse coal tow arrives at 1100 hours, the free time for the second Crounse coal tow shall not commence until 0100 hours the next day (twelve hours after the completion of the free unloading time for the first Crounse coal tow). This exception shall

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not apply to barges in either tow if such barges were diverted from a plant other than Trimble County.

The plant shall maintain a log of start and stop times for the unloading of each tow and shall communicate such times to Carrier’s towboat pilothouse personnel, as requested, in order for both parties to mutually reconcile free time calculations. Unloading shall be considered complete once the bucket unloader has completed its unloading cycle (and been cleared from the cargo box) for the last barge in that tow.

(c)Demurrage Accounts For Mill Creek, Ghent, Jefferson County Riverport, and Trimble County Limestone. Carrier shall maintain separate unloading demurrage accounts for Mill Creek, Ghent, Jefferson County Riverport, and Trimble County Limestone, in which one (1) credit shall be entered for each day the Actual Unloading Days for a barge are less than four (4) days for that barge, and in which one (1) debit shall be entered for each day the Actual Unloading Days for a barge exceed four (4) days for that barge. Separate demurrage accounts for coal and limestone shall be kept at Mill Creek, Ghent and Trimble County.

At the end of each month during the Term of this Agreement, the demurrage accounts shall be balanced and settled for that period (hereinafter called “Accounting Period”) by canceling one (1) debit with one (1) credit in each demurrage account and by the payment by Buyer to Carrier of one hundred and fifty dollars ($150), subject to the same adjustments set forth in subsection 7(b), for each such demurrage debit not so canceled. In the event the total credits exceed the total debits in the account at the end of any Accounting Period, such excess credits shall be canceled and shall not carry over to the next Accounting Period. At Buyer’s request, but not more frequently than once per month, Carrier shall send Buyer a summary of the current demurrage accounts.

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(d)Demurrage Accounts For Trimble County Coal and Cane Run. Carrier shall maintain unloading demurrage accounts for Trimble County coal and Cane Run, in which Buyer will receive one (1) credit for each hour the “Actual Unloading Hours” are less than the “Free Unloading Hours” and one (1) debit shall be entered for each hour the Actual Unloading Hours exceed the Free Unloading Hours.

At the end of each month during the Term of this Agreement, the demurrage accounts shall be balanced and settled for that one month period (hereinafter called “Accounting Period”) by canceling one (1) debit with one (1) credit in each demurrage account and by the payment by Buyer to Carrier of two hundred and twenty-five dollars ($225), subject to the same adjustments set forth in subsection 7(b), for each such demurrage debit not so canceled.  In the event the total credits exceed the total debits in the account at the end of any Accounting Period, such excess credits shall be canceled and shall not carry over to the next Accounting Period. At Buyer’s request, but not more frequently than once per month, Carrier shall send Buyer a summary of the current demurrage accounts.

9.Payment.

The method of determining the weight of the Cargo for the purpose of calculating payment to the Carrier hereunder shall be the same method used for the purpose of calculating payment to the Cargo set forth in Buyer’s various coal supply and limestone agreements. For all tons of Cargo unloaded pursuant to the provisions of Section 4, between the first (1^st) and fifteenth (15th) days of any calendar month, Buyer shall make payment to Carrier for the transportation of such tons of Cargo, between each loading point and each delivery point, by the twenty-fifth (25th) of such month of transportation. If the twenty-fifth (25th) is not a regular workday, payment shall be made on the next regular workday. Within approximately fifteen (15) days after the end of each calendar month, Buyer shall provide to

16

Carrier the number of tons of Cargo transported between each loading point and each delivery point during such calendar month under this Agreement. On the basis of this quantity information, Carrier shall submit an invoice to Buyer for receipt by Buyer on or before the twentieth (20th) of the month. Buyer shall make payment of such invoice (less the payment made for the tons of Cargo transported between the first (1^st) of the month and the fifteenth (15th) of the month) by the twenty-fifth (25th) of the month following delivery. If the twenty-fifth (25^th) is not a regular workday, payment shall be made on the next regular workday. Two (2) invoices will be sent to Buyer. The invoice for Louisville Gas and Electric will be sent to the following address:

Louisville Gas and Electric Company P.O. Box 32010

Louisville, Kentucky 40232

Attn: Manager, LG&E/KU Fuels

The invoice for Kentucky Utilities will be sent to the following address:

Kentucky Utilities Company

P.O. Box 32010

Louisville, Kentucky 40232

Attn: Manager, LG&E/KU Fuels

10.Indemnification.

The parties agree to defend, indemnify and hold harmless each other from any claim, demand, suit, loss, cost or expense or any damage which may be asserted, claimed or recovered against or from one of them by reason of any damage to property, including property of others, or injury, including death, sustained by any person or persons whomsoever to the extent such damage, injury or death arises out of any act or omission by the offending party, its officers, employees or parties engaged by it, in its performance of this agreement. Neither party shall be liable to the other party for consequential, punitive, or

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exemplary damages.

11.Insurance.At all times, the Carrier will carry and maintain at its own cost (a) protection and indemnity insurance, including tower’s liability, collision liability, and wharfinger’s liability, in the amount of at least five (5) million dollars per occurrence and (b) cargo insurance which shall fully insure the Cargo at the then current cost of that Cargo to Buyer, and (c) pollution insurance in the amount of at least five (5) million dollars. Certificates of insurance satisfactory in form to Buyer and signed by the Carrier’s insurer shall be supplied by the Carrier to Buyer evidencing that the above insurance is in force and that not less than thirty (30) calendar days written notice will be given to Buyer prior to any cancellation or material reduction in coverage under the policies. The Contractor shall cause its insurer to name Buyer as an additional named insured, and waive all subrogation rights against Buyer for all losses or claims arising from performance hereunder. Evidence of Buyer’s status as an additional insured, a statement that such status shall not prejudice any rights to which Buyer would have been entitled were Buyer not an additional insured, and evidence of such waiver of subrogation satisfactory in form and substance to Buyer shall be exhibited in the Certificate of Insurance mentioned above. Carrier’s liability shall not be limited to its insurance coverage.

12.Termination.If either party hereto commits a material breach of any of its obligations under this Agreement at any time, then the other party has the right to give written notice describing such breach and stating its intention to terminate the Agreement no sooner than 30 days after the date of the notice (the “Notice Period”). If such material breach is curable and the breaching party cures such material breach within the Notice Period, then the Agreement shall not be terminated due to such material breach. If such material breach is not curable or the breaching party fails to cure such material breach within the

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Notice Period, then this Agreement shall terminate at the end of the Notice Period in addition to all the other rights and remedies available to the aggrieved party under this Agreement and at law and in equity.

13.Force Majeure.If either party hereto is delayed in or prevented from performing any of its obligations under this Agreement due to acts of God, war, riots, civil insurrection, acts of the public enemy, strikes, lockouts, fires, floods, or earthquakes, equipment breakdowns, or other causes beyond the reasonable control of the affected party, then the obligations of both parties hereto shall be suspended to the extent made necessary by such event provided that such party gives written notice to the other party as promptly as practicable of the nature and probable duration of the force majeure event. The party declaring force majeure shall exercise due diligence to avoid and shorten the force majeure event and will keep the other party advised as to the continuance of the force majeure event. Services not provided during any force majeure period shall be made up within a reasonable time at the option of Buyer. If a force majeure event affects a material portion of the services hereunder for more than twenty (20) days, the party not claiming force majeure may terminate the contract by forwarding written notice to the claiming party. If the force majeure event claimed by Carrier is industry-wide, Buyer may not terminate this Agreement unless Buyer can obtain alternate river transportation services from another provider.

14.This section intentionally left blank.

15.Independent Contractor.Nothing in this Agreement shall be deemed to make the Carrier or any of the Carrier’s employers or agents the representative, agent, or employee of Buyer. The Carrier shall be an independent contractor and shall have responsibility for and control over the details and means for performance under this Agreement. Anything in this Agreement which may appear to give Buyer the right to direct the Carrier as to the details of

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its performance hereunder or to exercise a measure of control over the Carrier means that the Carrier shall be subject to the desires of Buyer only in the results achieved.

16.Equal Employment Opportunity.  To the extent applicable, Carrier shall comply with all of the following provisions which are incorporated herein by reference:  Equal Opportunity regulations set forth in 41 CRF §60-1.4(a) and (c) prohibiting discrimination against any employee or applicant for employment because of race, color, religion, sex, or national origin; Vietnam Era Veterans Readjustment Assistance Act regulations set forth in 41 CFR § 60-250.4 relating to the employment and advancement of disabled veterans and veterans of the Vietnam Era; Rehabilitation Act regulations set forth in 41 CFR § 60-741.4 relating to the employment and advancement of qualified disabled employees and applicants for employment; the clause known as “Utilization of Small Business Concerns and Small Business Concerns Owned and Controlled by Socially and Economically Disadvantaged Individuals” set forth in 15 USC § 637(d)(3); and subcontracting plan requirements set forth in 15 USC § 637(d).

17.Miscellaneous

(a)This Agreement shall be governed by the subject to the law of the Commonwealth of Kentucky (excluding its conflicts laws).

(b)All notices respecting this Agreement shall be in writing and shall be addressed as follows:

If to LG&E:	Louisville Gas and Electric Company
	P.O. Box 32010
	Louisville, Kentucky 40232
	Attn: Director Corporate Fuels and By Products
If to KU:	Kentucky Utilities
	P.O. Box 32010
	Louisville, Kentucky 40232
	Attn: Director Corporate Fuels and By Products

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If to Carrier:	Crounse Corporation
	2626 Broadway
	Paducah, Kentucky 42001
	Attn: President

(c)Attorneys’ Fees and Costs. If a dispute arises under this Agreement, the prevailing party shall be entitled to recover attorney’s fees and other costs from the nonprevailing party.

(d)Entire Agreement. This Agreement contains the entire agreement between the parties respecting the subject matter hereof and supersedes all prior or contemporaneous oral or written statements, understandings, and agreements.

(e)Headings. The paragraph headings appearing in this Agreement are for convenience only and shall not affect the meaning or interpretation of this Agreement.

provision of this agreement, or to take advantage of any rights hereunder, shall not be construed as a waiver of such provision or right.

(f)Waiver. The failure of either party to insist on strict performance of any provision of this agreement, or to take advantage of any rights hereunder, stall not be construed as a waiver of such provision or right.

(g)Remedies Cumulative. Remedies provided under this Agreement shall be cumulative and in addition to other remedies provided under this Agreement or by law or in equity.

(h)Severability. If any provision of this Agreement is found contrary to law or unenforceable by any court of law, the remaining provisions shall be severable and enforceable in accordance with their terms, unless such unlawful or unenforceable provision is material to the transactions contemplated hereby, in which case the parties shall negotiate in good faith a substitute provision.

(i)Binding Effect. This Agreement shall bind and inure to the benefit of the

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parties and their successors and assigns.

(j)Assignment.

(i)Carrier shall not, without Buyer’s prior written consent, which consent may be withheld in Buyer’s sole opinion, make any assignment, subcontracting or transfer of this Agreement by operation of law or otherwise, including without limitation any assignment or transfer as security for any obligation, and shall not assign or transfer the performance of or right or duty to perform any obligation of Carrier hereunder; provided, however, that Carrier may assign the right to receive payments directly from Buyer to a lender as part of any accounts receivable financing or other revolving credit arrangement which Carrier may have now or at any time during the Term of this Agreement, and provided further, that Buyer shall consider consenting to an assignment to an affiliate of Carrier. Buyer shall not unreasonably withhold its consent to an assignment to an affiliate of Carrier, provided: (a) the affiliate’s balance sheet, financial statement, and business experience and capability are comparable to Carrier’s, (b) the majority ownership of the affiliate is comparable to Carrier’s, and (c) Carrier receives Buyer’s prior written approval for the transfer.

(ii)Buyer shall not, without Carrier’s prior written consent, which consent shall not be unreasonably withheld, assign this Agreement or any right for the performance of or right or duty to perform any obligation of Buyer hereunder; except that, without such consent, Buyer may assign this Agreement in connection with a transfer by Buyer of all or a majority interest in the Buyer’s generating station that is the recipient of the coal to be delivered hereunder, or as part of a merger or consolidation involving Buyer.

(iii)In the event of an assignment or transfer contrary to the provisions of this section, the non-assigning party may terminate this Agreement immediately.

(k)Amendments. Except as otherwise provided herein, this Agreement may not be amended, supplemented or otherwise modified except by written instrument signed by both parties hereto.

The parties hereto have executed this Agreement effective as of the date first written above but actually on the dates set forth below.

LOUISVILLE GAS AND ELECTRIC COMPANY CROUNSE CORPORATION

22

KENTUCKY UTILITIES COMPANY
By:	/s/   Victor A. Staffieri
Title: Chief Executive Officer
Date: 8/21/02

Appendix A to Barging Agreement

Some specific minimum safety procedures are set forth below. This list in no way limits Carrier’s obligation to act safely at all times in its performance under this Agreement and to bear sole responsibility therefor. Additionally, while on Buyer’s property, Carrier will comply with Buyer’s safety rules for contractors.

1.Notice of Barge Transactions

At Mill Creek, Cane Run, Trimble County, and Ghent, the Carrier will notify Buyer of any barge transaction as follows. The Carrier first will attempt to notify Buyer’s guard service at the loading dock by way of the marine radio located at the Guard House. If the Carrier is unable to contact the guard service, the Carrier will notify the plant shift supervisor. If the Carrier is unable to notify the plant shift supervisor, the Carrier will notify the material handling supervisor. The Carrier shall not leave the barges until one of the Buyer’s employees or agents set forth above has been notified.

2.Location of Barges

At all times, the Carrier further will be prepared to, and upon request by

23

Buyer will, immediately state the location of any barge destined for Buyer and in the care and custody of Carrier from the time that Buyer requests barge placement at a holding point to the time that Carrier delivers the barges.

3.Mooring

(a)All barges that are moored at all destinations and are to be left at the plant site shall be moored using both the normal leaving lines supplied with each barge and a two inch (2”) fleeting line that is attached to each cell.

(b)Life preservers shall be worn by everyone working on the barges.

(c)For Trimble County and Cane Run, barges generally will be standby unloaded as stated in Section 4 of this Agreement. When circumstances dictate that barges will be moored at Trimble County, the maximum number of barges to be moored in the coal area is thirty (30) and in the limestone area is eighteen (18). Barges will be moored no more than three (3) abreast during rising river, falling river, high water, or icy conditions without a towboat in attendance.

(d)For Mill Creek, the maximum number of barges that can be moored without a harbor boat in attendance is thirty-two (32). Barges shall not be moored wider than five (5) abreast under any conditions.

(e)For Ghent, the maximum number of barges that can be moored without a harbor boat in attendance is thirty-two (32).

4.Riverport

For barges destined for the Riverport, the Carrier will comply with all requirements and procedures established by the Riverport pertaining to the Carrier’s performance hereunder.

24

5.Breakaway and Loose Barnes

If at any time and for any reason any barge breaks away from the dock or becomes loose, Carrier immediately will assist and cooperate in retrieving or securing such barge upon becoming aware of the situation.

25

EX-10.46

Exhibit 10.46

Base Salaries for Named Executive Officers

In December 2004, the Compensation Group of LG&E Energy LLC approved base salary increases for executive officers for 2005. The 2005 salaries for LG&E’s and KU’s named executive officers are as follows:

Officer Name	2005 Base Salary
Hermann, Chris	$	273,000
McCall, John R.	$	425,400
Rives, S. Bradford	$	345,280
Thompson , Paul W.	$	322,300
Staffieri, Victor A.	$	700,163

The salary increases were effective December 20, 2004.

EX-10.47

Exhibit 10.47

CERTIFICATE OF AWARD

LG&E Energy Long-Term Performance Unit Plan

200X-200X

Performance Unit Award

<Officer Name> has been awarded XX,XXX

LG&E performance units effective

January 1, 20XX.

Subject to terms and conditions of the plan, these performance units are payable in cash.

/s/ Victor A. Staffieri
Victor A. Staffieri
Chief Executive Officer	<Officer Name>
	Original – Employee
	Signed Copy – Employee Compensation File

EX-10.48

Exhibit 10.48

CERTIFICATE OF AWARD

E.ON Group Stock Option Program

20XX

Phantom Option Award

The Management Board of E.ON has awarded

X,XXX phantom options to <Officer Name>, effective

January 1, 20XX with a strike price of €XX.XX to be

converted to US dollars at an exchange rate of

XXXUS dollars per Euro ($XX.XX).

Subject to terms and conditions of the E.ON Group Stock Option Program, these phantom options are payable in cash.  The value of the phantom options will be based upon the market price of the underlying E.ON shares.

/s/ Victor A. Staffieri
Victor A. Staffieri
Chief Executive Officer	<Officer Name>

Original – Employee

Signed Copy – Compensation File

EX-12

EXHIBIT 12

KENTUCKY UTILITIES COMPANY

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

(Thousands of $)

		2004			2003			2002			2001			2000
Earnings:
Net Income		$	133,471		$	91,402		$	93,384		$	96,278		$	95,524
Add:
Federal income taxes - current		39,291			29,118			37,839			57,389			45,276
State income taxes - current		17,698			11,322			10,299			13,197			9,400
Deferred Federal income taxes - net		21,988			11,378			3,482			(12,117		)	(3,376		)
Deferred State income taxes - net		(503		)	904			1,459			(1,118		)	927
Investment tax credit - net		(2,054		)	(2,641		)	(2,955		)	(3,446		)	(3,674		)
Undistributed income of Electric Energy, Inc.		2,559			(3,644		)	(6,967		)	258			70
Fixed charges		26,425			25,980			26,717			35,215			40,834
Earnings		238,875			163,819			163,258			185,656			184,981
Fixed Charges:
Interest Charges per statements of income		25,501			25,249			25,688			34,043			39,484
Add:
One-third of rentals charged to operating expense (1)		924			731			1,029			1,172			1,350
Fixed charges		$	26,425		$	25,980		$	26,717		$	35,215		$	40,834
Ratio of Earnings to Fixed Charges		9.04			6.31			6.11			5.27			4.53
NOTE:
(1)	In the Company’s opinion, one-third of rentals represents a reasonable approximation of the interest factor.
	Rents	2,773			2,193			3,087			3,517			4,051
		924			731			1,029			1,172			1,350

LOUISVILLE GAS AND ELECTRIC COMPANY

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

(Thousands of $)

		2004			2003			2002			2001			2000
Earnings:
Net Income		$	95,618		$	90,839		$	88,929		$	106,781		$	110,573
Add:
Federal income taxes - current		33,850			25,768			24,564			41,127			30,425
State income taxes - current		13,008			10,003			7,653			8,185			4,450
Deferred Federal income taxes - net		11,384			16,793			20,258			12,595			24,233
Deferred State income taxes - net		(795		)	1,716			4,357			3,840			6,787
Investment tax credit - net		(4,153		)	(4,207		)	(4,153		)	(4,290		)	(4,274		)
Fixed charges		33,732			31,378			30,551			38,755			46,438
Earnings		182,644			172,290			172,159			206,993			218,632
Fixed Charges:
Interest Charges per statements of income		32,787			30,647			29,805			37,922			43,218
Add:
One-third of rentals charged to operating expense (1)		945			731			746			833			3,220
Fixed charges		$	33,732		$	31,378		$	30,551		$	38,755		$	46,438
Ratio of Earnings to Fixed Charges		5.41			5.49			5.64			5.34			4.71
NOTE:
(1)	In the Company’s opinion, one-third of rentals represents a reasonable approximation of the interest factor.
	Rents	2,834			2,192			2,237			2,500			9,660
		945			731			746			833			3,220

EX-21

Exhibit 21

SUBSIDIARIES OF THE REGISTRANTS

At December 31, 2004:

Louisville Gas and Electric Company, a Kentucky corporation, has no applicable subsidiaries.

Kentucky Utilities Company, a Kentucky and Virginia corporation (“KU”), has no applicable subsidiaries.  (KU does own 100% of the shares of Lexington Utilities Company, a Kentucky corporation, which entity is inactive.)

EX-24.

Exhibit 24

POWER OF ATTORNEY

WHEREAS, KENTUCKY UTILITIES COMPANY, a Kentucky corporation, is to file with the Securities and Exchange Commission, under the provisions of the Securities Exchange Act of 1934, as amended, its Annual Report on Form 10-K for the year ended December 31, 2004 (the 2004 Form 10-K); and

WHEREAS, each of the undersigned holds the office or offices in KENTUCKY UTILITIES COMPANY set opposite his name;

NOW, THEREFORE, each of the undersigned hereby constitutes and appoints JOHN R. McCALL, and S. BRADFORD RIVES, and each of them, individually, his attorney, with full power to act for him and in his name, place, and stead, to sign his name in the capacity or capacities set forth below to the 2004 Form 10-K and to any and all amendments to such 2004 Form 10-K and hereby ratifies and confirms all that said attorney may or shall lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned have hereunto set their hands and seals as of this 24th day of March, 2005.

/s/ Victor A. Staffieri	/s/ John R. McCall
VICTOR A. STAFFIERI	JOHN R. McCALL
Chairman, President and Chief	Executive Vice President, General Counsel
Executive Officer	and Corporate Secretary
(Principal Executive Officer)	Director
/s/ S. Bradford Rives	/s/ Chris Hermann
S. BRADFORD RIVES	CHRIS HERMANN
Chief Financial Officer and Director	Senior Vice President – Energy Delivery and
	Director
/s/ Paul. W. Thompson
PAUL W. THOMPSON
Senior Vice President – Energy Services and
Director

POWER OF ATTORNEY

WHEREAS, LOUISVILLE GAS AND ELECTRIC COMPANY, a Kentucky corporation, is to file with the Securities and Exchange Commission, under the provisions of the Securities Exchange Act of 1934, as amended, its Annual Report on Form 10-K for the year ended December 31, 2004 (the 2004 Form 10-K); and

WHEREAS, each of the undersigned holds the office or offices in LOUISVILLE GAS AND ELECTRIC COMPANY set opposite his name;

NOW, THEREFORE, each of the undersigned hereby constitutes and appoints JOHN R. MCCALL and S. BRADFORD RIVES, and each of them, individually, his attorney, with full power to act for him and in his name, place, and stead, to sign his name in the capacity or capacities set forth below to the 2004 Form 10-K and to any and all amendments to such 2004 Form 10-K and hereby ratifies and confirms all that said attorney may or shall lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned have hereunto set their hands and seals as of this 24th day of March, 2005.

/s/ Victor A. Staffieri	/s/ John R. McCall
VICTOR A. STAFFIERI	JOHN R. McCALL
Chairman, President and Chief	Executive Vice President, General Counsel
Executive Officer	and Corporate Secretary
(Principal Executive Officer)	Director
/s/ S. Bradford Rives	/s/ Chris Hermann
S. BRADFORD RIVES	CHRIS HERMANN
Chief Financial Officer and Director	Senior Vice President – Energy Delivery and
	Director
/s/ Paul. W. Thompson
PAUL W. THOMPSON
Senior Vice President – Energy Services and
Director

EX-31.1

Exhibit 31.1

CERTIFICATIONS

Louisville Gas and Electric Company

I, Victor A. Staffieri, Chairman of the Board, President and Chief Executive Officer, certify that:

1. I have reviewed this annual report on Form 10-K of Louisville Gas and Electric Company;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

c) disclosed in this annual report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting;

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 30, 2005

/s/ Victor A. Staffieri

Victor A. Staffieri

Chairman of the Board, President and Chief Executive Officer

EX-31.2

Exhibit 31.2

Louisville Gas and Electric Company

I, S. Bradford Rives, Chief Financial Officer, certify that:

1. I have reviewed this annual report on Form 10-K of Louisville Gas and Electric Company;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

c) disclosed in this annual report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting;

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  March 30, 2005

/s/ S. Bradford Rives

S. Bradford Rives

Chief Financial Officer

EX-31.3

Exhibit 31.3

Kentucky Utilities Company

I, Victor A. Staffieri, Chairman of the Board, President and Chief Executive Officer, certify that:

1. I have reviewed this annual report on Form 10-K of Kentucky Utilities Company;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

c) disclosed in this annual report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting;

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

March 30, 2005

/s/ Victor A. Staffieri

Victor A. Staffieri

Chairman of the Board, President and Chief Executive Officer

EX-31.4

Exhibit 31.4

Kentucky Utilities Company

I, S. Bradford Rives, Chief Financial Officer, certify that:

1. I have reviewed this annual report on Form 10-K of Kentucky Utilities Company;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

c) disclosed in this annual report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting;

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 30, 2005

/s/ S. Bradford Rives

S. Bradford Rives

Chief Financial Officer

EX-32

Exhibit 32

Certification Pursuant to 18 U.S.C. Section 1350

As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Annual Report of Louisville Gas and Electric Company and Kentucky Utilities Company (the “Companies”) on Form 10-K for th e year ended December 31, 2004, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned does hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer’s knowledge,

1)     The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2)     The information contained in the Report fairly presents, in all material respect s, the financial condition and results of operations of the Companies as of the dates and for the periods expressed in the Report.

March 30, 2005
	/s/ Victor A. Staffieri
Chairman of the Board, President
and Chief Executive Officer
Louisville Gas and Electric Company
Kentucky Utilities Company
	/s/ S. Bradford Rives
Chief Financial Officer
Louisville Gas and Electric Company
Kentucky Utilities Company

The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document.

EX-99.01

Exhibit 99.01

Cautionary Factors for Louisville Gas and Electric Company and Kentucky Utilities Company

The Private Securities Litigation Reform Act of 1995 provides a “safe harbor” for forward-looking statements to encourage such disclosures without the threat of litigation providing those statements are identified as forward-looking and are accompanied by meaningful, cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement. Forward-looking statements have been and will be made in written documents and oral presentations of E.ON AG (“E.ON”),  LG&E Energy LLC (“LG&E Energy”), Louisville Gas and Electric Company (“LG&E”) and Kentucky Utilities Company (“KU”) (the latter entities, LG&E and KU, collectively, the “Companies”). Such statements are based on management’s beliefs as well as assumptions made by and information currently available to management. When used in the Companies’ documents or oral presentations, the words “anticipate,” “estimate,” “expect,” “objective” and similar expressions are intended to identify forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause the Companies’ actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:

•Increased competition in the utility, natural gas and electric power marketing industries, including effects of: decreasing margins as a result of competitive pressures; industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of investments made under traditional regulation; nature of competitors entering the industry; retail wheeling; a new pricing structure; and former customers entering the generation market;

•Changing market conditions and a variety of other factors associated with physical energy and financial trading activities including, but not limited to, price, basis, credit, liquidity, volatility, capacity, transmission, currency, interest rate and warranty risks;

•Risks associated with price risk management strategies intended to mitigate exposure to adverse movement in the prices of electricity and natural gas on both a global and regional basis;

•Legal, regulatory, public policy-related and other developments which may result in re-determination, adjustment or cancellation of revenue payment streams paid to, or increased capital expenditures or operating and maintenance costs incurred by, the Companies, in connection with rate, fuel, transmission, environmental, consumer choice, safety and security and other proceedings or rules applicable to the Companies;

•Legal, regulatory, economic and other factors which may result in re-determination or cancellation of revenue payment streams under power sales agreements resulting in reduced operating income and potential asset impairment related to the Companies’ investments in independent power production ventures, as applicable;

•Economic conditions including interest rates, inflation rates and monetary or currency fluctuations;

•Trade, monetary, fiscal, taxation, and environmental policies of governments, agencies and similar organizations in geographic areas where the Companies have a financial interest;

•Customer business conditions including demand for their products or services and supply of labor and materials used in creating their products and services;

•Financial or regulatory accounting principles or policies imposed by the Public Company Accounting Oversight Board, Financial Accounting Standards Board, the Securities and Exchange Commission, the Federal Energy Regulatory Commission, state public utility commissions, state entities which regulate natural gas transmission, gathering and processing and similar entities with regulatory oversight;

•Availability or cost of capital such as changes in: interest rates, market perceptions of the utility and energy-related industries, the Companies or any of their subsidiaries or security ratings;

•Factors affecting utility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, unusual maintenance or repairs; unanticipated changes to fossil fuel, or gas supply costs or availability due to higher demand, shortages, transportation problems or other developments; environmental incidents; or electric transmission or gas pipeline system constraints;

•Factors which may affect the Companies’ utility operations or the demand for the Companies’ electric power or gas such as natural disasters, wars, terrorist acts or the effects thereof (including increased security costs), embargoes and other catastrophic events;

•Employee workforce factors including changes in key executives, collective bargaining agreements with union employees, or work stoppages;

•Rate-setting policies or procedures of regulatory entities, including environmental externalities;

•Social attitudes regarding the utility, natural gas and power industries;

•Identification of suitable investment opportunities to enhance shareholder returns and achieve long-term financial objectives through business acquisitions;

•Some future project investments made by the Companies, respectively, as applicable, could take the form of minority interests, which would limit the Companies’ ability to control the development or operation of the project;

•Legal and regulatory delays and other unforeseeable obstacles associated with mergers, acquisitions and investments in joint ventures;

•The resolution, costs and other effects of legal and administrative proceedings, settlements, investigations, claims and matters, including but not limited to those described in Notes 3, 11 and 17 (for LG&E) and Notes 3, 11 and 16 (for KU) of the respective Notes to Financial Statements of the Companies’ Annual Reports on Form 10-K for the year ended December 31, 2004, and items under the caption Item 3, Legal Proceedings;

•Technological developments, changing markets and other factors that result in competitive disadvantages and create the potential for impairment of existing assets;

•Other business or investment considerations that may be disclosed from time to time in the Companies’ Securities and Exchange Commission filings or in other publicly disseminated written documents;

•Factors affecting the realization of anticipated cost savings associated with the merger between LG&E Energy and KU Energy Corporation including national and regional economic conditions, national and regional competitive conditions, inflation rates, weather conditions, financial market conditions, and synergies resulting from the business combination;

•Factors associated with, resulting from or affecting the acquisition and operation of LG&E Energy by E.ON, including the integration of the existing business and operations of LG&E and KU as part of the E.ON group of companies thereunder, as well as national and international economic, financial market, regulatory and industry conditions or environments applicable to E.ON and its subsidiaries, including LG&E and KU, in the future.

The Companies undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

EX-99.02

Exhibit 99.02

LOUISVILLE GAS AND ELECTRIC COMPANY

AND

KENTUCKY UTILITIES COMPANY

DIRECTOR AND OFFICER INFORMATION

The outstanding stock of Louisville Gas and Electric Company (“LG&E”) is divided into three classes: Common Stock, Preferred Stock (without par value), and Preferred Stock, par value $25 per share. At the close of business on February 28, 2005, the following shares of four series of such classes were outstanding:

Common Stock, without par value	21,294,223 shares
Preferred Stock, par value $25 per share, 5% Series	860,287 shares
Preferred Stock, without par value, $5.875 Series	225,000 shares
Preferred Stock, without par value (stated value $100 per share)
Auction Rate Series A	500,000 shares

The outstanding stock of Kentucky Utilities Company (“KU”) is divided into three classes: Common Stock, without par value, Preferred Stock, without par value, and Preference Stock, without par value. As of the close of business on February 28, 2005, the following shares of three series of such classes were outstanding:

Common Stock, without par value	37,817,878 shares
Preferred Stock, without par value (stated value $100 per share)
4.75% Series	200,000 shares
6.53% Series	200,000 shares

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

As of February 28, 2005, all directors, nominees for director and executive officers of LG&E and KU as a group beneficially owned no shares of LG&E Preferred Stock or KU Preferred Stock and less than 1% of the shares of E.ON AG, the ultimate parent of LG&E and KU.

On December 11, 2000, Powergen plc, a public limited company with registered offices in England and Wales (“Powergen”) completed its acquisition of LG&E Energy Corp., then the parent corporation of LG&E and KU. In connection with such transaction, certain officers and directors of Powergen were appointed to fill vacancies in the Board of Directors of LG&E and KU occurring by resignation of prior directors.  In January 2003, Powergen was reregistered as Powergen Limited.

On July 1, 2002, E.ON AG, a German corporation (“E.ON”), completed the acquisition of Powergen.  In connection with such transaction, certain officers or directors of E.ON and Powergen were appointed to fill vacancies in the Board of Directors of LG&E and KU occurring by resignation of prior directors.

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

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INFORMATION ABOUT DIRECTORS

The number of members of each of the Boards of Directors of LG&E and KU is currently fixed at five, pursuant to the Companies’ bylaws and resolutions adopted by the Boards of Directors. Generally, directors are elected at each year’s Annual Meeting to serve for one-year terms and to continue in office until their successors are elected and qualified.

On January 31, 2004, in connection with reorganizations in reporting relationships among E.ON, Powergen and LG&E Energy in early 2004, Messrs. John R. McCall and S. Bradford Rives were appointed to the Boards of LG&E and KU to fill the vacancies created by resignations of Dr. Hans Michael Gaul and Mr. Michael Söhlke.  Effective January 1, 2005, the size of the Boards was increased to five and Messrs. Paul W. Thompson and Chris Hermann were appointed as directors.

The following contains certain information as of February 28, 2005 concerning the directors of LG&E and KU:

Directors with Terms Expiring at the 2005 Annual Meeting of Shareholders

Victor A. Staffieri (Age 49):    Mr. Staffieri is Chairman, President and Chief Executive Officer of LG&E Energy, LG&E and KU, serving from April 2001 to the present. He served as President and Chief Operating Officer of LG&E Energy, LG&E and KU from February 1999 to April 2001; Chief Financial Officer of LG&E Energy and LG&E from May 1997 to February 2000; Chief Financial Officer of KU from May 1998 to February 2000; President, Distribution Services Division of LG&E Energy from December 1995 to May 1997; and Senior Vice President, General Counsel and Public Policy of LG&E Energy and LG&E from November 1992 to December 1993. Mr. Staffieri has been a director of LG&E Energy, LG&E and KU since April 2001 and was a director of Powergen from April 2001 until January 2004.

John R. McCall  (Age 61):                Mr. McCall is Executive Vice President, General Counsel and Secretary of LG&E Energy and Executive Vice President, General Counsel and Corporate Secretary of LG&E and KU.  Mr. McCall has held these positions at LG&E Energy and LG&E since July 1994 and at KU since May 1998.  Mr. McCall has been a director of LG&E Energy, LG&E and KU since January 2004.

S. Bradford Rives (Age 46):              Mr. Rives is Chief Financial Officer of LG&E Energy, LG&E and KU, serving from September 2003 until the present.  He served as Senior Vice President – Finance and Controller of LG&E Energy, LG&E and KU from December 2000 until September 2003; Senior Vice President – Finance and Business Development of LG&E Energy and LG&E from February 1999 to December 2000; and Vice President – Finance and Controller of LG&E Energy and LG&E from March 1996 to February 1999.  Mr. Rives has been a director of LG&E Energy, LG&E and KU since January 2004.

Paul W. Thompson (Age 48):           Mr. Thompson is Senior Vice President – Energy Services of LG&E Energy, LG&E and KU, serving from June 2000 until the present.  He served as Senior Vice President – Energy Services of LG&E Energy from August 1999 until June 2000; Vice President, Retail Electric Business of LG&E from December 1998 to August 1999; and Group Vice President – Energy Marketing  of LG&E Energy from June 1998 to August 1999.  Mr. Thompson has been a director of LG&E Energy, LG&E and KU since January 2005.

Chris Hermann (Age 57):                  Mr. Hermann is Senior Vice President – Energy Delivery of LG&E Energy, LG&E and KU, serving from February 2003 until the present.  He served as Senior Vice President – Distribution Operations of LG&E Energy, LG&E and KU from December 2000 until February 2003; Vice President, Supply Chain and Operating Services of LG&E Energy and LG&E from December 1999 to December 2000; and Vice President, Power Generation and Engineering Services of  LG&E from May 1998 to December 1999.   Mr. Hermann has been a director of LG&E Energy, LG&E and KU since January 2005.

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INFORMATION CONCERNING THE BOARDS OF DIRECTORS

The Boards of Directors of LG&E and KU contain the same members.  Each member is also a director of LG&E Energy, as described above.

During 2004, there were a total of 11 and 12 meetings or consents of the LG&E and KU Boards, respectively. All directors attended 75% or more of the total number of meetings or consents of the Boards of Directors and committees of the Boards on which they served.

Compensation of Directors

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

Committees

There are currently no formal committees of the Boards of Directors of the Companies.  Due to the small Board size of five members, each Board as a whole performs the functions related to audit or nominating committees.

In July 2002, upon completion of the E.ON-Powergen acquisition, the structures of the LG&E and KU Boards were changed to recognize practical and administrative efficiencies. The LG&E and KU Boards and LG&E Energy Board, respectively, adopted resolutions providing that (i) the functions of the former Audit Committee would be performed by the LG&E and KU Boards as a whole and (ii) certain functions of the former Remuneration Committee under certain LG&E Energy executive compensation plans would be performed by the Senior Vice President – Corporate Executive Human Resources of E.ON AG, currently Dr. Stefan Vogg.

Audit and Auditor Matters

Due to the small size, each Board as a whole performs the functions associated with an Audit Committee.  Each Board has 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 members of the Boards are officers or employees of LG&E or KU and therefore are not independent within the meaning of Item 7(d)(3)(iv) of Schedule 14A of the Securities Exchange Act of 1934.

During 2004, the Boards maintained direct and indirect contact with the independent registered public accounting firm and with LG&E’s and KU’s internal Audit Services to review the following matters pertaining to LG&E and KU:  fees and services relating to the independent auditor; the adequacy of accounting and financial reporting procedures; the adequacy and effectiveness of internal accounting controls; the scope and results of the annual audit and any other matters relative to the audit of the Companies’ accounts and financial affairs that the Board, Audit Services or the independent registered public accounting firm deemed necessary.   A report of the Board acting as Audit Committee is included in the “Report on 2004 Audit Committee Matters” section of this document.  A copy of the charter applicable to the Board acting as Audit Committee is included as Appendix A of this document.

The Board is responsible for approving all audit and permissible non-audit services to be provided by the independent registered public accounting firm in accordance with LG&E’s and KU’s  Pre-Approval Policy.   Under the policy, the Board annually reviews and pre-approves the services that may be provided by the independent registered public accounting firm.   These include audit services, audit-related services, tax services and some permissible non-audit services, up to designated fee or budget levels.  New services or services exceeding these levels will require separate pre-approval by the Board.  Under the policy, the Board may delegate pre-approval authority to one or more of its members, subject to reporting of any decisions by such member to the Board or may rely upon certain annual or other pre-approvals by the E.ON Audit Committee under its policy, subject to certain reporting to the Board.

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 Nominations

Due to the small size of the Boards and the fact that LG&E Energy owns all of LG&E’s and KU’s common stock and approximately 96% of LG&E’s voting stock, the Boards have determined that it is appropriate not to have a standing nominating committee, nominating committee charter or policy regarding consideration of candidates for director, including shareholder nominees.  The full Boards, with input from E.ON officers, select director nominees.  All members of the Boards are officers or employees of LG&E or KU and therefore are not independent within the meaning of Item 7(d)(2)(ii)(D) of Schedule 14A of the Securities Exchange Act of 1934.

Nominations for the election of directors may be made by the Boards, a committee thereof or by shareholders entitled to vote in the election of directors generally.  Shareholder nominations must provide timely written notice in writing to the Companies’ Secretary in accordance with the procedures set forth in the section “Shareholder Proposals and Nominations” of this document.  The Boards’ chairman may void the nomination of any candidate for election which was not made in compliance with applicable procedures.

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COMPENSATION REPORT

Following the July 1, 2002 completion of E.ON’s acquisition of Powergen, the Remuneration Committee of the Boards of Directors of LG&E and KU was terminated.  As stated above, the LG&E Energy, LG&E and KU Boards adopted resolutions providing that certain functions of the former Remuneration Committee under certain executive compensation plans would be performed by the Senior Vice President - Corporate Executive Human Resources of E.ON, currently Dr. Stefan Vogg.  This report describes the compensation policies applicable to the Companies’ executive officers for the last completed fiscal year.

With respect to 2004, Dr. Vogg, in consultation with certain officers of E.ON AG, LG&E Energy, LG&E and KU, including members of the Companies’ Boards of Directors (collectively, the “Compensation Group”), arrived at decisions regarding the compensation of LG&E’s and KU’s executive officers, including the setting of base pay levels for 2004, and the administration and determination of awards under the E.ON Group Stock Option Program (the “E.ON SAR Plan”) and the LG&E Energy Corp. Performance Unit Plan (the “Long-Term Plan”) and of payments under the Short-Term Incentive Plan (the “Short-Term Plan”) as applicable to LG&E and KU.

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

Set forth below is a report addressing LG&E’s and KU’s compensation policies during 2004 for their officers, including the executive officers named in the following tables. In many cases, the executive officers also serve in similar capacities for affiliates of LG&E and KU, including LG&E Energy. For each of the executive officers of LG&E and KU, the policies and amounts discussed below are for all services to LG&E, KU and their affiliates, during the relevant period.

Compensation Philosophy

During 2004, LG&E’s and KU’s executive compensation program had three major components: (1) base salary; (2) short-term; and (3) long-term incentives. The Companies developed their executive compensation program to focus on both short-term and long-term business objectives that are designed to enhance overall shareholder value. The short-term and long-term incentives were premised on the belief that the interests of executives should be closely aligned with those of shareholders. Based on this philosophy, these two portions of each executive’s total compensation package were linked to the accomplishment of specific results that were designed to benefit shareholders in both the short-term and long-term.

The executive compensation program also recognized that compensation practices must be competitive not only with utilities and utility holding companies, but also with companies in general industry to ensure that a stable and successful management team can be recruited and retained.

Pursuant to this competitive market positioning philosophy, in establishing compensation levels for all executive positions for 2004, the Compensation Group reviewed competitive compensation information for United States general industry companies with revenue of approximately $3 billion (the “Survey Group”) and established targeted total direct compensation (base salary plus short-term incentives and long-term incentives) for each executive for 2004 to generally approach the 50th percentile of the competitive range from the Survey Group.  Salaries, short-term incentives and long-term incentives for 2004 are described below.  (The utilities and utility holding companies that were in the Survey Group were not necessarily the same as those in the Dow Jones Utility Average used in a company performance graph in any proxy statement.)

The 2004 compensation information set forth in other sections of this document, particularly with respect to the tabular information presented, reflects the considerations set forth in this report. The Base Salary, Short-Term

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Incentives, and Long-Term Incentives sections that follow address the compensation philosophy for 2004 for all executive officers except those serving as Chief Executive Officer.   The compensation of the Chief Executive Officer is discussed below under the heading “Chief Executive Officer Compensation.”

Base Salary

The base salaries for LG&E and KU executive officers for 2004 were designed to be competitive with the Survey Group at approximately the 50th percentile of the base salary range for executives in similar positions with companies in the Survey Group. Actual base salaries were determined based on a combination of market position, individual performance and experience.

Short-Term Incentives

The Short-Term Plan provided for Company Performance Awards and Individual Performance Awards, each of which is expressed as a percentage of base salary and each of which is determined independent of the other. The Compensation Group established the performance goals for the Company Performance Awards and Individual Performance Awards at the beginning of the 2004 performance year. Payment of Company Performance Awards for executive officers was based on varying performance measures tied to each officer’s responsible areas. These measures and goals included, among others, LG&E Energy earnings before interest and taxes (“EBIT”) targets and LG&E/KU EBIT targets.  The Compensation Group retains discretion to adjust the measures and goals as deemed appropriate. Payment of Individual Performance Awards was based 100% on management effectiveness. As stated, the awards varied within the executive officer group based upon the nature of each individual’s functional responsibilities.

For 2004, the Company Performance Award targets for named executive officers were 30% of base salary, and the Individual Performance Award targets were 20% of base salary. Both awards were established to be competitive with the 50th percentile of such awards granted to comparable executives employed by companies in the Survey Group. The individual officers were eligible to receive from 0% to 175% of their targeted Company Performance Award amounts, dependent upon Company performance as measured by the relevant performance goals, and were eligible to receive from 0% to 175% of their targeted Individual Performance Award amounts dependent upon individual performance as measured by management effectiveness.

Using the relevant E.ON, LG&E Energy, LG&E/KU and other subsidiaries’ performance against goals in 2004, the Compensation Group determined relative annual performance against targets for Company Performance Awards. Based upon this determination, Company Performance Awards for 2004 to the named executive officers were paid ranging from 118% to 131% of target and 36% to 39% of base salary. Based on determinations of management effectiveness, payouts for Individual Performance Awards to the named executive officers ranged from 150% to 165% of target and 32% to 71% of base salary.

Long-Term Incentives

The Compensation Group determines the competitive long-term grants under the Long-Term Plan and the E.ON SAR Plan to be awarded for each executive based on the long-term awards for the 50th percentile of the Survey Group. The aggregate expected value of the awards is intended to approach the expected value of long-term incentives payable to executives in similar positions with companies in the 50th percentile of the Survey Group, depending upon achievement of targeted Company performance.

In 2004, the Compensation Group granted performance units under the Long-Term Plan to executive officers and senior management and stock appreciation rights (“SAR’s”) under the E.ON SAR Plan to executive officers.  The amounts of the executive’s long-term award to be delivered in SAR’s and performance units were 25% and 75% respectively.  Under the Long-Term Plan, the future value of grants of performance units is dependent upon company performance against a value-added target.  The ultimate value of the performance unit can range from 0% to 150% of grant. Under the E.ON SAR Plan, the amount paid to executives when they exercise their SAR’s, after satisfaction of vesting and performance criteria, is the difference between E.ON’s stock price at the time of exercise and the stock price at the time of issuance, multiplied by the number of SAR’s exercised multiplied by the foreign exchange rate at the time of grant.  The price at issuance is the average of the XETRA closing quotations for E.ON stock during the December prior to issuance.  The future value of the 2004 grants

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of SAR’s was substantially dependent upon the changing value of E.ON shares in the marketplace.

SAR’s are subject to two year vesting and performance requirements.  No regular payouts of performance units under the Long-Term Plan occurred during 2004 as the three-year performance periods had not been completed.

Chief Executive Officer Compensation

Mr. Victor A. Staffieri was appointed Chief Executive Officer of LG&E and KU effective May 1, 2001. Mr. Staffieri’s compensation was governed by the terms of an Employment and Severance Agreement entered into on February 25, 2000 as amended (including upon his appointment as Chief Executive Officer) (the “2000 Agreement”). The 2000 Agreement was for an initial term of two years commencing on December 11, 2000, with automatic annual extensions thereafter unless E.ON orthe Companies or Mr. Staffieri give notice of non-renewal.  During 2004, Mr. Staffieri entered into an amendment to his employment and severance agreement.

The 2000 Agreement established the minimum levels of Mr. Staffieri’s base compensation, although the Chairman of E.ON retains discretion to increase such compensation. For 2004, the Compensation Group established Mr. Staffieri’s compensation and short-term and long-term awards using comparisons to relevant officers of companies in the Survey Group, including utilities, and survey data from various compensation consulting firms. Mr. Staffieri also received Company contributions to the savings plan, similar to those of other officers and employees. Details of Mr. Staffieri’s 2004 compensation are set forth below.

Base Salary.      Mr. Staffieri was paid a total base salary of $673,236 during 2004, pursuant to the 2000 Agreement, as amended. The Compensation Group, in determining Mr. Staffieri’s 2004 annual salary, including the minimum, considered his individual performance in the prior growth of LG&E Energy and the comparative compensation data described above.

Short-Term Incentives.      Mr. Staffieri’s short-term incentive target award as Chief Executive Officer was 70% of his 2004 base salary. As with other executive officers receiving short-term incentive awards, Mr. Staffieri was eligible to receive more or less than the targeted amount, based on Company performance and individual performance. His 2004 short-term incentive payouts were based 40% on achievement of Company Performance Award targets and 60% on achievement of Individual Performance Award targets.

For 2004, the Company Performance Award payout for Mr. Staffieri was 131% of target and 37% of his 2004 base salary and the Individual Performance Award payout was 170% of target and 71% of his 2004 base salary.  Mr. Staffieri’s Company Performance Award was based on LG&E Energy EBIT.  His Company Performance Award was calculated based upon annual Company performance as described under the heading “Short-Term Incentives.”  In determining the Individual Performance Award, the Compensation Group considered Mr. Staffieri’s effectiveness in several areas, including the financial and operational performance of LG&E Energy, LG&E, KU and other subsidiaries, Company growth and other measures.

Long-Term Incentive Grant.      In 2004, Mr. Staffieri received 883,619 performance units for the 2004-2006 performance period under the Long-Term Plan and 24,778 SAR’s under the E.ON SAR Plan. These amounts were determined pursuant to the terms of his 2000 Agreement, as amended, with an aggregate expected value representing approximately 175% of his base salary. The terms of the performance units and SAR’s for Mr. Staffieri are the same as for other executive officers, as described under the heading “Long-Term Incentives.”

Long-Term Incentive Payout.       Mr. Staffieri exercised SAR’s during 2004 as indicated in the “Option/SAR Exercises and Year-End Value Table.”  As with other executive officers, no regular payouts of performance units under the Long-Term Plan occurred during 2004 as the three-year performance periods had not been completed.

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Other.     In 2004, Mr. Staffieri also received a retention payment in connection with a 2002 amendment to his employment and severance agreement in the amount of $872,032, including interest, as indicated in the Summary Compensation Table.

Members of the Companies’ Boards of Directors

Victor A. Staffieri

John R. McCall

S. Bradford Rives

Paul W. Thompson

Chris Hermann

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EXECUTIVE COMPENSATION AND OTHER INFORMATION

The following table shows the cash compensation paid or to be paid by LG&E, KU or LG&E Energy, as well as certain other compensation paid or accrued for those years, to the Chief Executive Officer and the next four highest compensated executive officers of LG&E and KU who were serving as such at December 31, 2004, as required, in all capacities in which they served LG&E, KU, LG&E Energy or its subsidiaries during 2002, 2003 and 2004:

SUMMARY COMPENSATION TABLE

	Annual Compensation					Long-Term Compensation
						Awards	Payouts
Name and Principal Position				Other Annual Comp. ($)		Restricted Stock Awards ($)	Securities Underlying Options/SAR (#)(1)	LTIP Payouts ($)(2)	All Other CompenSation ($)
	Year	Salary ($)	Bonus ($)
Victor A. Staffieri	2004	673,236	728,159	31,572		—	24,778	0	941,069	(3)
Chairman of the Board,	2003	648,902	741,340	39,461		—	25,282	0	902,945	(4)
President and Chief Executive	2002	630,001	650,101	24,282		—	6,250	1,483,377	2,433,735	(5)
Officer
John R. McCall	2004	408,949	296,015	9,365		—	8,600	0	670,532	(3)
Executive Vice President,	2003	389,475	313,933	198,681	(6)	—	8,671	0	47,529	(4)
General Counsel and	2002	363,975	251,543	144,756	(6)	—	3,611	401,580	1,390,557	(5)
Corporate Secretary
S. Bradford Rives	2004	332,001	230,355	7,293		—	5,586	0	517,626	(3)
Chief Financial Officer	2003	305,495	243,607	6,880		—	5,345	0	423,923	(4)
	2002	280,019	180,145	6,616		—	2,877	204,450	486,491	(5)
Paul W. Thompson	2004	286,258	209,048	8,273		—	4,697	0	435,220	(3)
Senior Vice President -	2003	269,071	187,526	7,232		—	4,792	0	10,151	(4)
Energy Services	2002	262,497	147,944	8,106		—	2,604	290,000	440,486	(5)
Chris Hermann	2004	262,412	179,732	7,891		—	3,311	0	416,884	(3)
Senior Vice President -	2003	252,928	166,267	4,905		—	3,378	0	22,463	(4)
Energy Delivery	2002	246,748	129,505	7,892		—	2,448	204,450	228,722	(5)

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(1)Amounts for all years reflect E.ON SAR Plan grants.

(2)No regular payout were made under the Long-Term Plan were made during years 2004, 2003 or 2002 as no three-year performance periods had yet been completed.  Amounts for year 2002, reflect acceleration of open performance periods upon the change in control event resulting from the Powergen shareholders’ approval of the E.ON transaction.

(3)Includes employer contributions to 401(k) plan, nonqualified thrift plan, employer paid life insurance premiums, vacation sell back and retention payments in 2004 as follows: Mr. Staffieri $6,500, $35,937, $26,600, $0 and $872,032, respectively; Mr. McCall $6,095, $15,662, $22,050, $2,359 and $613,425,  respectively; Mr. Rives $1,571, $15,736, $1,042, $1,277 and $498,000, respectively; Mr. Thompson, $4,353, $9,861, $2,259. $0 and $418,747, respectively and Mr. Hermann, $6,228, $6,754, $6,250, $4,037 and $393,615, respectively.  Mr. McCall’s figure also includes $10,941 representing certain overseas assignment and tax equalization amounts.  The retention payments above are discussed in the “Compensation Report” and “Employment Contracts and Termination of Employment Arrangements and Change in Control Provisions”.

(4)Includes retention payments in 2003 as follows: Mr. Staffieri, $837,375; Mr. McCall, $0; Mr. Rives, $403,556; Mr. Thompson, $0; and Mr. Hermann, $0, respectively.

(5)Includes retention payments in 2002 as follows: Mr. Staffieri, $2,349,170; Mr. McCall, $1,346,416; Mr. Rives, $87,746; Mr. Thompson, $425,926; and Mr. Hermann, $211,342, respectively.

(6)Includes financial planning, automobile, spouse travel, dues, overseas compensation and tax payments in 2003 ($1,500, $4,000, $7,202, $0, $0 and $178,445) and 2002 ($2,000, $7,586, $50,589, $240, $36,398 and $48,143) respectively.

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OPTION/SAR GRANTS TABLE

Option/SAR Grants in 2004 Fiscal Year

The following table contains information at December 31, 2004, with respect to grants of E.ON AG stock appreciation rights (SAR’s) to the named executive officers:

	Individual Grants					Potential
Name	Number of Securities Underlying Options/SARs Granted (#) (1)	Percent of Total Options/SARs Granted to Employees in Fiscal Year (2)		Exercise Or Base Price ($/ Share)	Expiration Date	Realizable Value At Assumed Annual Rates of Stock Price Appreciation For Option Term		10%($)
						0%($)	5% ($)
Victor A. Staffieri	24,778	39.1	%	61.76	12/31/2010	0	622,981	1,451,812
John R. McCall	8,600	13.6	%	61.76	12/31/2010	0	216,226	503,898
S. Bradford Rives	5,586	8.8	%	61.76	12/31/2010	0	140,446	327,299
Paul W. Thompson	4,697	7.4	%	61.76	12/31/2010	0	118,094	275,210
Chris Hermann	3,311	5.2	%	61.76	12/31/2010	0	83,247	194,001

(1)E.ON SAR’s were awarded with an exercise price at issuance equal to the average XETRA closing quotations for E.ON stock during the December prior to issuance.  The SAR’s are exercisable over a seven-year period from their issuance date.

(2)Represents percentage grants to LG&E Energy, LG&E and KU officers only.

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OPTION/SAR EXERCISES AND YEAR-END VALUE TABLE

Aggregated Option/SAR Exercises in 2004 Fiscal Year

And FY-End Option/SAR Values

The following table sets forth information with respect to the named executive officers concerning the value of unexercised E.ON SAR’s held by them as of December 31, 2004:

Name	Shares Acquired On Exercise (#)(1)	Value Realized ($)	Number of Securities Underlying Unexercised Options/SARs at FY-End (#) Exercisable/Unexercisable	Value of Unexercised In-The-Money Options/SARs at FY-End ($) Exercisable/Unexercisable
Victor A. Staffieri	6,250	51,969	0 / 50,060	0 / 1,913,016
John R. McCall	3,611	30,025	0 / 17,271	0 / 659,088
S. Bradford Rives	2,877	23,922	0 / 10,931	0 / 414,603
Paul W. Thompson	0	0	2,604 / 9,489	107,649 / 362,612
Chris Hermann	0	0	2,448 / 6,689	101,200 / 255,613

(1)           Amounts shown are E.ON SAR’s.

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LONG-TERM INCENTIVE PLAN AWARDS TABLE

Long-Term Incentive Plan Awards in 2004 Fiscal Year

The following table provides information concerning awards of performance units made in fiscal year 2004 to the named executive officers under the Long-Term Plan.

Name	Number of Shares, Units or Other Rights	Performance or Other Period Until Maturation Or Payout	Estimated Future Payouts under Non-Stock Price Based Plans (number of units)
			Threshold(#)	Target(#)	Maximum(#)
Victor A. Staffieri	883,619	12/31/2006	441,810	883,619	1,325,429
John R. McCall	306,712	12/31/2006	153,356	306,712	460,068
S. Bradford Rives	199,200	12/31//2006	99,600	199,200	298,800
Paul W. Thompson	167,499	12/31/2006	83,750	167,499	251,249
Chris Hermann	118,084	12/31/2006	59,042	118,084	177,126

Each performance unit awarded under the Long-Term Plan represented the right to receive an amount payable in cash on the date of payout. The amount of the payout is determined by company performance over a three-year cycle. For awards made in 2004, the Long-Term Plan awards were intended to reward executives on a three-year rolling basis dependent upon the achievement of a value-added target by LG&E Energy.

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Pension Plans

The following table shows the estimated pension benefits payable to a covered participant at normal retirement age under LG&E Energy’s qualified defined benefit pension plans, as well as non-qualified supplemental pension plans that provide benefits that would otherwise be denied participants by reason of certain Internal Revenue Code limitations for qualified plan benefits, based on the remuneration that is covered under the plan and years of service with LG&E Energy and its subsidiaries:

2004 PENSION PLAN TABLE

		Years of Service
Remuneration		15		20		25		30 or more
$	100,000	$	42,592	$	42,592	$	42,592	$	42,592
$	200,000	$	106,592	$	106,592	$	106,592	$	106,592
$	300,000	$	170,592	$	170,592	$	170,592	$	170,592
$	400,000	$	234,592	$	234,592	$	234,592	$	234,592
$	500,000	$	298,592	$	298,592	$	298,592	$	298,592
$	600,000	$	362,592	$	362,592	$	362,592	$	362,592
$	700,000	$	426,592	$	426,592	$	426,592	$	426,592
$	800,000	$	490,592	$	490,592	$	490,592	$	490,592
$	900,000	$	554,592	$	554,592	$	554,592	$	554,592
$	1,000,000	$	618,592	$	618,592	$	618,592	$	618,592
$	1,100,000	$	682,592	$	682,592	$	682,592	$	682,592
$	1,200,000	$	746,592	$	746,592	$	746,592	$	746,592
$	1,300,000	$	810,592	$	810,592	$	810,592	$	810,592
$	1,400,000	$	874,592	$	874,592	$	874,592	$	874,592
$	1,500,000	$	938,592	$	938,592	$	938,592	$	938,592
$	1,600,000	$	1,002,592	$	1,002,592	$	1,002,592	$	1,002,592
$	1,700,000	$	1,066,592	$	1,066,592	$	1,066,592	$	1,066,592
$	1,800,000	$	1,130,592	$	1,130,592	$	1,130,592	$	1,130,592
$	1,900,000	$	1,194,592	$	1,194,592	$	1,194,592	$	1,194,592

A participant’s remuneration covered by the Retirement Income Plan (the “Retirement Income Plan”) is his or her average base salary and short-term incentive payment (as reported in the Summary Compensation Table) for the five calendar plan years during the last ten years of the participant’s career for which such average is the highest. The years of service for each named executive employed by LG&E Energy at December 31, 2004 were as follows:  12 years for Mr. Staffieri; 10 years for Mr. McCall; 21 years for Mr. Rives; 13 years for Mr. Thompson; and 34 years for Mr. Hermann. Benefits shown are computed as a straight life single annuity beginning at age 65.

Current Federal law prohibits paying benefits under the Retirement Income Plan in excess of $165,000 per year. Officers of LG&E Energy, LG&E and KU with at least one year of service with any company are eligible to participate in LG&E Energy’s Supplemental Executive Retirement Plan (the “Supplemental Executive Retirement Plan”), which is an unfunded supplemental plan that is not subject to the $165,000 limit. Presently, participants in the Supplemental Executive Retirement Plan consist of all of the eligible officers of LG&E Energy, LG&E and KU. This plan provides generally for retirement benefits equal to 64% of average current earnings during the highest 36 consecutive months prior to retirement, reduced by Social Security benefits, by amounts received under the Retirement Income Plan and by benefits from other employers. As with all other officers, Mr. Staffieri participates in the Supplemental Executive Retirement Plan described above.

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Estimated annual benefits to be received under the Retirement Income Plan and the Supplemental Executive Retirement Plan upon normal retirement at age 65 and after deduction of Social Security benefits will be $803,702 for Mr. Staffieri; $375,678 for Mr. McCall; $294,765 for Mr. Rives; $254,564 for Mr. Thompson; and $231,544 for Mr. Hermann.

EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT

ARRANGEMENTS AND CHANGE IN CONTROL PROVISIONS

In connection with the E.ON-Powergen merger, Messrs. Staffieri and McCall entered into amendments to their  employment and severance agreements and Mr. Staffieri entered into a further amendment in early 2004.  The original agreements, effective upon the LG&E Energy-Powergen merger for two year terms, contained change in control provisions and the benefits described below.  Pursuant to the amended agreements, Mr. Staffieri received certain retention payments during 2003 and 2004 described in the Compensation Report and the Summary Compensation Table.

Under the terms of his revised employment and severance agreement, Mr. Staffieri was entitled to additional retentions payment of $800,570, plus interest, on each of July 1, 2004 and January 1, 2005 (the two year and thirty month anniversaries of the E.ON-Powergen merger), which was initially to be credited into a deferred compensation account and which was then payable in a lump sum in cash.  If during the term of his agreement, which is automatically extended for subsequent one year terms unless terminated upon 90 days notice, and within twenty four months following a change in control, Mr. Staffieri’s employment is terminated for reasons other than cause, disability or death, or for good reason, Mr. Staffieri shall be entitled to a severance amount equal to 2.99 times the sum of (1) his annual base salary and (2) his bonus or “target” award paid or payable.  If during the term of his agreement but prior to a change in control, Mr. Staffieri’s employment is terminated for reasons other than cause, disability or death, or for good reason, Mr. Staffieri will be entitled an amount equal to two times his annual base salary and target annual bonus.

Under the terms of his revised employment and severance agreement, on July 1, 2004, Mr. McCall received a lump sum cash payment equal to his annual salary plus target annual bonus.  If during the term of his agreement, which is automatically extended for subsequent one year terms unless terminated upon 90 days notice, and within twenty four months following a change in control or within forty-eight months of the E.ON-Powergen merger, Mr. McCall’s employment is terminated for reasons other than cause, disability or death, or for good reason, Mr. McCall shall be entitled to a severance amount equal to 2.99 times the sum of (1) his annual base salary and (2) his bonus or “target” award paid or payable, or, if within 48 months of the date of the E.ON-Powergen merger, 2.99 times the sum of (1) and (2).

During 2002, in connection with the E.ON-Powergen merger, Messrs. Thompson, Rives and Hermann entered into new retention agreements under which these officers were entitled to a payment equal to the sum of (1) his annual base salary and (2) his annual bonus or “target” award, in the event of their continued employment through the second anniversary of the E.ON-Powergen merger.  During 2001, Messrs. Thompson, Rives and Hermann also entered into change of control agreements with terms of 24 months, with automatic one year renewals if not terminated, which provide that, in the event of termination of employment for reasons other than cause, disability or death, or for good reason within the 24 months following a change in control, these officers shall be entitled to a severance amount equal to 2.99 times the sum of (1) his annual base salary and (2) his bonus or “target” award paid or payable.

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

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EQUITY COMPENSATION PLAN INFORMATION

The executive officers of LG&E and KU do not participate in any compensation plans under which equity securities of LG&E, KU or any affiliate are authorized for issuance.

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Report on 2004 Audit Committee Matters

The Boards of Directors, consisting of five members, performed the functions of the Audit Committee (“Audit Committee”). The Audit Committee is governed by a charter adopted by the Board of Directors, which sets forth the responsibilities of the Audit Committee members.  The Audit Committee held four meetings during 2004.

The financial statements of Louisville Gas and Electric Company and Subsidiary and of Kentucky Utilities Company and Subsidiary are prepared by management, which is responsible for their objectivity and integrity.  With respect to the financial statements for the calendar year ended December 31, 2004, the Audit Committee reviewed and discussed the audited financial statements and the quality of the financial reporting with management and the independent registered public accounting firm.  It also discussed with the independent registered public accounting firm the matters required to be discussed by Statement on Auditing Standards No. 61, Communication with Audit Committees, as amended, and received and discussed with the independent registered public accounting firm the matters in the written disclosures required by Independence Standards Board Standard No. 1, Independence Discussions with Audit Committees.

Based upon the reviews and discussions referred to above, the Audit Committee recommended to the Board of Directors the inclusion of the audited financial statements in Louisville Gas and Electric Company’s and Kentucky Utilities Company’s Annual Report on Form 10-K for the year ended December 31, 2004, for filing with the Securities and Exchange Commission.

The following information on independent audit fees and services is being provided in compliance with the Securities and Exchange Commission rules on auditor independence.

1.  PricewaterhouseCoopers LLP fees for the periods ended December 31, 2004 and December 31, 2003 are as follows:  (Certain amounts for 2003 have been reclassified to conform to 2004 presentation.)

	LG&E				KU
	2004		2003		2004		2003
Audit Fees
Audit Fees	$	188,333	$	128,862	$	188,333	$	128,862
Internal Controls	$	16,667	$	—	$	16,667	$	—
Comfort Letter Procedures	$	—	$	51,154	$	34,360	$	—
Regulatory Work	$	—	$	4,665	$	—	$	4,665
Total Audit Fees	$	205,000	$	182,681	$	239,360	$	133,527
Audit-Related Fees
Pension Plan Audits	$	36,667	$	17,200	$	36,667	$	9,000
Total Audit-Related Fees	$	36,667	$	17,200	$	36,667	$	9,000
Tax Fees
Sales Tax Services	$	11,200	$	—	$	4,480	$	—
Total Tax Fees	$	11,200	$	—	$	4,480	$	—
All Other Fees
Assorted Fees	$	405	$	—	$	405	$	—
Total All Other Fees	$	405	$	—	$	405	$	—

2.The Audit Committee considered whether the independent registered public accounting firm’s provision of non-audit services is compatible with maintaining the registered public accounting firm’s independence.

3.The Audit Committee has been advised by PricewaterhouseCoopers LLP that hours expended on the audit engagement were entirely performed by PricewaterhouseCoopers’ personnel.

This report has been provided by the Board of Directors performing the functions of the Audit Committee.

Victor A. Staffieri, Chairman

John R. McCall

S. Bradford Rives

Paul W. Thompson

Chris Hermann

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SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

LG&E and KU have in place procedures to assist its directors and officers in complying with Section 16(a) of the Exchange Act of 1934, which includes assisting the director or officer in preparing forms for filing.   Based upon information provided to LG&E and KU by individual directors and officers, LG&E and KU believe that in respect of the year ended December 31, 2004, all filing requirements have been complied with.

SHAREHOLDER PROPOSALS AND NOMINATIONS

Under LG&E’s By-laws, shareholders intending to nominate a director for election at the annual meeting must provide advance written notice. In general, such notice must be received by the Secretary of LG&E (a) not less than 90 days prior to the meeting date or (b) if the meeting date is not publicly announced more than 100 days prior to the meeting, by the tenth day following such announcement. Under KU’s s By-laws, shareholders intending to nominate a director for election at the annual meeting must provide advance written notice. In general, such notice must be received by the Secretary of KU (a) not less than 60 days prior to the meeting date or (b) if the meeting date is not publicly announced more than 70 days prior to the meeting, by the tenth day following such announcement.

To be proper, written notice must generally include (a) the name and address of the shareholder and of each nominee, (b) a representation that the shareholder is a holder of record entitled to vote at such meeting and intends to appear in person or by proxy, (c) a description of all arrangements between the shareholder and each nominee, (d) such other information regarding each nominee as would be required to be included in a proxy statement under the Securities and Exchange Commission rules had the nominee been nominated by the Board and (e) the consent of the each nominee to serve if elected.  LG&E shareholder proponents must also include the class and number of shares beneficially owned by the proponent.  Proposals not properly submitted will be considered untimely.

SHAREHOLDER COMMUNICATIONS

Shareholders can communicate with the Boards by submitting a letter or writing addressed to a director care of:  John R. McCall, Secretary, Louisville Gas and Electric Company/Kentucky Utilities Company, P.O. Box 32102, 220 West Main Street, Louisville, KY  40232. The Secretary may initially review communications with directors and transmit a summary to the directors, but has discretion to exclude from transmittal any communications that are commercial advertisements or other forms of solicitation or individual service or billing complaints (although all communications are available to the directors upon request). The Secretary will forward to the directors any communications raising substantial issues.

We encourage all directors to attend our annual meeting. Two of our five now-serving directors were in attendance at the LG&E and KU annual meeting in 2004.

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APPENDIX A

LOUISVILLE GAS AND ELECTRIC COMPANY

AND

KENTUCKY UTILITIES COMPANY

AUDIT COMMITTEE CHARTER

(Revised and Approved March 24, 2005)

Mission Statement

The Audit Committee (the “Committee”) is a Committee, respectively, of the Boards of Directors (each, separately, the “Board”) of Louisville Gas and Electric Company and of Kentucky Utilities Company (each, separately, the “Company”).  Its primary function is to assist the Board in fulfilling its oversight responsibilities by reviewing the integrity and internal controls over the Company’s financial reporting process, and other systems of internal controls which management and the Board of Directors have established; the independence and performance of the independent accountant and the Audit Services function; and the process for monitoring compliance with the Code of Business Conduct and the Code of Ethics for the Chief Executive Officer (CEO) and Senior Financial Officers.   Although operating as a combined Committee, actions of the Committee related to an individual Company only are applicable to such Company only, as appropriate.

Composition

The Committee will be composed of at least three members of the Board of Directors who shall serve at the pleasure of the Board. At least one member of the Committee shall be designated as a financial expert. In the event that the Board of Directors does not appoint a Committee, the functions of the Committee shall be performed by the Board of Directors or its members.

Audit Committee members will be appointed by the Board of Directors. One of the members will be designated as the Committee’s Chairman.  The Chairman will preside over the Committee meetings and report Committee actions to the Board of Directors.

Meetings

The Committee will meet on a regular basis, but not less than quarterly, and will call special meetings as circumstances require.  It will meet privately, as necessary, with the Director of Audit Services and the independent public accountant in separate executive sessions to discuss any matters that the Committee, the Director of Audit Services, or the independent accountant believe should be discussed privately. The Committee may ask members of management or others to attend meetings and provide pertinent information, as necessary.

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Responsibilities

1.Provide an open avenue of communication between the internal auditors, the independent accountant, and the Board of Directors.

2.Review and update, where appropriate, the Committee’s charter annually.

3.Recommend to the Board of Directors on an annual basis the independent accountant to be nominated, approve the compensation of the independent accountant, and review and approve the discharge of the independent accountant.  The independent accountant is ultimately responsible to the Board of Directors and the Audit Committee.

4.Pre-approve the audit and non-audit services performed by the independent accountant as prescribed under the Sarbanes-Oxley Act of 2002, and related regulations of the Securities and Exchange Commission.

5.Review and concur in the appointment, replacement, reassignment or dismissal of the Director of Audit Services.

6.Require the independent accountant to submit to the Committee on a periodic basis a formal written statement regarding independence of such independent accountant and all facts and circumstances relevant thereto; discuss with the independent accountant its independence; confirm and assure the independence of the Audit Services Department and the independent accountant, including a review of management consulting services and related fees provided by the independent accountant; and recommend to the Board of Directors actions necessary to ensure independence of the Audit Services Department and the independent accountant. Ascertain that the lead audit partner for the independent accountant(s) serves in that capacity for no more than five years. In addition, ascertain that any partner other than the lead or concurring partner serves no more than seven years at the partner level on the Company’s audit.

7.Monitor the Company’s practices relative to the hiring of current or former employees of the independent accountant.

8.Inquire of management, the Director of Audit Services, and the independent accountant about significant risks or exposures, assess the steps management has taken to minimize such risk to the Company, and periodically review compliance with such steps.

9.Approve the annual audit plan, ensuring provisions are made for the monitoring of the independent accountant’s services as required by the Audit Committee Pre-Approval Policy, and review the three-year plan of the internal auditing function. Review the independent accountant’s proposed audit plan, including coordination with Audit Services’ annual audit plan.

10.Review with the Director of Audit Services and the independent accountant the coordination of audit effort to assure completeness of coverage, reduction of redundant efforts, and the effective use of audit resources.

11.Consider with management and the independent accountant the rationale for employing audit firms other than the principal independent accountant.

12.Consider and review with the independent accountant and the Director of Audit Services:

a.The adequacy of the Company’s internal controls, including computerized information system controls and security;

b.Any related significant issues identified by the independent accountant and Audit Services, together with management’s responses thereto;

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c.Material written communications between the independent accountant and management, such as any management letter or schedule of unadjusted audit differences; and

d.Significant deficiencies and/or material weaknesses in the internal controls over financial reporting identified during the process of management’s assessment of such internal controls or by the independent accountant in their testing of management’s assessment to determine the proper disposition of deficiencies and/or weaknesses identified.

13.Review with management and the independent accountant at the completion of the annual audit:

a.The Company’s annual financial statements and related footnotes;

b.The independent accountant’s audit of the financial statements and the report thereon;

c.The independent accountant’s judgement about the quality and appropriateness of the Company’s accounting principals as applied to its financial reporting;

d.Any significant changes required in the independent accountant’s audit plan and scope;

e.Any serious difficulties or disputes with management encountered during the course of the audit; and

f.Other matters related to the conduct of the audit which are to be communicated to the Committee under generally accepted auditing standards.

14.Review with management such appropriate notices or reports as may be required to be filed on behalf of the Committee with the regulatory authorities, exchanges or included in the Company’s proxy materials or otherwise, pursuant to law or exchange regulations. Review with management and the independent accountant the effect of any regulatory and accounting initiatives, as well as off-balance sheet structures, if any.

15.Consider and review with management and the Director of Audit Services:

a.Any difficulties encountered in the course of their audits, including any restrictions on the scope of their work or access to required information;

b.Any significant changes required in their audit plan;

c.Any significant audit findings and management’s responses thereto;

d.The Audit Services Department budget, staffing, and staff qualifications;

e.The Audit Services Department charter; and

f.Audit Services’ compliance with the Institute of Internal Auditors’ Standards for the Professional Practice of Internal Auditing.

16.Provide oversight of the Company’s Code of Business Conduct, Code of Ethics for the CEO and Senior Financial Officers, and anti-fraud programs. The Committee’s oversight role includes:

a.Periodic review, reassessment, and approval of the Company’s Code of Business Conduct and Code of Ethics for the CEO and Senior Financial Officers;

b.A review, with the Director of Audit Services, of the results of the annual Code of Business Conduct questionnaire;

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c.Creation, maintenance, and review of procedures for:

i.Receipt, retention, and treatment of complaints received by the Company  regarding accounting, internal accounting controls, or auditing matters that may be submitted by any party internal or external to the organization;

ii.Confidential, anonymous submissions by employees of concerns regarding questionable accounting or auditing matters; and

iii.Review of any complaints received for appropriate, timely follow-up and resolution by management.

17.Review the results of any audits of officers’ expense reimbursements, perquisites, and officer use of corporate assets by Audit Services or the independent accountant.  As considered necessary by the Committee, review policies and procedures governing these areas.

18.Review legal and regulatory matters that may have a material impact on the financial statements, related Company compliance policies and programs, and reports received from regulators.

19.Report Committee actions to the Board of Directors with such recommendations as the Committee may deem appropriate.

20.Conduct or authorize investigations into any matters within the Committee’s scope of responsibilities, and retain independent counsel, accountants or others to assist it in the conduct of any investigation.

21.Conduct a periodic review of the Committee’s effectiveness and performance.

22.Assume such other duties and considerations as may be delegated to the Committee by the Board of Directors, or required of the Committee upon the request of the Board of Directors from time to time pursuant to a duly adopted resolution of the Board of Directors.

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