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, 2002
OR
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)

 

 

 

 

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 28, 2002, 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, 2003, Louisville Gas and Electric Company had 21,294,223 shares of common stock outstanding, all held by LG&E Energy Corp.  Kentucky Utilities Company had 37,817,878 shares of common stock outstanding, all held by LG&E Energy Corp.

 

This combined Form 10-K is separately filed by Louisville Gas and Electric Company and Kentucky Utilities Company.  Information contained herein related to any individual registrant is filed by such registrant on its own behalf.  Each registrant makes no representation as to information relating to the other registrants.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Not applicable.

 

 

TABLE OF CONTENTS

 

PART I
Item 1.	Business
	Louisville Gas and Electric Company
	General
	Electric Operations
	Gas Operations
	Rates and Regulation
	Construction Program and Financing
	Coal Supply
	Gas Supply
	Environmental Matters
	Competition
	Kentucky Utilities Company
	General
	Electric Operations
	Rates and Regulation
	Construction Program and Financing
	Coal Supply
	Environmental Matters
	Competition
	Employees and Labor Relations
	Executive Officers of the Companies
Item 2.	Properties
Item 3.	Legal Proceedings
Item 4.	Submission of Matters to a Vote of Security Holders
PART II
Item 5.	Market for the Registrant’s Common Equity and Related Stockholder Matters
Item 6.	Selected Financial Data
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operation:
	Louisville Gas and Electric Company
	Kentucky Utilities Company
Item 7A.	Quantitative and Qualitative 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
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 (a)
Item 13.	Certain Relationships and Related Transactions (a)
PART IV
Item 14.	Controls and Procedures
Item 15.	Exhibits, Financial Statement Schedules, and Reports on Form 8-K
Signatures

 

(a) Incorporated by reference.

 

 

INDEX OF ABBREVIATIONS

 

Capital Corp.		LG&E Capital Corp.
Clean Air Act		The Clean Air Act, as amended in 1990
CCN		Certificate of Public Convenience and Necessity
CT		Combustion Turbines
DSM		Demand Side Management
ECR		Environmental Cost Recovery
EEI		Electric Energy, Inc.
EITF		Emerging Issues Task Force Issue
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
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 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 System Operator
Mmbtu		Million British thermal units
Moody’s		Moody’s Investor Services, Inc.
Mw		Megawatts
Mwh		Megawatt hours
NNS		No-Notice Service
NOPR		Notice of Proposed Rulemaking
NOx		Nitrogen Oxide
OATT		Open Access Transmission Tariff
OMU		Owensboro Municipal Utilities
OVEC		Ohio Valley Electric Corporation
PBR		Performance-Based Ratemaking
PJM		Pennsylvania, New Jersey, Maryland Interconnection
Powergen		Powergen Limited (formerly Powergen plc)
PUHCA		Public Utility Holding Company Act of 1935
ROE		Return on Equity
RTO		Regional Transmission Organization
S&P		Standard & Poor’s Rating Services

 

 

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

 

 

 

PART I.

 

Item 1.  Business.

 

LG&E and KU are each subsidiaries of LG&E Energy.  On December 11, 2000, LG&E Energy was acquired by Powergen plc, now known as Powergen Limited, for cash of approximately $3.2 billion or $24.85 per share and the assumption of all of LG&E Energy’s debt.  As a result of the acquisition, among other things, LG&E Energy became a wholly owned subsidiary of Powergen and, as a result, LG&E and KU became indirect subsidiaries of Powergen.  The utility operations (LG&E and KU) of LG&E Energy have continued their separate identities and continue to serve customers in Kentucky, Virginia and Tennessee under their existing names.  The preferred stock and debt securities of the utility operations were not affected by this transaction resulting in the utility operations’ obligations to continue to file SEC reports.  Following the acquisition, Powergen became a registered holding company under PUHCA, and LG&E and KU, as subsidiaries of a registered holding company, became subject to additional regulation under PUHCA.

 

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

 

On July 1, 2002, E.ON, a German company, completed its acquisition of Powergen following receipt of all necessary regulatory approvals.  E.ON had announced its pre-conditional cash offer of £5.1 billion ($7.3 billion) for Powergen on April 9, 2001.

 

LOUISVILLE GAS AND ELECTRIC COMPANY

 

General

 

Incorporated in 1913 in Kentucky, LG&E is a regulated public utility that supplies natural gas to approximately 310,000 customers and electricity to approximately 382,000 customers in Louisville and adjacent areas in Kentucky.  LG&E’s service area covers approximately 700 square miles in 17 counties and has an estimated population of one million.  Included in this area is the Fort Knox Military Reservation, to which LG&E transports gas and provides electric service, but which maintains its own distribution systems.  LG&E also provides gas service in limited additional areas.  LG&E’s coal-fired electric generating plants, all equipped with systems to reduce sulfur dioxide emissions, produce most of LG&E’s electricity.  The remainder is generated by a hydroelectric power plant and combustion turbines.  Underground natural gas storage fields help LG&E provide economical and reliable gas service to customers.  See Item 2, Properties.

 

LG&E has one wholly owned consolidated subsidiary, LG&E R. LG&E R is a special purpose entity formed in September 2000 to enter into accounts receivable securitization transactions with LG&E.  LG&E R started operations in 2001.  LG&E is considering unwinding its accounts receivable securitization arrangements involving LG&E R during 2003.

 

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For the year ended December 31, 2002, 74% of total operating revenues were derived from electric operations and 26% 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:

 

		(Thousands of $)
		Electric				Gas			Combined			% Combined
Residential		$		232,285		$	160,733		$	393,018		47	%
Commercial		185,112				61,036			246,148			30	%
Industrial		111,871				10,232			122,103			15	%
Public authorities		57,703				11,197			68,900			8	%
Total retail		586,971				243,198			830,169			100	%
Wholesale sales		143,002				16,384			159,386
Gas transported – net		—				6,232			6,232
Provision for rate collections		12,267				—			12,267
Miscellaneous		16,251				1,879			18,130
Total		$	758,491			$	267,693		$	1,026,184

 

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, 2002.

 

Electric Operations

 

The sources of LG&E’s electric operating revenues and the volumes of sales for the three years ended December 31, 2002, were as follows:

 

		2002			2001			2000
ELECTRIC OPERATING REVENUES
(Thousands of $)
Residential		$	232,285		$	205,926		$	205,105
Commercial		185,112			171,540			171,414
Industrial		111,871			104,438			104,738
Public authorities		57,703			53,725			54,270
Total retail		586,971			535,629			535,527
Wholesale sales		143,002			159,406			165,080
Provision for rate collections (refunds)		12,267			(720		)	(2,500		)
Miscellaneous		16,251			11,610			12,851
Total		$	758,491		$	705,925		$	710,958
ELECTRIC SALES (Thousands of Mwh):
Residential		4,036			3,782			3,722
Commercial		3,493			3,395			3,350
Industrial		3,028			2,976			3,043
Public authorities		1,253			1,224			1,214
Total retail		11,810			11,377			11,329
Wholesale sales		7,262			6,957			6,834
Total		19,072			18,334			18,163

 

LG&E uses efficient coal-fired boilers, fully equipped with sulfur dioxide removal systems, to generate most of its

 

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electricity.  LG&E’s weighted-average system-wide emission rate for sulfur dioxide in 2002 was approximately 0.55 lbs./Mmbtu of heat input, with every generating unit below its emission limit established by the Kentucky Division for Air Quality.

 

LG&E set a record local peak load of 2,623 Mw on Monday, August 5, 2002, when the peak daily temperature was 100 degrees F.

 

The electric utility business is affected by seasonal weather patterns.  As a result, operating revenues (and associated operating expenses) are not generated evenly throughout the year.  See LG&E’s Results of Operations under Item 7.

 

LG&E currently maintains a 13 – 15% reserve margin range.  At December 31, 2002, LG&E owned steam and combustion turbine generating facilities with a net summer capability of 2,882 Mw and an 80 Mw nameplate rated hydroelectric facility on the Ohio River with a summer capability rate of 48 Mw.  At December 31, 2002, LG&E’s system net summer capability, including purchases from others and excluding the hydroelectric facility, was 3,037 Mw.  See Item 2, Properties.

 

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’s of generation capacity. LG&E also has agreements with a number of entities throughout the United States for the purchase and/or sale of capacity and energy and for the utilization of their bulk transmission system.

 

On February 1, 2002, LG&E (along with KU) turned over operational control of its high voltage transmission facilities (100kV and above) to MISO.  LG&E (along with KU) is a founding member of MISO.  Such membership was obtained in 1998 in response to and consistent with federal policy initiatives.  MISO operates a single OATT over the facilities under its control.  Currently MISO controls over 100,000 miles of transmission over 1.1 million square miles located in the northern Midwest between Manitoba, Canada and Kentucky.  On September 18, 2002, FERC granted a 12.88% ROE on transmission facilities for LG&E, KU and the rest of the MISO owners.  This ROE includes a 50 basis point increase because of operational independence.

 

MISO plans to implement a Congestion Management System in December 2003, in compliance with FERC Order 2000.  This system will be similar to the Locational Marginal Pricing (LMP) system currently used by the PJM RTO and contemplated in FERC’s SMD NOPR, currently being discussed.  MISO filed with FERC a mechanism for recovery of costs for the Congestion Management System, designated Schedule 16 and Schedule 17.  The MISO transmission owners, including LG&E and KU, and others have objected to the allocation of costs between market participants and retail native load.  This case is currently in a hearing at FERC.

 

In October 2001, the FERC issued an order requiring that the bundled retail load and grandfathered wholesale load of each member transmission owner (including LG&E) be included in the current calculation of MISO’s “cost-adder,” a charge designed to recover MISO’s costs of operation, including start-up capital (debt) costs.  LG&E, along with several other transmission owners, opposed the FERC’s ruling in this regard, which opposition the FERC rejected in an order on rehearing issued in 2002.   Later that year, MISO’s transmission owners, including LG&E, appealed the FERC’s decision to the United States Court of Appeals for the District of Columbia Circuit.  In response, by petition filed November 25, 2002, the FERC requested that the Court issue a partial remand of its challenged orders to allow the FERC to revisit certain issues raised therein, and further requested that the case be held in abeyance pending the agency’s resolution of such issues.  The Court granted the FERC’s petition by order dated December 6, 2002.   On February 24, 2003, FERC issued an order

 

8

 

reaffirming its position concerning the calculation of the “cost-adder”.

 

As a separate matter, MISO, its transmission owners and other interested industry segments reached a settlement in mid-2002 regarding the level of cost responsibility properly borne by bundled and grandfathered load under these FERC rulings (such settlement expressly not prejudicing the transmission owners’ and LG&E’s right to challenge the FERC’s ruling imposing cost responsibility on bundled loads in the first instance).  On February 24, 2003, FERC accepted a partial settlement between MISO and the transmission owners.  FERC did not accept the only contested section of the settlement, which would have allowed the transmission owners to immediately treat unrecoverable Schedule 10 charges as regulatory assets.  FERC will consider allowing regulatory asset treatment of unrecoverable Schedule 10 charges on a case-by-case basis.

 

Gas Operations

 

The sources of LG&E’s gas operating revenues and the volumes of sales for the three years ended December 31, 2002, were as follows:

 

		2002			2001			2000
GAS OPERATING REVENUES
(Thousands of $)
Residential		$	160,733		$	177,387		$	159,670
Commercial		61,036			70,296			61,888
Industrial		10,232			15,750			15,898
Public authorities		11,197			13,223			9,193
Total retail		243,198			276,656			246,649
Wholesale sales		16,384			5,702			17,344
Gas transported – net		6,232			6,042			6,922
Miscellaneous		1,879			2,375			1,574
Total		$	267,693		$	290,775		$	272,489
GAS SALES (Millions of cu. ft.):
Residential		22,124			20,429			24,274
Commercial		9,074			8,587			10,132
Industrial		1,783			2,160			3,089
Public authorities		1,747			1,681			1,576
Total retail		34,728			32,857			39,071
Wholesale sales		5,345			1,882			5,115
Gas transported		13,939			13,108			14,729
Total		54,012			47,847			58,915

 

The gas utility business is affected by seasonal weather patterns.  As a result, operating revenues (and associated operating expenses) are not generated evenly throughout the year.  See LG&E’s Results of Operations under Item 7.

 

LG&E has five underground natural gas storage fields that help provide economical and reliable gas service to ultimate consumers.  By using gas storage facilities, LG&E avoids the costs associated with typically more expensive pipeline transportation capacity to serve peak winter space-heating loads.  LG&E stores gas in the summer season for withdrawal in the subsequent winter heating season.  Without its storage capacity, LG&E would be forced to buy additional gas and pipeline transportation services when customer demand increases, likely to be when the price for those items are typically at their highest.  Currently, LG&E buys competitively

 

9

 

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, 2002, LG&E had an inventory balance of gas stored underground of 12.6 million Mcf valued at $50.3 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 about one-fourth of LG&E’s annual throughput.

 

The all-time maximum day gas sendout of 545,000 Mcf occurred on Sunday, January 20, 1985, when the average temperature for the day was -11 degrees F.  During 2002, maximum day gas sendout was approximately 418,000 Mcf, occurring on February 27, 2002, when the average temperature for the day was 21 degrees F.  Supply on that day consisted of approximately 130,000 Mcf from purchases, approximately 221,000 Mcf delivered from underground storage, and approximately 67,000 Mcf transported for industrial customers.  For a further discussion, see Gas Supply under Item 1.

 

Rates and Regulation

 

Following the purchase of Powergen by E.ON, E.ON became a registered holding company under PUHCA.  As a result, E.ON, its utility subsidiaries, including LG&E, and certain of its non-utility subsidiaries are subject to extensive regulation by the SEC under PUHCA with respect to issuances and sales of securities, acquisitions and sales of certain utility properties, and intra-system sales of certain goods and services.  In addition, PUHCA generally limits the ability of registered holding companies to acquire additional public utility systems and to acquire and retain businesses unrelated to the utility operations of the holding company.  LG&E believes that it has adequate authority (including financing authority) under existing SEC orders and regulations to conduct its business.  LG&E will seek additional authorization when necessary.

 

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.

 

The Kentucky Commission has regulatory jurisdiction over the rates and service of LG&E and over the issuance of certain of its securities.  The Kentucky Commission has the ability to examine the rates LG&E charges its retail customers at any time.  LG&E is a “public utility” as defined in the FPA, and is subject to the jurisdiction of the Department of Energy and FERC with respect to the matters covered in the FPA, including the sale of electric energy at wholesale in interstate commerce.

 

For a discussion of current regulatory matters, see Rates and Regulation for LG&E under Item 7 and Note 3 of LG&E’s Notes to Financial Statements under Item 8.

 

LG&E’s 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.

 

LG&E’s retail electric rates are subject to an ESM.  The ESM, initially in place for three years beginning in 2000, sets an upper and lower point for rate of return on equity, whereby if LG&E’s rate of return for the calendar year

 

10

 

falls within the range of 10.5% to 12.5%, no action is necessary.  If earnings are above the upper limit, the excess earnings are shared 40% with ratepayers and 60% with shareholders; if earnings are below the lower limit, the earnings deficiency is recovered 40% from ratepayers and 60% from shareholders.  By order of the Kentucky Commission, rate changes prompted by the ESM filing go into effect in April of each year subject to a balancing adjustment in successive periods.  LG&E made its second ESM filing on March 1, 2002, for the calendar year 2001 reporting period.  LG&E is in the process of refunding $441,000 to customers for the 2001 reporting period.  LG&E estimated that the rate of return will fall below the lower limit, subject to Kentucky Commission approval, for the year ended December 31, 2002.  The 2002 financial statements include an accrual to reflect the earnings deficiency of $12.5 million to be recovered from customers commencing in April 2003.

 

On November 27, 2002, LG&E filed a revised ESM tariff which proposed continuance of the existing ESM through 2005.  The Kentucky Commission issued an Order suspending the ESM tariff one day making the effective date January 2, 2003.  In addition, the Kentucky Commission is conducting a management audit to review the ESM plan and reassess its reasonableness in 2003.  LG&E and interested parties will have the opportunity to provide recommendations for modification and continuance of the ESM or other forms of alternative or incentive regulation.

 

LG&E’s retail rates contain an ECR surcharge which recovers certain costs incurred by LG&E that are required to comply with the Clean Air Act and other environmental regulations.  See Note 3 of LG&E’s Notes to Financial Statements under Item 8.

 

LG&E’s gas rates contain a GSC, whereby increases or decreases in the cost of gas supply are reflected in LG&E’s rates, subject to approval by the Kentucky Commission.  The GSC procedure prescribed by order of the Kentucky Commission provides for quarterly rate adjustments to reflect the expected cost of gas supply in that quarter.  In addition, the GSC contains a mechanism whereby any over- or under-recoveries of gas supply cost from prior quarters will be refunded to or recovered from customers through the adjustment factor determined for subsequent quarters.

 

Integrated resource planning regulations in Kentucky require LG&E and the other major utilities to make triennial filings with the Kentucky Commission of various historical and forecasted information relating to load, capacity margins and demand-side management techniques.  LG&E filed its most recent integrated resource plan on October 1, 2002.

 

Pursuant to Kentucky law, the Kentucky Commission has established the boundaries of the service territory or area of each retail electric supplier in Kentucky (including LG&E), other than municipal corporations.  Within this service territory each such supplier has the exclusive right to render retail electric service.

 

Construction Program and Financing

 

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

 

During the five years ended December 31, 2002, gross property additions amounted to approximately $950 million. 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

 

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December 31, 2002, and consisted of $798 million for electric properties and $152 million for gas properties.  Gross retirements during the same period were $106 million, consisting of $74 million for electric properties and $32 million for gas properties.

 

Coal Supply

 

Coal-fired generating units provided over 97% of LG&E’s net kilowatt-hour generation for 2002.  The remaining net generation was provided by a natural gas and oil fueled combustion turbine peaking units and a hydroelectric plant.  Coal will be the predominant fuel used by LG&E in the foreseeable future, with natural gas and oil being used for peaking capacity and flame stabilization in coal-fired boilers or in emergencies.  LG&E has no nuclear generating units and has no plans to build any in the foreseeable future.  LG&E has entered into coal supply agreements with various suppliers for coal deliveries for 2003 and beyond.  LG&E normally augments its coal supply agreements with spot market purchases. LG&E has a coal inventory policy which it believes provides adequate protection under most contingencies.  LG&E had a coal inventory of approximately 1.5 million tons, or a 74-day supply, on hand at December 31, 2002.

 

LG&E expects to continue purchasing most of its coal, with sulfur content in the 2%-4.5% range, from western Kentucky, southwest Indiana, and West Virginia for the foreseeable future.  This supply is relatively low priced coal, and in combination with its sulfur dioxide removal systems is expected to enable LG&E to continue to provide electric service in compliance with existing environmental laws and regulations.

 

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

 

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

 

		2002			2001			2000
Per ton		$	25.30		$	21.27		$	20.96
Per Mmbtu		$	1.11		$	.93		$	.92
Spot purchases as % of all sources		2		%	3		%	1		%

 

The delivered cost of coal is expected to remain relatively flat during 2003.  Slight increases in the cost of coal in multi-year contracts signed for 2002 are expected to be offset by lower prices negotiated in contracts signed for 2003.

 

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.

 

On April 28, 2000, Texas Gas filed with FERC in Docket RP00-260 for an increase in its base rates effective June 1, 2000.  This filing is part of a rate case Texas Gas was required to file pursuant to the settlement in its last rate case.  On May 31, 2000, FERC issued an Order suspending the effectiveness of Texas Gas’s proposed rates, subject to refund, until November 1, 2000, and establishing a hearing and settlement procedures.  As the result of reaching various FERC-approved settlements, Texas Gas’s higher motion rates were not billed after July 31, 2002, and its lower prospective rates went into effect on August 1, 2002.  Refunds covering the period from November 1, 2000, through July 31, 2002, were received on September 17, 2002, and are currently being

 

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refunded to customers through the GSC.  LG&E participates in rate and other proceedings affecting its regulated interstate pipeline services, as appropriate.

 

LG&E transports on the Texas Gas system under NNS and FT rate schedules.  During the winter months, LG&E has 184,900 Mmbtu/day in NNS service and 18,000 Mmbtu/day (increasing to 36,000 Mmbtu/day effective November 1, 2003) 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 also transports on the Tennessee system under Tennessee’s FT-A rate schedule.  LG&E’s contract levels with Tennessee are 51,000 Mmbtu/day throughout the year.  The FT-A agreement with Tennessee, which was subject to termination by LG&E during 2002, has been successfully renegotiated for a minimum additional term of five years at a lower price.

 

LG&E also has a portfolio of supply arrangements with various suppliers in order to meet its firm sales obligations.  These gas supply arrangements include pricing provisions that are market-responsive.  These firm gas supplies, in tandem with pipeline transportation services, provide the reliability and flexibility necessary to serve LG&E’s customers.

 

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

 

The estimated maximum deliverability from storage during the early part of the heating season is typically about 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 $4.19 in 2002, $5.27 in 2001 and $5.08 in 2000.  Although natural gas prices in the unregulated wholesale market increased significantly throughout 2000 and early 2001, these prices decreased dramatically in early 2002 and then began to increase again.  These increases in natural gas prices, caused in part by decreased natural gas production, decreased liquidity in the marketplace, increases in the price of oil, and increased reliance on natural gas as a fuel for electric generation were mitigated in part by higher national storage inventory levels, and decreased demand associated with a less robust economy.

 

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 2002, expenditures for pollution control facilities represented $253.8 million or 27% of total construction expenditures.  LG&E estimates that construction expenditures for the installation of NOx control equipment from 2003 through 2004 will be approximately $32 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 prepare for the expected increase in competition in its industry, including a reduction in the number of employees; aggressive cost cutting; write-offs of previously

 

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deferred expenses; an increase in focus on commercial, industrial and residential customers; an increase in employee involvement and training; a major realignment and formation of new business units, and continuous modifications of its organizational structure.  LG&E will continue to take additional steps to better position itself for competition in the future.

 

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 477,000 customers in over 600 communities and adjacent suburban and rural areas in 77 counties in central, southeastern and western Kentucky, to approximately 30,000 customers in 5 counties in southwestern Virginia and to less than 10 customers in Tennessee.  In Virginia, KU operates under the name Old Dominion Power Company.  KU operates under appropriate franchises in substantially all of the 160 Kentucky incorporated municipalities served.  No franchises are required in unincorporated Kentucky or Virginia communities.  The lack of franchises is not expected to have a material adverse effect on KU’s operations.  KU also sells wholesale electric energy to 12 municipalities.

 

KU has one wholly owned consolidated subsidiary, KU R.  KU R is a special purpose entity formed in September 2000 to enter into accounts receivable securitization transactions with KU.  KU R began operations in 2001.  KU is considering unwinding its accounts receivable securitization arrangements involving KU R during 2003.

 

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Electric Operations

 

The sources of KU’s electric operating revenues and the volumes of sales for the three years ended December 31, 2002, were as follows:

 

		2002			2001			2000
ELECTRIC OPERATING REVENUES
(Thousands of $):
Residential		$	275,869		$	244,004		$	241,783
Commercial		179,157			165,389			161,291
Industrial		163,206			146,968			153,017
Mine power		29,453			28,196			27,089
Public authorities		62,649			58,770			57,979
Total retail		710,334			643,327			641,159
Wholesale sales		143,807			203,181			198,073
Provision for rate collections (refunds)		13,027			(954		)	—
Miscellaneous		21,051			13,918			12,709
Total		$	888,219		$	859,472		$	851,941
ELECTRIC SALES (Thousands of Mwh):
Residential		6,198			5,678			5,714
Commercial		4,161			3,990			3,954
Industrial		4,975			4,716			5,044
Mine power		766			771			767
Public authorities		1,533			1,481			1,495
Total retail		17,633			16,636			16,974
Wholesale sales		5,780			7,713			7,573
Total		23,413			24,349			24,547

 

KU’s weighted-average system-wide emission rate for sulfur dioxide in 2002 was approximately 1.24 lbs./Mmbtu of heat input, with every generating unit below its emission limit established by the Kentucky Division for Air Quality.

 

KU set a record local peak load of 3,899 Mw on Monday, August 5, 2002, when the peak daily temperature was 100 degrees F.

 

The electric utility business is affected by seasonal weather patterns.  As a result, operating revenues (and associated operating expenses) are not generated evenly throughout the year.  See KU’s Results of Operations under Item 7.

 

KU currently maintains a 13-15% reserve margin range.  At December 31, 2002, KU owned steam and combustion turbine generating facilities with a net summer capability of 4,111 Mw and a 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, 2002, KU’s system net summer capability, including purchases from others and excluding the hydroelectric facility, was 4,630 Mw.

 

Under a contract expiring in 2020 with OMU, KU has agreed to purchase from OMU the surplus output of the 150-Mw and 250-Mw generating units at OMU’s Elmer Smith station.  Purchases under the contract are made under a contractual formula which has resulted in costs which were and are expected to be comparable to the cost of other power purchased or generated by KU.  Such power equated to approximately 8% of KU’s net

 

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generation system output during 2002.  See Note 11 of KU’s Notes to Financial Statements under Item 8.

 

KU owns 20% of the common stock of EEI, which owns and operates a 1,000-Mw generating station in southern Illinois.  KU is entitled to take 20% of the available capacity of the station.  Purchases from EEI are made under a contractual formula which has resulted in costs which were and are expected to be comparable to the cost of other power purchased or generated by KU.  Such power equated to approximately 9% of KU’s net generation system output in 2002.  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. 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 Mws of generation capacity.  KU also has agreements with a number of entities throughout the United States for the purchase and/or sale of capacity and energy and for the utilization of their bulk transmission systems.

 

On February 1, 2002, KU (along with LG&E) turned over operational control of its high voltage transmission facilities (100kV and above) to MISO.  KU (along with LG&E) is a founding member of MISO.  Such membership was obtained in 1998 in response to and consistent with federal policy initiatives.  MISO operates a single OATT over the facilities under its control.  Currently MISO controls over 100,000 miles of transmission over 1.1 million square miles located in the northern Midwest between Manitoba, Canada and Kentucky.  On September 18, 2002, FERC granted a 12.88% ROE on transmission facilities for LG&E, KU and the rest of the MISO owners.  This ROE includes a 50 basis point increase because of operational independence.

 

MISO plans to implement a Congestion Management System in December 2003, in compliance with FERC Order 2000.  This system will be similar to the Locational Marginal Pricing (LMP) system currently used by the PJM RTO and contemplated in FERC’s SMD NOPR currently being discussed.  MISO filed with FERC a mechanism for recovery of costs for the Congestion Management System, designated Schedule 16 and Schedule 17.  MISO transmission owners, including LG&E and KU, and others have objected to the allocation of costs between market participants and retail native load.  This case is currently in a hearing at FERC.

 

In October 2001, the FERC issued an order requiring that the bundled retail load and grandfathered wholesale load of each member transmission owner (including KU) be included in the current calculation of MISO’s “cost-adder,” a charge designed to recover MISO’s costs of operation, including start-up capital (debt) costs.  KU, along with several other transmission owners, opposed the FERC’s ruling in this regard, which opposition the FERC rejected in an order on rehearing issued in 2002.  Later that year, MISO’s transmission owners, including KU, appealed the FERC’s decision to the United States Court of Appeals for the District of Columbia Circuit.  In response, by petition filed November 25, 2002, FERC requested that the Court issue a partial remand of its challenged orders to allow the FERC to revisit certain issues raised therein, and further requested that the case be held in abeyance pending the agency’s resolution of such issues.  The Court granted the FERC’s petition by order dated December 6, 2002.  On February 24, 2003, FERC issued an order reaffirming its position concerning the calculation of the “cost-adder”.

 

As a separate matter, MISO, its transmission owners and other interested industry segments reached a settlement in mid-2002 regarding the level of cost responsibility properly borne by bundled and grandfathered load under these FERC rulings (such settlement expressly not prejudicing the transmission owners’ and KU’s right to challenge the FERC’s ruling imposing cost responsibility on bundled loads in the first instance).  On February 24, 2003, FERC accepted a partial settlement between MISO and the transmission owners.  FERC did not accept the only contested section of the settlement, which would have allowed the transmission owners to immediately treat unrecoverable Schedule 10 charges as regulatory assets.  FERC will consider allowing

 

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regulatory asset treatment of unrecoverable Schedule 10 charges on a case-by-case basis.

 

Rates and Regulation

 

Following the purchase of Powergen by E.ON, E.ON became a registered holding company under PUHCA.  As a result, E.ON, its utility subsidiaries, including KU, and certain of its non-utility subsidiaries are subject to extensive regulation by the SEC under PUHCA with respect to issuances and sales of securities, acquisitions and sales of certain utility properties, and intra-system sales of certain goods and services.  In addition, PUHCA generally limits the ability of registered holding companies to acquire additional public utility systems and to acquire and retain businesses unrelated to the utility operations of the holding company.  KU believes that it has adequate authority (including financing authority) under existing SEC orders and regulations to conduct its business.  KU will seek additional authorization when necessary.

 

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.

 

The Kentucky Commission and the Virginia Commission have regulatory jurisdiction over KU’s retail rates and service, and over the issuance of certain of its securities. By reason of owning and operating a small amount of electric utility property in one county in Tennessee (having a gross book value of approximately $225,000) from which KU served five customers at December 31, 2002, KU is subject to the jurisdiction of the TRA. FERC has classified KU as a “public utility” as defined in the FPA.  FERC has jurisdiction under the FPA over certain of the electric utility facilities and operations, wholesale sale of power and related transactions and accounting practices of KU, and in certain other respects as provided in the FPA.

 

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

 

KU’s Kentucky retail electric rates contain a FAC, whereby increases and decreases in the cost of fuel for electric generation are reflected in the rates charged to retail electric customers.  The Kentucky Commission requires public hearings at six-month intervals to examine past fuel adjustments, and at two-year intervals to review past operations of the fuel clause and transfer of the then current fuel adjustment charge or credit to the base charges.  The Kentucky Commission also requires that electric utilities, including KU, file certain documents relating to fuel procurement and the purchase of power and energy from other utilities.  The FAC mechanism for Virginia customers uses an average fuel cost factor based primarily on projected fuel costs.  The fuel cost factor may be adjusted annually for over or under collections of fuel costs from the previous year.

 

KU’s Kentucky retail electric rates are subject to an ESM.  The ESM, initially in place for three years beginning in 2000, sets an upper and lower point for rate of return on equity, whereby if KU’s rate of return for the calendar year falls within the range of 10.5% to 12.5%, no action is necessary.  If earnings are above the upper limit, the excess earnings are shared 40% with ratepayers and 60% with shareholders; if earnings are below the lower limit, the earnings deficiency is recovered 40% from ratepayers and 60% from shareholders.  By order of the Kentucky Commission, rate changes prompted by the ESM filing go into effect in April of each year subject to a balancing adjustment in successive periods.  KU made its second ESM filing on March 1, 2002 for the calendar year 2001 reporting period.  KU is in the process of refunding $1 million to customers for the 2001 reporting period.  KU estimated that the rate of return will fall below the lower limit for the year ended December 31, 2002.  The 2002 financial statements include an accrual to reflect the earnings, subject to Kentucky Commission approval, deficiency of $13.5 million to be recovered from customers commencing in April 2003.

 

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On November 27, 2002, KU filed a revised ESM tariff which proposed continuance of the existing ESM through 2005.  The Kentucky Commission issued an Order suspending the ESM tariff one day making the effective date January 2, 2003.  In addition, the Kentucky Commission is conducting a management audit to review the ESM plan and reassess its reasonableness in 2003.  KU and interested parties will have the opportunity to provide recommendations for modification and continuance of the ESM or other forms of alternative or incentive regulation.

 

KU’s Kentucky retail rates contain an ECR surcharge which recovers certain costs incurred by KU that are required to comply with the Clean Air Act and other environmental regulations.  See Note 3 of KU’s Notes to Financial Statements under Item 8.

 

Integrated resource planning regulations in Kentucky require KU and the other major utilities to make triennial filings with the Kentucky Commission of various historical and forecasted information relating to load, capacity margins and demand-side management techniques.  KU filed its most recent integrated resource plan on October 1, 2002.

 

Pursuant to Kentucky law, the Kentucky Commission has established the boundaries of the service territory or area of each retail electric supplier in Kentucky (including KU), other than municipal corporations.  Within this service territory each such supplier has the exclusive right to render retail electric service.

 

The state of Virginia passed the Virginia Electric Utility Restructuring Act in 1999.  This act gives Virginia customers a choice for energy services.  The change will be phased in gradually between January 2002 and January 2004.  KU filed unbundled rates that became effective January 1, 2002.  Rates are capped at current levels through June 2007.  The Virginia Commission will continue to require each Virginia utility to make annual filings of either a base rate change or an Annual Informational Filing consisting of a set of standard financial schedules.  The Virginia Staff will issue a Staff Report regarding the individual utility’s financial performance during the historic 12-month period.  The Staff Report can lead to an adjustment in rates, but through June 2007 will be limited to decreases.  KU was granted a waiver from the Virginia Commission on October 29, 2002, exempting KU from retail choice through December 31, 2004.  KU is also seeking a permanent legislative exemption from the Virginia Electric Utility Restructuring Act.  The outcome of this legislative initiative is not expected be known until mid-2003.

 

Construction Program and Financing

 

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

 

During the five years ended December 31, 2002, gross property additions amounted to approximately $754 million.  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 23% of total utility plant at December 31, 2002.  Gross retirements during the same period were $82 million.

 

Coal Supply

 

Coal-fired generating units provided over 97% of KU’s net kilowatt-hour generation for 2002.  The remaining

 

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net generation for 2002 was provided by natural gas and oil fueled combustion turbine peaking units and hydroelectric plants.  Coal will be the predominant fuel used by KU in the foreseeable future, with natural gas and oil being used for capacity and flame stabilization in coal-fired boilers or in emergencies.  KU has no nuclear generating units and has no plans to build any in the foreseeable future.

 

KU maintains its fuel inventory at levels estimated to be necessary to avoid operational disruptions at its coal-fired generating units.  Reliability of coal deliveries can be affected from time to time by a number of factors, including fluctuations in demand, coal mine labor issues and other supplier or transporter operating difficulties.

 

KU believes there are adequate reserves available to supply its existing base-load generating units with the quantity and quality of coal required for those units throughout their useful lives.  KU intends to meet a portion of its coal requirements with three-year or shorter contracts.  As part of this strategy, KU will continue to negotiate replacement contracts as contracts expire.  KU does not anticipate any problems negotiating new contracts for future coal needs.  The balance of coal requirements will be met through spot purchases.  KU had a coal inventory of approximately 1.4 million tons, or a 67-day supply, on hand at December 31, 2002.

 

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, southwest Indiana, Wyoming and Pennsylvania for the foreseeable future.

 

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

 

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

 

		2002			2001			2000
Per ton		$	31.44		$	27.84		$	25.63
Per Mmbtu		$	1.35		$	1.20		$	1.07
Spot purchases as % of all sources		18		%	44		%	51		%

 

KU’s historical average cost of coal purchased is higher than LG&E’s due to the lower sulfur content of the coal KU purchases for use at its Ghent plant and higher cost to transport coal to the E.W. Brown plant. The delivered cost of coal is expected to increase during 2003.

 

Environmental Matters

 

Protection of the environment is a major priority for KU.  Federal, state, and local regulatory agencies have issued KU permits for various activities subject to air quality, water quality, and waste management laws and regulations.  For the five-year period ending with 2002, expenditures for pollution control facilities represented $63.5 million or 11% of total construction expenditures. KU estimates that construction expenditures for the installation of NOx control equipment from 2003 through 2004 will be approximately $178 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 prepare for the expected increase in competition in its

 

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industry, 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; a major realignment and formation of new business units; and continuous modifications of its organizational structure.  KU will continue to take additional steps to better position itself for competition in the future.

 

EMPLOYEES AND LABOR RELATIONS

 

LG&E had 891 full-time regular employees and KU had 946 full-time regular employees at December 31, 2002.  Of the LG&E total, 628 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.  Of the KU total, 162 operating, maintenance, and construction employees were represented by IBEW Local 2100 and USWA Local 9447-01.  In August 2001, KU and employees represented by IBEW Local 2100 entered into a two-year collective bargaining agreement.  KU and employees represented by USWA Local 9447-01 entered into a three-year collective bargaining agreement effective August 2002 and expiring August 2005.

 

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

 

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

 

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Executive Officers of LG&E and KU at December 31, 2002:

 

Name		Age		Position		Effective Date of Election to Present Position
Victor A. Staffieri		47		Chairman of the Board, President and Chief Executive Officer		May 1, 2001
Richard Aitken-Davies		53		Chief Financial Officer		January 31, 2001
John R. McCall		59		Executive Vice President, General Counsel and Corporate Secretary		July 1, 1994
S. Bradford Rives		44		Senior Vice President - Finance and Controller		December 11, 2000
Paul W. Thompson		45		Senior Vice President - Energy Services		June 7, 2000
Chris Hermann		55		Senior Vice President - Distribution Operations		December 11, 2000
Wendy C. Welsh		48		Senior Vice President - Information Technology		December 11, 2000
Martyn Gallus		38		Senior Vice President - Energy Marketing		December 11, 2000
A. Roger Smith		49		Senior Vice President Project Engineering		December 11, 2000
David A. Vogel		36		Vice President – Retail Services		December 11, 2000
Daniel K. Arbough		41		Treasurer		December 11, 2000
Bruce D. Hamilton		47		Vice President Independent Power Operations		December 11, 2000
Robert E. Henriques		61		Vice President Regulated Generation		September 30, 2001
Michael S. Beer		44		Vice President-Rates and Regulatory		February 1, 2001
George R. Siemens		53		Vice President-External Affairs		January 11, 2001
Paula H. Pottinger		45		Vice President - Human Resources		June 1, 2002
D. Ralph Bowling		45		Vice President - Power Operations WKE		August 1, 2002
R. W. Chip Keeling		46		Vice President - Communications		March 18, 2002

 

 

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The present term of office of each of the above executive officers extends to the meeting of the Board of Directors following the 2003 Annual Meeting of Shareholders.

 

There are no family relationships between or among executive officers of LG&E and KU.  The above tables indicate officers serving as executive officers of both LG&E and KU at December 31, 2002.  Each of the above officers serves in the same capacity for LG&E and KU.

 

Before he was elected to his current positions, Mr. Staffieri was President, Distribution Services Division of LG&E Energy Corp. from December 1995 to May 1997; Chief Financial Officer of LG&E Energy Corp. and LG&E from May 1997 to February 1999, (including Chief Financial Officer of KU from May 1998 to February 1999); President and  Chief Operating Officer of LG&E Energy Corp. from March 1999 to April 2001 (including President of LG&E and KU from June 2000 to April 2001); Chairman, President and CEO of LG&E Energy Corp., LG&E and KU from May 2001 to present.

 

Before he was elected to his current positions, Mr. Aitken-Davies was Group Performance Director at Powergen from April 1998 to March 2000; Director - LG&E Transition Team at Powergen from March 2000 to January 2001.

 

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

 

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

 

Before he was elected to his current positions, Mr. Thompson was Vice President – Business Development for LG&E Energy Corp. from July 1994 to September 1996; Vice President, Retail Electric Business for LG&E from September 1996 to June 1998; Group Vice President for LG&E Energy Marketing, Inc. from June 1998 to August 1999; Vice President, Retail Electric Business for LG&E from December 1998 to August 1999; and Senior Vice President – Energy Services for LG&E Energy Corp. from August 1999 to June 2000.

 

Before he was elected to his current positions, Mr. Hermann was Vice President and General Manager, Wholesale Electric Business of LG&E from January 1993 to June 1997; Vice President, Business Integration of LG&E from June 1997 to May 1998; Vice President, Power Generation and Engineering Services, of LG&E from May 1998 to December 1999; and Vice President Supply Chain and Operating Services from December 1999 to December 2000.

 

Before she was elected to her current positions, Ms. Welsh was Vice President - Information Services of LG&E from January 1994 to May 1997; Vice President, Administration of LG&E Energy Corp. from May 1997 to February 1998; and Vice President-Information Technology from February 1998 to December 2000.

 

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Before he was elected to his current positions, Mr. Gallus was Director, Trading and Risk Management from January 1996 to September 1996; Director, Product Development from September 1996 to April 1997; Vice President, Structured Products from April 1997 to May 1998; Senior Vice President, Trading, from May 1998 to August 1998 for LG&E Energy Marketing Inc.; and Vice President, Energy Marketing from August 1998 to December 2000 for LG&E Energy Corp.

 

Before he was elected to his current positions, Mr. Smith was Head of Construction Projects - Powergen from January 1996 to May 1999; Director of Projects - Powergen from May 1999 to December 1999; and Director of Engineering Projects for Powergen International from January 2000 to December 2000.

 

Before he was elected to his current positions, Mr. Vogel served in management positions within the Distribution organization of LG&E and KU prior to December 2000.  In his position prior to his current role he was responsible for statewide outage management and restoration of distribution network.

 

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

 

Before he was elected to his current positions, Mr. Hamilton was Venture Manager from May 1992 to December 1995; Senior Venture Manager from December 1995 to September 1997, and Vice President, Asset Management from September 1997 to December 2000.

 

Before he was elected to his current positions, Mr. Henriques was Senior Venture Manager for LG&E Power Inc. from May 1993 to September 1995, and Vice President-Plant Operations from September 1995 to September 2001.

 

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

 

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

 

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

 

Before he was elected to his current positions, Mr. Bowling was Plant General Manager at Western Kentucky Energy Corp. 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 1998 to January 1999.  He joined LG&E Energy Corp. 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.

 

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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:

 

		Summer Capability Rating (Kw)
Steam Stations:
Mill Creek - Kosmosdale, KY
Unit 1		308,000
Unit 2		306,000
Unit 3		391,000
Unit 4		480,000
Total Mill Creek		1,485,000
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		386,000
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)		189,000
Trimble County – Bedford, KY(d)		90,000
Total combustion turbine generators		448,000
Total capability rating		2,882,000

 

(a)	Amount shown represents LG&E’s 75% interest in Trimble County 1.  See Notes 11 and 12 of LG&E’s Notes to Financial Statements under Item 8 for further discussion on ownership.
(b)	Amount shown represents LG&E’s 53% interest in Paddy’s Run Unit 13 and 100% ownership of two other Paddy’s Run CTs.  See Notes 11 and 12 of LG&E’s Notes to Financial Statement, under Item 8 for further discussion on ownership.
(c)	Amount shown represents LG&E’s 53% interest in Unit 5 and 38% interest in Units 6 and 7 at E.W. Brown.  See Notes 11 and 12 of LG&E’s Notes to Financial Statements, under Item 8 for further discussion on ownership.  KU operates the units on behalf of LG&E.
(d)	Amount shown represents LG&E’s 29% interest in Units 5 and 6 at Trimble County.  See Notes 11 and 12 of LG&E’s Notes to Financial Statements, under Item 8 for further discussion on ownership.

 

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

 

At December 31, 2002, LG&E’s electric transmission system included 21 substations with a total capacity of

 

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approximately 11,519,700 Kva and approximately 656 structure miles of lines.  The electric distribution system included 84 substations with a total capacity of approximately 3,448,730 Kva, 3,761 structure miles of overhead lines and 379 miles of underground conduit.

 

LG&E’s gas transmission system includes 212 miles of transmission mains, and the gas distribution system includes 4,066 miles of distribution mains.

 

LG&E operates underground gas storage facilities with a current working gas capacity of approximately 15.1 million Mcf.  See Gas Supply under Item 1.

 

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

 

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

 

The trust indenture securing LG&E’s First Mortgage Bonds constitutes a direct first mortgage lien upon much of the property owned by LG&E.

 

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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:

 

		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 1		22,000
Unit 2		22,000
Unit 3		68,000
Unit 4		100,000
Total Green River		212,000
E.W. Brown – Burgin, KY
Unit 1		104,000
Unit 2		168,000
Unit 3		429,000
Total E.W. Brown		701,000
Ghent – Ghent, KY
Unit 1		509,000
Unit 2		494,000
Unit 3		496,000
Unit 4		467,000
Total Ghent		1,966,000
Combustion Turbine Generators (Peaking capability):
E.W. Brown – Burgin, KY (Units 5-11)(a)		773,000
Haefling – Lexington, KY		36,000
Paddy’s Run – Louisville, KY(b)		74,000
Trimble County-Bedford, KY(c)		220,000
Total combustion turbine generators		1,103,000
Total capability rating		4,111,000

 

(a)	Amount shown represents KU’s 47% interest in Unit 5, 62% interest in Units 6 and 7 and 100% of four other units at E.W. Brown. See Notes 11 and 12 of KU’s Notes to Financial Statements, under Item 8 for further discussion on ownership.
(b)	Amount shown represents KU’s 47% interest in Unit 13 at Paddy’s Run.  See Notes 11 and 12 of KU’s Notes to Financial Statements, under Item 8 for further discussion on ownership.  LG&E operates this unit on behalf of KU.
(c)	Amount shown represents KU’s 71% interest in Units 5 and 6 at Trimble County.  See Notes 11 and 12 of KU’s Notes to Financial Statements, under Item 8 for further discussion on ownership.  LG&E operates these units on behalf of KU.

 

KU also owns a 24 Mw hydroelectric generating station located in Burgin, Kentucky (Dix Dam), operated under a license issued by the FERC.

 

At December 31, 2002, KU’s electric transmission system included 112 substations with a total capacity of approximately 14,855,396 Kva and approximately 4,229 structure miles of lines.  The electric distribution system included 464 substations with a total capacity of approximately 5,046,335 Kva and 15,036 structure

 

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miles of lines.

 

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

 

Substantially all properties are subject to the lien of KU’s Mortgage Indenture.

 

ITEM 3.  Legal Proceedings.

 

Rates and Regulatory Matters

 

For a discussion of current rate and regulatory matters, including (a) environmental surcharge and cost recovery proceedings, (b) fuel adjustment and gas supply clause proceedings,  (c) earnings sharing mechanism extension proceedings, (d) merger surcredit proceedings and (e) other rate or regulatory matters affecting LG&E and KU, see Rates and Regulation under Item 7 and Note 3 of LG&E’s Notes to Financial Statements and Note 3 of KU’s Notes to Financial Statements under Item 8.

 

Environmental

 

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

 

LG&E Employment Discrimination Case

 

In October 2001 approximately 30 employees or former employees filed a complaint against LG&E claiming past and current instances of employment discrimination against LG&E.  LG&E has removed the case to the U.S. District Court for the Western District of Kentucky and filed an answer denying all plaintiff’s claims.  Discovery has commenced in the matter.  The court has ordered mediation and certain plaintiffs have settled for non-material amounts as a result of that process.  In addition, certain plaintiffs have sought administrative review before the U.S. Equal Employment Opportunity Commission which has, to date, declined to proceed to litigation on any claims reviewed.  Amended pleadings have also reduced the size of the plaintiff and defendant groups and eliminated certain prior demands.  The amended complaints included a reduced claimed damage amount of $100 million as well as requests for injunctive relief.  LG&E intends to defend itself vigorously in the action and management does not anticipate that the outcome will have a material impact on LG&E’s operations or financial condition.

 

Combustion Turbine Litigation

 

In September 2002, LG&E and KU, or their affiliates, filed further amended complaints in litigation in the U.S. District Court for the Eastern District of Kentucky against Alstom Power, Inc. (formerly ABB Power Generation, Inc.) (“Alstom”) regarding two combustion turbines supplied by Alstom in 1999.  These units are installed at KU’s E.W. Brown generating plant and are jointly owned by LG&E and KU.  The original purchase price for the turbines was approximately $91.8 million.  The suit presents warranty, negligence, misrepresentation, fraud and other claims relating to numerous operational defects or deficiencies in connection therewith.  LG&E and KU have requested rescission of the contract and recovery of all expenditures relating to the

 

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turbines.  As an alternative to rescission, LG&E and KU have requested relief for amounts incurred or expended to date in connection with operational repairs, cover damages or liquidated damages and other costs, with possible further damages and interest to be proven at trial. The matter is currently in discovery with a trial presently scheduled for the third quarter of 2003.

 

Preferred Stock Delisting

 

On April 16, 2002, the LG&E 5% Cumulative Preferred class of stock was delisted from the NASDAQ Small Capitalization Market.  On June 3, 2002, the KU 4.75% Cumulative Preferred class of stock was delisted from the Philadelphia Stock Exchange.  Delisting will enable the Companies to realize certain administrative and corporate governance efficiencies.

 

Other

 

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

 

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

 

a)                                      LG&E’s and KU’s Annual Meetings of Shareholders were held on December 19, 2002.

 

b)                                     Not applicable.

 

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

 

1.          LG&E

 

i)		The shareholders voted to elect LG&E’s nominees for election to the Board of Directors, as follows:
		Michael Söhlke - 21,294,223 common shares and 114,107 preferred shares cast in favor of election and 1,979 preferred shares withheld.
		Victor A. Staffieri - 21,294,223 common shares and 113,207 preferred shares cast in favor of election and 2,879 preferred shares withheld.
		Edmund A. Wallis - 21,294,223 common shares and 114,246 preferred shares cast in favor of election and 1,840 preferred shares withheld.
		No holders of common or preferred shares abstained from voting on this matter.
ii)		The shareholders voted 21,294,223 common shares and 113,801 preferred shares in favor of and 331 preferred shares against the approval of PricewaterhouseCoopers LLP as independent accountants for 2002.  Holders of 1,954 preferred shares abstained from voting on this matter.

 

2.   KU

 

i)		The sole shareholder voted to elect KU’s nominees for election to the Board of Directors, as follows:
		37,817,878 common shares cast in favor of election and no shares withheld for each of Michael Söhlke, Victor A. Staffieri and  Edmund A. Wallis,  respectively.
ii)		The sole shareholder voted 37,817,878 common shares in favor of and no shares withheld for approval of PricewaterhouseCoopers LLP as independent accountants for 2002.
		No holders of common shares abstained from voting on these matters.

d)                                     Not applicable.

PART II.

 

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

 

LG&E:

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

 

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for LG&E’s common stock.

 

The following table sets forth LG&E’s cash distributions on common stock paid to LG&E Energy (in thousands of $):

 

		2002			2001
First quarter		$	0		$	0
Second quarter		23,000			0
Third quarter		23,000			0
Fourth quarter		23,000			23,000

 

KU:

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

 

The following table sets forth KU’s cash distributions on common stock paid to LG&E Energy (in thousands of $):

 

		2002			2001
First quarter		$	0		$	0
Second quarter		0			0
Third quarter		0			0
Fourth quarter		0			30,500

 

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ITEM 6.  Selected Financial Data.

 

The Consolidated Financial Statements for 1998 through 2000 for LG&E and KU were audited by Arthur Andersen LLP (Andersen) who has ceased operations.  A copy of the report previously issued by Andersen on our financial statements for the year ended December 31, 2000, is included elsewhere in this report.  Such report has not been reissued by Andersen.

 

		Years Ended December 31 (Thousands of $)
		2002			2001			2000			1999			1998
LG&E:
Operating revenues:
Revenues		$	1,013,917		$	997,420		$	985,947		$	969,984		$	854,556
Provision for rate collections (refunds)		12,267			(720		)	(2,500		)	(1,735		)	(4,500		)
Total operating revenues		1,026,184			996,700			983,447			968,249			850,056
Net operating income		117,914			141,773			148,870			140,091			135,523
Net income		88,929			106,781			110,573			106,270			78,120
Net income available for common stock		84,683			102,042			105,363			101,769			73,552
Total assets		2,561,078			2,448,354			2,226,084			2,171,452			2,104,637
Long-term obligations (including amounts due within one year)		$	616,904		$	616,904		$	606,800		$	626,800		$	626,800

 

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

 

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		Years Ended December 31 (Thousands of $)
		2002			2001			2000			1999			1998
KU:
Operating revenues:
Revenues		$	875,192		$	860,426		$	851,941		$	943,210		$	831,614
Provision for rate collections (refunds)		13,027			(954		)	—			(5,900		)	(21,500		)
Total operating revenues		888,219			859,472			851,941			937,310			810,114
Net operating income		108,643			121,370			128,136			136,016			125,388
Net income		93,384			96,414			95,524			106,558			72,764
Net income available for common stock		91,128			94,158			93,268			104,302			70,508
Total assets		1,998,383			1,826,902			1,739,518			1,785,090			1,761,201
Long-term obligations (including amounts due within one year)		$	500,492		$	488,506		$	484,830		$	546,330		$	546,330

 

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

 

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

 

LG&E:

 

GENERAL

 

The following discussion and analysis by management focuses on those factors that had a material effect on LG&E’s financial results of operations and financial condition during 2002, 2001, and 2000 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 reports to the SEC, including Exhibit No. 99.01 to this report on Form 10-K.

 

MERGERS and ACQUISITIONS

 

On December 11, 2000, LG&E Energy was acquired by Powergen for cash of approximately $3.2 billion or $24.85 per share and the assumption of all of LG&E Energy’s debt.  As a result of the acquisition, LG&E Energy became a wholly owned subsidiary of Powergen and, as a result, LG&E became an indirect subsidiary of Powergen.  LG&E has continued its separate identity and serves customers in Kentucky under its existing

 

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name.  The preferred stock and debt securities of LG&E were not affected by this transaction and LG&E continues to file SEC reports. Following the acquisition, Powergen became a registered holding company under PUHCA, and LG&E, as a subsidiary of a registered holding company, became subject to additional regulation under PUHCA.  See “Rates and Regulation” under Item 1.

 

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

 

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

 

RESULTS OF OPERATIONS

 

Net Income

 

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

 

LG&E’s net income decreased $3.8 million for 2001, as compared to 2000.  This decrease is mainly due to higher pension related expenses and amortization of VDT regulatory asset, partially offset by increased electric and gas net revenues (operating revenues less fuel for electric generation, power purchased and gas supply expenses) and decreased interest expenses.

 

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Revenues

 

A comparison of operating revenues for the years 2002 and 2001, excluding the provisions recorded for rate collections (refunds), with the immediately preceding year reflects both increases and decreases, which have been segregated by the following principal causes (in thousands of $):

 

		Increase (Decrease) From Prior Period
		Electric Revenues						Gas Revenues
Cause		2002			2001			2002			2001
Retail sales:
Fuel and gas supply adjustments		$	19,449		$	(394	)	$	(58,003	)	$	79,627
LG&E/KU Merger surcredit		(2,825		)	(2,456		)	—			—
Performance based rate		—			1,962			—			—
Environmental cost recovery surcharge		9,694			1,246			—			—
Demand side management		1,381			—			938			—
Electric rate reduction		—			(3,671		)	—			—
VDT surcredit		(1,177		)	(1,014		)	(285		)	(68		)
Gas rate increase		—			—			—			15,265
Weather normalization		—			—			2,234			—
Variation in sales volumes and other		24,819			4,429			21,658			(64,817		)
Total retail sales		51,341			102			(33,458		)	30,007
Wholesale sales		(16,404		)	(5,674		)	10,683			(11,642		)
Gas transportation-net		—			—			189			(880		)
Other		4,642			(1,241		)	(496		)	801
Total		$	39,579		$	(6,813	)	$	(23,082	)	$	18,286

 

Electric revenues increased in 2002 primarily due to an increase in retail sales due to warmer summer weather, an increase in the recovery of fuel costs passed through the FAC, partially offset by a decrease in wholesale sales due to lower market prices as compared to 2001. Cooling degree days increased 20% compared to 2001.  Electric revenues decreased in 2001 primarily due to a decrease in brokered activity in the wholesale electric sales market, an electric rate reduction ordered by the Kentucky Commission and the effects of the LG&E/KU merger surcredit (See Note 2 of LG&E’s  Notes to Financial Statements under Item 8) partially offset by an increase in electric retail sales. In January 2000, the Kentucky Commission ordered an electric rate reduction and the termination of LG&E’s proposed electric PBR mechanism.

 

Gas revenues in 2002 decreased due to a lower gas supply cost billed to customers through the gas supply clause offset partially by increased gas retail sales due to cooler winter weather and an increase in wholesale sales volume.  Heating degree days increased 17% as compared to 2001.  Gas revenues in 2001 increased primarily as a result of higher gas supply costs billed to customers through the gas supply clause and the effects of a gas rate increase ordered by the Kentucky Commission in September 2000.  The gas revenue increase was partially offset by a decrease in retail and wholesale gas sales in 2001 due to warmer weather.  Heating degree days decreased 10.2% compared to 2000.

 

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

 

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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 $35.7 million (22.4%) in 2002 due to increased generation ($5.4 million) and  higher cost of coal burned ($30.3 million). Fuel for electric generation decreased $0.2 million (.1%) in 2001 primarily due to decreased generation as a result of decreased electric sales ($2.2 million) partially offset by a higher cost of coal burned ($2.0 million). The average delivered cost per ton of coal purchased was $25.30 in 2002, $21.27 in 2001 and $20.96 in 2000.

 

Power purchased increased $2.9 million (3.5%) in 2002 due to an increase in purchases to meet requirements for native load and off-system sales partially offset by decreased brokered sales activity in the wholesale electric market. Power purchased decreased $15.4 million (15.9%) in 2001 primarily due to decreased brokered sales activity in the wholesale electric market and a lower unit cost of the purchases partially offset by an increase in purchases to meet requirements for native load and off-system sales.

 

Gas supply expenses decreased $24.1 million (11.7%) in 2002 due to a decrease in cost of net gas supply ($36.6 million), partially offset by an increase in the volume of gas delivered to the distribution system ($12.5 million). Gas supply expenses increased $9.3 million (4.7%) in 2001 primarily due to an increase in cost of net gas supply ($36.2 million), partially offset by a decrease in the volume of gas delivered to the distribution system ($26.9 million). The average unit cost per Mcf of purchased gas was $4.19 in 2002, $5.27 in 2001 and $5.08 in 2000.

 

Other operation expenses increased $40.5 million (24.1%) in 2002 primarily due to a full year amortization in 2002 of a regulatory asset created as a result of the workforce reduction costs associated with LG&E’s VDT ($17.0 million), higher costs for electric transmission primarily resulting from increased MISO costs ($13.9 million), an increase in property and other insurance costs ($3.9 million), an increase in pension costs due to change in pension assumptions to reflect current market conditions and change in market value of the plan assets at the measurement date ($3.7 million), and an increase in steam production costs ($3.4 million).  Other operation expenses increased $31.9 million (23.4%) in 2001 primarily due to amortization of a regulatory asset resulting from workforce reduction costs associated with LG&E’s VDT ($13.0 million), an increase in pension expense  ($10.3 million) and an increase in outside services ($8.5 million). Outside services increased in part due to the reclassification of expenses as a result of the formation of LG&E Services, as required by the SEC to comply with PUHCA.

 

Maintenance expenses for 2002 increased $1.5 million (2.6%) primarily due to gas distribution expenses for main remediation work ($2.2 million).  Maintenance expenses for 2001 decreased $5.0 million (7.9%) primarily due to decreases in scheduled outages ($2.8 million), and a decrease in software and communication equipment maintenance ($2.8 million).

 

Depreciation and amortization increased $5.5 million (5.5%) in 2002 and $2.1 million (2.1%) in 2001 because of additional utility plant in service. The 2001 increase was offset by a decrease in depreciation rates resulting from a settlement order in December 2001 from the Kentucky Commission.  Depreciation expenses decreased $5.6 million as a result of the settlement order.

 

Variations in income tax expenses are largely attributable to changes in pre-tax income. LG&E’s 2002 effective income tax rate increased to 37.2% from the 36.5% rate in 2001. See Note 7 of LG&E’s Notes to Financial Statements under Item 8.

 

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Property and other taxes decreased $0.3 million (1.6%) in 2002. Property and other taxes decreased $1.2 million (6.5%) in 2001 primarily due to a reduction in payroll taxes related to fewer employees as a result of workforce reductions and transfers to LG&E Services.

 

Other income – net decreased $2.1 million (72.0%) in 2002 primarily due to increased  costs for non-utility areas, $1.3 million and decreases in the gain on sale of property $0.8 million. Other income – net decreased $2.0 million (40.5%) in 2001 primarily due to lower interest and dividend income.

 

Interest charges for 2002 decreased $8.1 million (21.4%) primarily due to lower interest rates on variable rate debt ($5.6 million) a decrease in debt to associated companies ($0.8 million) and an decrease in interest associated with LG&E’s accounts receivable securitization program ($1.5 million).  Interest charges for 2001 decreased $5.3 million (12.2%) primarily due to lower interest rates on variable rate debt ($2.2 million) and the retirement of short-term borrowings ($8.1 million) partially offset by an increase in debt to associated companies ($2.5 million) and an increase in interest associated with LG&E’s accounts receivable securitization program ($2.5 million). See Note 9 of LG&E’s Notes to Financial Statements under Item 8.

 

LG&E’s weighted average cost of long-term debt, including amortization of debt expense and interest rate swaps, was 3.87% at December 31, 2002 compared to 4.17% at December 31, 2001.  See Note 9 of LG&E’s Notes to Financial Statements under Item 8.

 

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

 

CRITICAL ACCOUNTING POLICIES/ESTIMATES

 

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

 

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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 known weather and days not billed.  At December 31, 2002, a 10% change in these estimated quantities would cause revenue and accounts receivable to change by approximately $5.0 million, including $2.3 million for electric usage and $2.7 million for gas usage.  See also Note 1 of LG&E’s Notes to Financial Statements under Item 8.

 

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

 

LG&E’s costs of providing defined-benefit pension retirement plans is dependent upon a number of factors, such as the rates of return on plan assets, discount rate, and contributions made to the plan.  The market value of LG&E plan assets has been affected by declines in the equity market since the beginning of the fiscal year.  As a result, at December 31, 2002, LG&E was required to recognize an additional minimum liability as prescribed by SFAS No. 87 Employers’ Accounting for Pensions.  The liability was recorded as a reduction to other comprehensive income, and did not affect net income for 2002.  The amount of the liability depended upon the asset returns experienced in 2002 and contributions made by LG&E to the plan during 2002.  Also, pension cost and cash contributions to the plan could increase in future years without a substantial recovery in the equity market.  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.

 

The combination of poor market performance and a decrease in short-term corporate bond interest rates has created a divergence in the potential value of the pension liability and the actual value of the pension assets.  These conditions could result in an increase in LG&E’s funded accumulated benefit obligation and future pension expense.  The primary assumptions that drive the value of the unfunded accumulated benefit obligation are the discount rate and expected return on plan assets.

 

LG&E made a contribution to the pension plan of $83.1 million in January 2003.

 

A 1% increase or decrease in the assumed discount rate could have an approximate $37.0 million positive or negative impact to the accumulated benefit obligation of LG&E.

 

See also Note 6 of LG&E’s Notes to Financial Statements under Item 8.

 

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

 

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

 

LG&E has accrued in the financial statements an estimate of $12.5 million for 2002 ESM, with collection from

 

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customer commencing in April 2003.  The ESM is subject to Kentucky Commission approval.

 

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

 

NEW ACCOUNTING PRONOUNCEMENTS

 

The following accounting pronouncements were issued that affected LG&E in 2002:

 

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 is January 1, 2003.  Management has calculated the impact of SFAS No. 143 and the recently released FERC NOPR No. RM02-7, Accounting, Financial Reporting, and Rate Filing Requirements for Asset Retirement Obligations.  As of January 1, 2003, LG&E recorded asset retirement obligation (ARO) assets in the amount of $4.6 million and  liabilities in the amount of $9.3 million. LG&E also recorded a cumulative effect adjustment in the amount of $5.3 million to reflect the accumulated depreciation and accretion of ARO assets at the transition date less amounts previously accrued under regulatory depreciation.  LG&E recorded offsetting regulatory assets of $5.3 million, pursuant to regulatory treatment prescribed under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. Also pursuant to SFAS No. 71, LG&E recorded regulatory liabilities in the amount of $60,000 offsetting removal costs previously accrued under regulatory accounting in excess of amounts allowed under SFAS No. 143.

 

LG&E also expects to record ARO accretion expense of approximately $617,000, ARO depreciation expense of approximately $117,000 and an offsetting regulatory credit in the income statement of approximately $734,000 in 2003, pursuant to regulatory treatment prescribed under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation.  The accretion, depreciation and regulatory credit will be annual adjustments.  SFAS No. 143 will have no impact on the results of the operation of LG&E.

 

LG&E’s asset retirement obligations are primarily related to the final retirement of generating units.  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 will be recorded for transmission and distribution assets.

 

LG&E adopted EITF No. 98-10, Accounting for Energy Trading and Risk Management Activities, effective January 1, 1999.  This pronouncement required that energy trading contracts be marked to market on the balance sheet, with the gains and losses shown net in the income statement.  In October 2002, the Emerging Issues Task Force reached a consensus to rescind EITF 98-10.  The effective date for the full rescission is for fiscal periods beginning after December 15, 2002.  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.  LG&E does not expect the rescission of this standard to have a material impact on financial position or results of operations.

 

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In January 2003, the Financial Accounting Standards Board issued Financial Accounting Standards Board Interpretation No. 46, Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51 (FIN 46).  FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties.  FIN 46 is 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 be applied for the first interim or annual period beginning after June 15, 2003.  LG&E does not expect the adoption of this standard to have any impact on the financial position or results of operations.

 

LIQUIDITY AND CAPITAL RESOURCES

 

LG&E uses net cash generated from its operations and external financing to fund construction of plant and equipment and the payment of dividends.  LG&E believes that such sources of funds will be sufficient to meet the needs of its business in the foreseeable future.

 

Operating Activities

 

Cash provided by operations was $212.4 million, $287.1 million and $156.2 million in 2002, 2001, and 2000, respectively.  The 2002 decrease compared to 2001 of $74.7 million resulted primarily from the change in accounts receivable balances, including the sale of accounts receivable through the accounts receivable securitization program and a decrease in accounts payable and accrued taxes.  The 2001 increase of $130.9 million resulted primarily from an increase in accounts receivable, and a decrease in accrued taxes.  See Note 1 of LG&E’s Notes to Financial Statements under Item 8 for a discussion of accounts receivable securitization.

 

Investing Activities

 

LG&E’s primary use of funds for investing activities continues to be for capital expenditures.  Capital expenditures were $220.4 million, $253.0 million and $144.2 million in 2002, 2001, and 2000, respectively.  LG&E expects its capital expenditures for 2003 and 2004 to total approximately $340.0 million, which consists primarily of construction estimates associated with installation of NOx equipment as described in the section titled “Environmental Matters,” purchase of jointly owned CTs with KU and on-going construction for the distribution systems.

 

Net cash used for investment activities decreased $28.7 million in 2002 compared to 2001 primarily due to the level of construction expenditures.  CT expenditures were approximately $35.9 million in 2002 and $57.8 million in 2001.  The $107.9 million increase in net cash used in 2001 as compared to 2000 was due to NOx expenditures and the purchase of CTs.

 

Financing Activities

 

Net cash inflows for financing activities were $22.5 million in 2002 and outflows of $38.7 million and $67.7 million in 2001 and 2000, respectively.  In 2002, short-term borrowings increased $98.9 million which were used in part for dividend payments of $73.3 million.  During 2001, short-term borrowings decreased $20.4 million from 2000 and LG&E paid $28.0 million in dividends.

 

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

 

On March 6, 2002, LG&E refinanced its $22.5 million and $27.5 million unsecured pollution control bonds, both due September 1, 2026.  The replacement bonds, due September 1, 2026, are variable rate bonds and are secured by first mortgage bonds.

 

On March 22, 2002, LG&E refinanced its two $35 million unsecured pollution control bonds due November 1, 2027.  The replacement variable rate bonds are secured by first mortgage bonds and will mature November 1, 2027.

 

In October 2002, LG&E issued $41.7 million variable rate pollution 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 for LG&E’s variable-rate pollution control bonds totaling $246.2 million, the bonds are subject to tender for purchase at the option of the holder and to mandatory tender for purchase upon the occurrence of certain events, causing the bonds to be classified as current portion of long-term debt.

 

Future Capital Requirements

 

Future capital requirements may be affected in varying degrees by factors such as load growth, changes in construction expenditure levels, rate actions by regulatory agencies, new legislation, market entry of competing electric power generators, changes in environmental regulations and other regulatory requirements.  LG&E anticipates funding future capital requirements through operating cash flow, debt, and/or infusions of capital from its parent.

 

LG&E’s debt ratings as of December 31, 2002, were:

 

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

 

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

 

Contractual Obligations

 

The following is provided to summarize LG&E’s contractual cash obligations for periods after December 31, 2002 (in thousands of $):

 

		Payments Due by Period
Contractual cash Obligations		2003			2004- 2005			2006- 2007			After 2007			Total
Short-term debt(a)		$	193,053		$	—		$	—		$	—		$	193,053
Long-term debt(b)		288,800			—			—			328,104			616,904
Operating lease(c)		3,371			6,866			7,143			29,794			47,174
Unconditional purchase obligations(d)		10,773			20,268			21,632			184,544			237,217
Other long-term obligations(e)		28,401			95,151			—			—			123,552
Total contractual cash obligations(f)		$	524,398		$	122,285		$	28,775		$	542,442		$	1,217,900

 

(a)                                  Represents borrowings from parent 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 2017 to 2027.

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

(d)                                 Represents future minimum payments under purchased power agreements through 2020.

(e)                                  Represents construction commitments.

(f)                                    LG&E does not expect to pay the $246.2 million of long-term debt classified as a current liability in the consolidated balance sheets in 2003 as explained in (b) above.  LG&E anticipates cash from operations and external financing will be sufficient to fund future obligations.  LG&E anticipates refinancing a portion of its short-term debt with long-term debt in 2003.

 

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Market Risks

 

LG&E is exposed to market risks from changes in interest rates and commodity prices.  To mitigate changes in cash flows attributable to these exposures, LG&E uses various financial instruments including derivatives.  Derivative positions are monitored using techniques that include market value and sensitivity analysis.

See Note 1 and 4 of LG&E’s Notes to Financial Statements under Item 8.

 

Interest Rate Sensitivity

 

LG&E has short-term and long-term variable rate debt obligations outstanding.  At December 31, 2002, the potential change in interest expense associated with a 1% change in base interest rates of LG&E’s unhedged debt is estimated at $5.5 million after 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, 2002, LG&E had swaps with a combined notional value of $117.3 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 $10.8 million as of December 31, 2002.  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.

 

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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 EITF 98-10 Accounting for Contracts Involved in Energy Trading and Risk Management Activities, SFAS No. 133 Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138 Accounting for Certain Derivative Instruments and Certain Hedging Activities.  Wholesale sales of excess asset capacity and wholesale purchases are treated as normal sales and purchases under SFAS No. 133 and SFAS No. 138 and are not marked-to-market.

 

The rescission of EITF 98-10, effective for fiscal periods ending after December 15, 2002, will have no impact on LG&E’s energy trading and risk management reporting as all contracts marked to market under EITF 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 2002 and 2001 (in thousands of $).

 

		2002			2001
Fair value of contracts at beginning of period, net liability		$	(186	)	$	(17	)
Fair value of contracts when entered into during the period		(65		)	3,441
Contracts realized or otherwise settled during the period		448			(2,894		)
Changes in fair values due to changes in assumptions		(353		)	(716		)
Fair value of contracts at end of period, net liability		$	(156	)	$	(186	)

 

No changes to valuation techniques for energy trading and risk management activities occurred during 2002.  Changes in market pricing, interest rate and volatility assumptions were made during both years.  All contracts outstanding at December 31, 2002, 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, 2002, 86% of the trading and risk management commitments were with counterparties rated BBB- equivalent or better.

 

Accounts Receivable Securitization

 

On February 6, 2001, LG&E implemented an accounts receivable securitization program.  The purpose of this program is to enable LG&E to accelerate the receipt of cash from the collection of retail accounts receivable, thereby reducing dependence upon more costly sources of working capital.  The securitization program allows for a percentage of eligible receivables to be sold.  Eligible receivables are generally all receivables associated with retail sales that have standard terms and are not past due.  LG&E is able to terminate the program at any time without penalty.  If there is a significant deterioration in the payment record of the receivables by the retail

 

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customers or if LG&E fails to meet certain covenants regarding the program, the program may terminate at the election of the financial institutions.  In this case, payments from retail customers would first be used to repay the financial institutions participating in the program, and would then be available for use by LG&E.

 

As part of the program, LG&E sold retail accounts receivables to a wholly owned subsidiary, LG&E R.  Simultaneously, LG&E R entered into two separate three-year accounts receivable securitization facilities with two financial institutions and their affiliates whereby LG&E R can sell, on a revolving basis, an undivided interest in certain of its receivables and receive up to $75 million from an unrelated third party purchaser.  The effective cost of the receivables programs is comparable to LG&E’s lowest cost source of capital, and is based on prime rated commercial paper. LG&E retains servicing rights of the sold receivables through two separate servicing agreements with the third party purchaser.  LG&E has obtained an opinion from independent legal counsel indicating these transactions qualify as a true sale of receivables.  As of December 31, 2002, the outstanding program balance was $63.2 million.  LG&E is considering unwinding its accounts receivable securitization arrangements involving LG&E R during 2003.

 

The allowance for doubtful accounts associated with the eligible securitized receivables was $2.1 million at December 31, 2002.  This allowance is based on historical experience of LG&E. Each securitization facility contains a fully funded reserve for uncollectible receivables.

 

RATES AND REGULATION

 

Following the purchase of Powergen by E.ON, E.ON became a registered holding company under PUHCA.  As a result, E.ON, its utility subsidiaries, including LG&E, and certain of its non-utility subsidiaries are subject to extensive regulation by the SEC under PUHCA with respect to issuances and sales of securities, acquisitions and sales of certain utility properties, and intra-system sales of certain goods and services.  In addition, PUHCA generally limits the ability of registered holding companies to acquire additional public utility systems and to acquire and retain businesses unrelated to the utility operations of the holding company.  LG&E believes that it has adequate authority (including financing authority) under existing SEC orders and regulations to conduct its business.  LG&E will seek additional authorization when necessary.

 

LG&E is subject to the jurisdiction of the Kentucky Commission in virtually all matters related to electric and gas utility regulation, and as such, its accounting is subject to SFAS No. 71, Accounting for the Effects of Certain Types of Regulation.  Given LG&E’s competitive position in the marketplace and the status of regulation in the state of Kentucky, LG&E has no plans or intentions to discontinue its application of SFAS No. 71.  See Note 3 of LG&E’s Notes to Financial Statements under Item 8.

 

Kentucky Commission Settlement Order - VDT Costs, ESM and Depreciation

 

During the first quarter 2001, LG&E recorded a $144 million charge for a workforce reduction program.  Primary components of the charge were separation benefits, enhanced early retirement benefits, and health care benefits.  The result of this workforce reduction was the elimination of approximately 700 positions, accomplished primarily through a voluntary enhanced severance program.

 

On June 1, 2001, LG&E filed an application (VDT case) with the Kentucky Commission to create a regulatory asset relating to these first quarter 2001 charges.  The application requested permission to amortize these costs over a four-year period.  The Kentucky Commission also opened a case to review a new depreciation study and

 

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resulting depreciation rates implemented in 2001.

 

LG&E reached a settlement in the VDT case as well as the other cases involving depreciation rates and ESM with all intervening parties.  The settlement agreement was approved by Kentucky Commission Order on December 3, 2001.  The order allowed LG&E to set up a regulatory asset of $141 million for the workforce reduction costs and begin amortizing these costs over a five year period starting in April 2001.  The first quarter 2001 charge of $144 million represented all employees who had accepted a voluntary enhanced severance program.  Some employees rescinded their participation in the voluntary enhanced severance program, thereby decreasing the original charge from $144 million to $141 million.  The settlement will also reduce revenues approximately $26 million through a surcredit on future bills to customers over the same five year period.  The surcredit represents stipulated net savings LG&E is expected to realize from implementation of best practices through the VDT.  The agreement also established LG&E’s new depreciation rates in effect December 2001, retroactive to January 1, 2001.  The new depreciation rates decreased depreciation expense by $5.6 million in 2001.

 

Environmental Cost Recovery

 

In June 2000, the Kentucky Commission approved LG&E’s application for a CCN to construct up to three SCR NOx reduction facilities. The construction and subsequent operation of the SCRs is intended to reduce NOx emission levels to meet the EPA’s mandated NOx emission level of 0.15 lbs./ Mmbtu by May 2004.  In its order, the Kentucky Commission ruled that LG&E’s proposed plan for construction was “reasonable, cost-effective and will not result in the wasteful duplication of facilities.”  In October 2000, LG&E filed an application with the Kentucky Commission to amend its Environmental Compliance Plan to reflect the addition of the proposed NOx reduction technology projects and to amend its Environmental Cost Recovery Tariff to include an overall rate of return on capital investments. Approval of LG&E’s application in April 2001 allowed LG&E to begin to recover the costs associated with these new projects, subject to Kentucky Commission oversight during normal six-month and two-year reviews.

 

In May 2002, the Kentucky Commission initiated a periodic two year review of LG&E’s environmental surcharge.  The review included the operation of the surcharge mechanism, determination of the appropriateness of costs included in the surcharge mechanism, recalculation of the cost of debt to reflect actual costs for the period under review, final determination of the amount of environmental revenues over-collected from customers, and a final determination of the amount of environmental costs and revenues to be “rolled-in” to base rates.  A final order was issued on October 22, 2002, in which LG&E was ordered to refund $325,000 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 on a going-forward basis.

 

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.  The Kentucky Commission conducted a public hearing on the case on December 20, 2002, final briefs were filed on January 15, 2003, and a final order was issued February 11, 2003.  The final order approved recovery of four new environmental compliance facilities totaling $43.1 million.  A fifth project, expansion of the land fill facility at the Mill Creek Station, was denied without prejudice with an invitation to reapply for recovery when required construction permits are approved.  Cost

 

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recovery through the environmental surcharge of the four approved projects will begin with the bills rendered in April 2003.

 

ESM

 

LG&E’s electric rates are subject to an ESM.  The ESM, initially in place for three years beginning in 2000, sets an upper and lower point for rate of return on equity, whereby if LG&E’s rate of return for the calendar year falls within the range of 10.5% to 12.5%, no action is necessary.  If earnings are above the upper limit, the excess earnings are shared 40% with ratepayers and 60% with shareholders; if earnings are below the lower limit, the earnings deficiency is recovered 40% from ratepayers and 60% from shareholders.  By order of the Kentucky Commission, rate changes prompted by the ESM filing go into effect in April of each year subject to a balancing adjustment in successive periods.  LG&E made its second ESM filing on March 1, 2002, for the calendar year 2001 reporting period.  LG&E is in the process of refunding $441,000 to customers for the 2001 reporting period.  LG&E estimated that the rate of return will fall below the lower limit, subject to Kentucky Commission approval, for the year ended December 31, 2002.  The 2002 financial statements include an accrual to reflect the earnings deficiency of $12.5 million to be recovered from customers commencing in April 2003.

 

On November 27, 2002, LG&E filed a revised ESM tariff which proposed continuance of the existing ESM through December 2005.  The Kentucky Commission issued an Order suspending the ESM tariff one day making the effective date January 2, 2003.  In addition, the Kentucky Commission is conducting a management audit to review the ESM plan and reassess its reasonableness in 2003.  LG&E and interested parties will have the opportunity to provide recommendations for modification and continuance of the ESM or other forms of alternative or incentive regulation.

 

DSM

 

LG&E’s rates contain a DSM provision.  The provision includes a rate mechanism that provides concurrent recovery of DSM costs and provides an incentive for implementing DSM programs.  This program had allowed LG&E to recover revenues from lost sales associated with the DSM program.  In May 2001, the Kentucky Commission approved LG&E’s plan to continue DSM programs.  This filing called for the expansion of the DSM programs into the service territory served by KU and proposed a mechanism to recover revenues from lost sales associated with DSM programs based on program planning engineering estimates and post-implementation evaluation.

 

Gas PBR

 

Since November 1, 1997, LG&E has operated under an experimental PBR mechanism related to its gas procurement activities.   For each of the last five years, LG&E’s rates have been adjusted to recover its portion of the savings (or expenses) incurred during each of the five 12-month periods beginning November 1 and ending October 31. Since its implementation on November 1, 1997, through October 31, 2002, LG&E has achieved $38.1 million in savings. Of the total savings, LG&E has retained $16.5 million, and the remaining portion of $21.6 million has been distributed to customers.  In December 2000, LG&E filed an application reporting on the operation of the experimental PBR and requested the Kentucky Commission to extend the PBR as a result of the benefits provided to both LG&E and its customers during the experimental period. Following the discovery and hearing process, the Kentucky Commission issued an order effective November 1, 2001, extending the experimental PBR program for an additional four years, and making other modifications,

 

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including changes to the sharing levels applicable to savings or expenses incurred under the PBR.  Specifically, the Kentucky Commission modified the sharing mechanism to a 25%/75% Company/Customer sharing for all savings (and expenses) up to 4.5% of the benchmarked gas costs.  Savings (and expenses) in excess of 4.5% of the benchmarked gas costs are shared at a 50%/50% level.

 

FAC

 

Prior to implementation of the electric PBR in July 1999, and following its termination in March 2000, LG&E employed an FAC mechanism, which under Kentucky law allowed LG&E to recover from customers the actual fuel costs associated with retail electric sales.  In February 1999, LG&E received orders from the Kentucky Commission requiring a refund to retail electric customers of approximately $3.9 million resulting from reviews of the FAC from November 1994, through April 1998.  While legal challenges to the Kentucky Commission order were pending a comprehensive settlement was reached by all parties and approved by the  Kentucky Commission on May 17, 2002.   Thereunder, LG&E agreed to credit its fuel clause in the amount of $720,000 (such credit provided over the course of June and July 2002), and the parties agreed on a prospective interpretation of the state’s fuel adjustment clause regulation to ensure consistent and mutually acceptable application on a going-forward basis.

 

In December 2002, the Kentucky Commission initiated a two year review of the operation of LG&E’s FAC for the period November 2000 through October 2002.  Testimony in the review case was filed on January 20, 2003 and a public hearing was held February 18, 2003.  Issues addressed at that time included the establishment of the current base fuel factor to be included in LG&E’s base rates, verification of proper treatment of purchased power costs during unit outages, and compliance with fuel procurement policies and practices.

 

Gas Rate Case

 

In March 2000, LG&E filed an application with the Kentucky Commission requesting an adjustment in LG&E’s gas rates.  In September 2000, the Kentucky Commission granted LG&E an annual increase in its base gas revenues of $20.2 million effective September 28, 2000.  The Kentucky Commission authorized a return on equity of 11.25%.  The Kentucky Commission approved LG&E’s proposal for a weather normalization billing adjustment mechanism that will normalize the effect of weather on base gas revenues from gas sales.

 

Wholesale Natural Gas Prices

 

On September 12, 2000, the Kentucky Commission issued an order establishing Administrative Case No. 384 – “An Investigation of Increasing Wholesale Natural Gas Prices and the Impacts of such Increase on the Retail Customers Served by Kentucky’s Jurisdictional Natural Gas Distribution Companies”.  The impetus for this administrative proceeding was the escalation of wholesale natural gas prices during the summer of 2000.

 

The Kentucky Commission directed Kentucky’s natural gas distribution companies, including LG&E, to file selected information regarding the individual companies’ natural gas purchasing practices, expectations for the then-approaching winter heating season of 2000-2001, and potential actions which these companies might take to mitigate price volatility.  On July 17, 2001, the Kentucky Commission issued an order encouraging the natural gas distribution companies in Kentucky to take various actions, among them to propose a natural gas hedge plan, consider performance-based ratemaking mechanisms, and to increase the use of storage.

 

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In April 2002, in Case No. 2002-00136, LG&E proposed a hedging plan for the 2002/2003 winter heating season with three alternatives, the first two using a combination of storage and financial hedge instruments and the third relying upon storage alone.  LG&E and the Attorney General, who represents Kentucky consumers, entered into a settlement which selected the third option.  In August 2002, the Kentucky Commission approved the plan contemplated in the settlement.  The Kentucky Commission validated the effectiveness of storage to mitigate potentially high winter gas prices by approving this natural gas hedging plan.

 

The Kentucky Commission also decided in Administrative Case No. 384 to engage a consultant to conduct a forward-looking audit of the gas procurement and supply procedures of Kentucky’s largest natural gas distribution companies.  The Kentucky Commission completed its audit in late 2002.  The audit recognized LG&E as ”efficient and effective [in the] procurement and management of significant quantities of natural gas supplies.”  The auditors also recognized that “the Company’s residential gas prices have long been below averages for the U. S. and for the Commonwealth of Kentucky” which “demonstrates [LG&E’s] effectiveness in [the] procurement and management of natural gas supplies.”  The audit also stated that the ”Company’s very impressive record in keeping its rates down provides sound evidence on the excellent job done in the area of gas supply procurement and management.”

 

Kentucky Commission Administrative Case for Affiliate Transactions

 

In December 1997, the Kentucky Commission opened Administrative Case No. 369 to consider Kentucky Commission policy regarding cost allocations, affiliate transactions and codes of conduct governing the relationship between utilities and their non-utility operations and affiliates.  The Kentucky Commission intended to address two major areas in the proceedings: the tools and conditions needed to prevent cost shifting and cross-subsidization between regulated and non-utility operations; and whether a code of conduct should be established to assure that non-utility segments of the holding company are not engaged in practices that could result in unfair competition caused by cost shifting from the non-utility affiliate to the utility.  During the period September 1998 to February 2000, the Kentucky Commission issued draft codes of conduct and cost allocation guidelines.  In early 2000, the Kentucky General Assembly enacted legislation, House Bill 897, which authorized the Kentucky Commission to require utilities who provide nonregulated activities to keep separate accounts and allocate costs in accordance with procedures established by the Kentucky Commission.  In the same bill, the General Assembly set forth provisions to govern a 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.  On February 14, 2001, the Kentucky Commission published notice of their intent to promulgate new administrative regulations under the auspices of the new law.  This effort is still on going.

 

Kentucky Commission Administrative Case for System Adequacy

 

On June 19, 2001, Kentucky Governor Paul E. Patton issued Executive Order 2001-771, which directed the Kentucky Commission to review and study issues relating to the need for and development of new electric generating capacity in Kentucky.  The issues to be considered included the impact of new power plants on the electric supply grid, facility citing issues, and economic development matters, with the goal of ensuring a continued, reliable source of supply of electricity for the citizens of Kentucky and the continued environmental and economic vitality of Kentucky and its communities.  In response to that Executive Order, in July 2001 the

 

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Kentucky Commission opened Administrative Case No. 387 to review the adequacy of Kentucky’s generation capacity and transmission system.  Specifically, the items reviewed were the appropriate level of reliance on purchased power, the appropriate reserve margins to meet existing and future electric demand, the impact of spikes in natural gas prices on electric utility planning strategies, and the adequacy of Kentucky’s electric transmission facilities.  LG&E, as a party to this proceeding, filed written testimony and responded to two requests for information.  Public hearings were held and in October 2001, LG&E filed a final brief in the case.  In December 2001, the Kentucky Commission issued an order in which it noted that LG&E is responsibly addressing the long-term supply needs of native load customers and that current reserve margins are appropriate.  However, due to the rapid pace of change in the industry, the order also requires LG&E to provide an annual assessment of supply resources, future demand, reserve margin, and the need for new resources.

 

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

 

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

 

FERC SMD NOPR

 

On July 31, 2002, FERC issued a NOPR in Docket No. RM01-12-000 which would substantially alter the regulations governing the nation’s wholesale electricity markets by establishing a common set of rules — 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 a final rule is expected during 2003.  While it is expected that the SMD final rule will affect LG&E revenues and expenses, the specific impact of the rulemaking is not known at this time.

 

MISO

 

LG&E is a member of the MISO, which began commercial operations on February 1, 2002.  MISO now has operational control over LG&E’s high-voltage transmission facilities (100 kV and greater), while LG&E continues to control and operate the lower voltage transmission subject to the terms and conditions of the MISO OATT.  As a transmission-owning member of MISO, LG&E also incurs administrative costs of MISO pursuant to Schedule 10 of the MISO OATT.

 

MISO also proposed to implement a congestion management system.  FERC directed the MISO to coordinate its efforts with FERC’s Rulemaking on SMD. On September 24, 2002, the MISO filed new rate schedules designated as Schedules 16 and 17, which provide for the collection of costs incurred by the MISO to establish day-ahead and real-time energy markets. The MISO proposed to recover these costs under Schedules 16 and 17 once service commences. If approved by FERC, these schedules will cause LG&E to incur additional costs.  LG&E opposes the establishment of Schedules 16 and 17.  This effort is still on-going and the ultimate impact of the two schedules, if approved, is not known at this time.

 

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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 the Companies, 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 customers the then-projected non-fuel savings associated with the merger.  The Companies submitted this filing on January 13, 2003, proposing to continue to share with customers, on a 50%/50% basis, the estimated fifth-year gross level of non-fuel savings associated with the merger.  The filing is currently under review.

 

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

 

Environmental Matters

 

The Clean Air Act imposed stringent new SO2 and NOx emission limits on electric generating units.  LG&E previously had installed scrubbers on all of its generating units.  LG&E’s strategy for Phase II SO2 reductions, which commenced January 1, 2000, is to increase scrubber removal efficiency to delay additional capital expenditures and may also include fuel switching or upgrading scrubbers.  LG&E met the NOx emission requirements of the Act through installation of low-NOx burner systems.  LG&E’s compliance plans are subject to many factors including developments in the emission allowance and fuel markets, future regulatory and legislative initiatives, and advances in clean air control technology.  LG&E will continue to monitor these developments to ensure that its environmental obligations are met in the most efficient and cost-effective manner.

 

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

 

LG&E is currently implementing a plan for adding significant additional NOx controls to its generating units.  Installation of additional NOx controls will proceed on a phased basis, with installation of controls commencing

 

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in late 2000 and continuing through the final compliance date.  LG&E estimates that it will incur total capital costs of approximately $178 million to reduce its NOx emissions to the 0.15 lb./Mmbtu level on a company-wide basis.  In addition, LG&E will incur additional operating and maintenance costs in operating new NOx controls.  LG&E believes its costs in this regard to be comparable to those of similarly situated utilities with like generation assets.  LG&E had anticipated that such capital and operating costs are the type of costs that are eligible for recovery from customers under its environmental surcharge mechanism and believed that a significant portion of such costs could be recovered.  In April 2001, the Kentucky Commission granted recovery of these costs for LG&E.

 

LG&E is also monitoring several other air quality issues which may potentially impact coal-fired power plants, including the appeal of the D.C. Circuit’s remand of the EPA’s revised air quality standards for ozone and particulate matter, measures to implement EPA’s regional haze rule, and EPA’s December 2000 determination to regulate mercury emissions from power plants.  In addition, LG&E is currently working with local regulatory authorities to review the effectiveness of remedial measures aimed at controlling particulate matter emissions from its Mill Creek Station.  LG&E previously settled a number of property damage claims from adjacent residents and completed significant remedial measures as part of its ongoing capital construction program. LG&E is in the process of converting the Mill Creek Station to wet stack operation in an effort to resolve all outstanding issues related to particulate matter emissions.

 

LG&E owns or formerly owned three properties which are the location of past MGP operations.  Various contaminants are typically found at such former MGP sites and environmental remediation measures are frequently required.  With respect to the sites, LG&E has completed cleanups, obtained regulatory approval of site management plans, or reached agreements for other parties to assume responsibility for cleanup.  Based on currently available information, management estimates that it will incur additional costs of $400,000.  Accordingly, an accrual of $400,000 has been recorded in the accompanying financial statements at December 31, 2002 and 2001.

 

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

 

Deferred Income Taxes

 

LG&E expects to have adequate levels of taxable income to realize its recorded deferred tax assets.  At December 31, 2002, deferred tax assets totaled $98.2 million  and were principally related to expenses attributable to LG&E’s pension plans and post retirement benefit obligations.

 

FUTURE OUTLOOK

 

Competition and Customer Choice

 

LG&E has moved aggressively over the past decade to be positioned for the energy industry’s shift to customer choice and a competitive market for energy services.  Specifically, LG&E has taken many steps to prepare for the expected increase in competition in its business, including support for PBR structures; aggressive cost reduction activities; strategic acquisitions, dispositions and growth initiatives; write-offs of previously deferred expenses; an increase in focus on commercial and industrial customers; an increase in employee training; and necessary corporate and business unit realignments.

 

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In December 1997, the Kentucky Commission issued a set of principles which was intended to serve as its guide in consideration of issues relating to industry restructuring.  Among the issues addressed by these principles are: consumer protection and benefit, system reliability, universal service, environmental responsibility, cost allocation, stranded costs and codes of conduct.  During 1998, the Kentucky Commission and a task force of the Kentucky General Assembly had each initiated proceedings, including meetings with representatives of utilities, consumers, state agencies and other groups in Kentucky, to discuss the possible structure and effects of energy industry restructuring in Kentucky.

 

In November 1999, the task force issued a report to the Governor of Kentucky and a legislative agency recommending no general electric industry restructuring actions during the 2000 legislative session.  No general restructuring actions have been taken to date by the legislature.

 

Thus, at the time of this report, neither the Kentucky General Assembly nor the Kentucky Commission has adopted or approved a plan or timetable for retail electric industry competition in Kentucky.  The nature or timing of the ultimate legislative or regulatory actions regarding industry restructuring and their impact on LG&E, which may be significant, cannot currently be predicted.

 

While many states have moved forward in providing retail choice, many others have not. Some are reconsidering their initiatives and have even delayed implementation.

 

KU

 

GENERAL

 

The following discussion and analysis by management focuses on those factors that had a material effect on KU’s financial results of operations and financial condition during 2002, 2001, and 2000 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 KU’s reports to the SEC, including Exhibit No. 99.01 to this report on Form 10-K.

 

MERGERS and ACQUISITIONS

 

On December 11, 2000, LG&E Energy was acquired by Powergen for cash of approximately $3.2 billion or $24.85 per share and the assumption of all of LG&E Energy’s debt.  As a result of the acquisition, LG&E Energy became a wholly owned subsidiary of Powergen and, as a result, KU became an indirect subsidiary of Powergen.  KU has continued its separate identity and serves customers in Kentucky, Virginia and Tennessee  under its existing name.  The preferred stock and debt securities of KU were not affected by this transaction and KU continued to file SEC reports. Following the acquisition, Powergen became a registered holding company under PUHCA and KU, as a subsidiary of a registered holding company, became subject to additional

 

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regulation under PUHCA.  See “Rates and Regulation” under Item 1.

 

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

 

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

 

RESULTS OF OPERATIONS

 

Net Income

 

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

 

KU’s net income in 2001 was relatively flat as compared to 2000 with an increase of $.9 million. The increase resulted primarily from decreased depreciation, interest expenses and property and other taxes, partially offset by higher pension related expenses and amortization of regulatory assets.

 

Revenues

 

A comparison of operating revenues for the years 2002 and 2001, excluding the provision for rate collections (refunds), with the immediately preceding year reflects both increases and decreases which have been segregated by the following principal causes (in thousands of $):

 

		Increase (Decrease) From Prior Period
Cause		2002			2001
Retail sales:
Fuel clause adjustments		$	18,223		$	10,220
KU/LG&E Merger surcredit		(2,641		)	(3,856		)
Environmental cost recovery surcharge		3,781			1,458
Demand side management		1,570			—
Performance based rate		—			1,747
Electric rate reduction		—			(5,395		)
VDT surcredit		(527		)	(372		)
Variation in sales volumes, and other		46,601			(1,627		)
Total retail sales		67,007			2,175
Wholesale sales		(59,373		)	5,108
Other		7,132			1,202
Total		$	14,766		$	8,485

 

Electric revenues increased in 2002 primarily due to an increase in retail sales due to warmer weather and an increase in the recovery of fuel costs passed through the FAC. Cooling degree days for 2002 increased 26% over 2001. The increase in retail sales was partially offset by a decrease in wholesale sales volumes. The

 

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decrease in wholesale sales was due in large part to fewer megawatts available due to increased retail sales.  Electric revenues increased in 2001 primarily due to an increase in the recovery of fuel costs passed through the FAC and an increase in wholesale activity partially offset by a rate reduction ordered by Kentucky Commission in 2000 and lower sales volumes.

 

Expenses

 

Fuel for electric generation comprises a large component of KU’s total operating expenses.  KU’s Kentucky jurisdictional electric rates are subject to a FAC whereby increases or decreases are reflected in the FAC factor, subject to the approval of the Kentucky Commission.   KU’s wholesale and Virginia jurisdictional electric rates contain a fuel adjustment clause whereby increases or decreases in the cost of fuel are reflected in rates, subject to the approval of FERC and the Virginia Commission, respectively.

 

Fuel for electric generation increased $13.1 million (5.5%) in 2002 because of an increase in the cost of coal burned ($29.7 million), partially offset by a decrease in generation ($16.5 million). Fuel for electric generation increased $17.1 million (7.8%) in 2001 because of an increase in the cost of coal burned ($21.8 million), partially offset by a decrease in generation ($4.7 million).  The average delivered cost per ton of coal purchased was $31.44 in 2002, $27.84 in 2001 and  $25.63 in 2000.

 

Power purchased expense in 2002 increased slightly over 2001, $.8 million (.5%) primarily due to an increase in purchases to meet requirements for native load and off-system sales partially offset by a decrease in purchase price.  Power purchased expense decreased $9.8 million (5.9%) in 2001 primarily due to decreased brokered sales activity in the wholesale electric market and a lower unit cost of the purchases partially offset by an increase in purchases to meet requirements for native load and off-system sales.

 

Other operation expenses increased $25.8 million (21.8%) in 2002. The primary cause for the increase was the full year amortization in 2002 of a regulatory asset created as a result of the workforce reduction associated with KU’s VDT of $6.5 million, higher costs for electric transmission primarily resulting from increased MISO costs of $7.4 million, an increase in property insurance costs of $2.8 million, an increase in employee benefit costs due to changes in pension assumptions to reflect current market conditions and changes in market value of plan assets at the measurement date of $1.7 million, and an increase in outside services of $4.9 million.   Other operation expenses increased $10.3 million (9.5%) in 2001. The primary cause for the increase was the amortization of a regulatory asset as a result of the workforce reduction associated with KU’s VDT of $5.0 million and an increase in pension expense of $5.5 million.

 

Maintenance expenses increased $5.9 million (10.3%) in 2002 primarily due to increases in steam maintenance of $6.1 million related to annual outages at the Ghent, Green River, and Tyrone steam facilities.  Maintenance expenses for 2001 decreased $4.6 million (7.5%) primarily due to decreased repairs to steam facilities ($6.5 million).

 

Depreciation and amortization increased $5.2 million (5.7%) in 2002 primarily due to an increase in plant in service.  Depreciation and amortization decreased $8.0 million (8.1%) in 2001 primarily due to a reduction in depreciation rates as a result of a settlement order in December 2001 from the Kentucky Commission.  Depreciation expenses decreased by $6.0 million as a result of the settlement order.

 

Variations in income tax expense are largely attributable to changes in pre-tax income.  The 2002 effective income tax rate decreased to 34.9% from the 35.9% rate in 2001. See Note 7 of KU’s Notes to Financial Statements under Item 8.

 

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Property and other taxes increased $1.1 million (7.6%) in 2002 due to higher property taxes and payroll taxes. Property and other taxes decreased $3.1 million (18.2%) in 2001 due to decreases in payroll taxes related to fewer employees as a result of workforce reductions and transfers to LG&E Energy Services Company.

 

Other income-net increased $1.5 million (16.8%) in 2002 primarily due to a non-recurring increase in earnings from KU’s equity earnings in a minority interest of  $5.2 million, partially offset by a gain on disposition of property in 2001,  $1.8 million, lower interest and dividend income from investments, $0.7 million, and higher benefit and other costs, $1.4 million.  The increased equity earnings in 2002 are due to the gain on the sale of emissions allowances. Other income-net increased $2.1 million (30.5%) in 2001 due to an increase in the gain on sale of assets.

 

Interest charges decreased $8.3 million (24.5%) in 2002 as compared to 2001 due to lower interest rates on variable rate debt and refinancing of long term debt with lower interest rates, $8.0 million. Interest charges decreased $5.4 million (13.7%) in 2001 from 2000 due to lower interest rates on variable rate debt, $4.6 million, the retirement of short-term borrowings, $1.6 million, lower interest on debt to parent company, $1.2 million, partially offset by an increase in interest associated with KU’s accounts receivable securitization program, $1.8 million.

 

KU’s weighted average cost of long-term debt, including amortization of debt expense and interest rate swaps, was 3.30% at December 31, 2002 compared to 4.91% at December 31, 2001.  See Note 9 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.

 

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 known weather and days not billed.  At December 31, 2002, a 10% change in these estimated quantities would cause revenue and accounts receivable to change by approximately $4.2 million.  See also Note 1 of KU’s Notes to Financial Statements under Item 8.

 

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

 

KU’s costs of providing defined-benefit pension retirement plans is dependent upon a number of factors, such as the rates of return on plan assets, discount rate, and contributions made to the plan.  The market value of KU plan assets has been affected by declines in the equity market since the beginning of the fiscal year.  As a result, at December 31, 2002, KU was required to recognize an additional minimum liability as prescribed by SFAS No. 87 Employers’ Accounting for Pensions.  The liability was recorded as a reduction to other comprehensive income, and did not affect net income for 2002.  The amount of the liability depended upon the asset returns experienced in 2002 and contributions made by KU to the plan during 2002.  Also, pension cost and cash contributions to the plan could increase in future years without a substantial recovery in the equity market.  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.

 

The combination of poor market performance and a decrease in short-term corporate bond interest rates has created a divergence in the potential value of the pension liability and the actual value of the pension assets.  These conditions could result in an increase in KU’s funded accumulated benefit obligation and future pension expense.  The primary assumptions that drive the value of the unfunded accumulated benefit obligation are the discount rate and expected return on plan assets.

 

KU made a contribution to the pension plan of $3.5 million in January 2003.

 

A 1% increase or decrease in the assumed discount rate could have an approximate $26.0 million positive or negative impact to the accumulated benefit obligation of KU.

 

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

 

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

 

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

 

KU has accrued in the financial statements, an estimate of $13.5 million for 2002 ESM, with collection from customers commencing in April 2003.  The ESM is subject to Kentucky Commission approval.

 

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

 

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NEW ACCOUNTING PRONOUNCEMENTS

 

The following accounting pronouncements were issued that affected KU in 2002:

 

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 is January 1, 2003.  Management has calculated the impact of SFAS No. 143 and the recently released FERC NOPR No. RM02-7, Accounting, Financial Reporting, and Rate Filing Requirements for Asset Retirement Obligations.  As of January 1, 2003, KU recorded asset retirement obligation (ARO) assets in the amount of $8.6 million and liabilities in the amount of $18.5 million. KU also recorded a cumulative effect adjustment in the amount of $9.9 million to reflect the accumulated depreciation and accretion of ARO assets at the transition date less amounts previously accrued under regulatory depreciation.  KU recorded offsetting regulatory assets of $9.9 million, pursuant to regulatory treatment prescribed under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation.  Also pursuant to SFAS No. 71, KU recorded regulatory liabilities in the amount of $888,000 offsetting removal costs previously accrued under regulatory accounting in excess of amounts allowed under SFAS No. 143.

 

KU also expects to record ARO accretion expense of approximately $1.2 million, ARO depreciation expense of approximately $176,000 and an offsetting regulatory credit in the income statement of approximately $1.4 million in 2003, pursuant to regulatory treatment prescribed under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation.  The accretion, depreciation and regulatory credit will be annual adjustments.  SFAS No. 143 will have no impact on the results of the operation of KU.

 

KU’s asset retirement obligations are primarily related to the final retirement of generating units.  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 will be recorded for transmission and distribution assets.

 

KU adopted EITF No. 98-10, Accounting for Energy Trading and Risk Management Activities, effective January 1, 1999.  This pronouncement required that energy trading contracts be marked to market on the balance sheet, with the gains and losses shown net in the income statement.  In October 2002, the Emerging Issues Task Force reached a consensus to rescind EITF 98-10.  The effective date for the full rescission is for fiscal periods beginning after December 15, 2002.  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.  KU does not expect the rescission of this standard to have a material impact on financial position or results of operations.

 

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

 

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does not expect the adoption of this standard to have any impact on the financial position or results of operations.

 

LIQUIDITY AND CAPITAL RESOURCES

 

KU uses net cash generated from its operations and external financing to fund construction of plant and equipment and the payment of dividends.  KU believes that such sources of funds will be sufficient to meet the needs of its business in the foreseeable future.

 

Operating Activities

 

Cash provided by operations was $175.8 million, $188.1 million and $176.3 million in 2002, 2001 and 2000, respectively.  The 2002 decrease from 2001 of $12.3 million was primarily the result of a decrease in accrued taxes and changes in accounts receivable. The 2001 increase resulted from sale of accounts receivable through a securitization program.  See Note 1 of KU’s Notes to Financial Statements under Item 8 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 $237.9 million, $142.4 million and $100.3 million in 2002, 2001 and 2000, respectively.  KU expects its capital expenditures for 2003 and 2004 will total approximately $550.0 million, which consists primarily of construction costs associated with installation of NOx equipment as described in the section titled “Environmental Matters,” purchase of jointly owned CTs with LG&E and on going construction for the distribution system.

 

Net cash used for investment activities increased $99.0 million in 2002 compared to 2001 and $38.6 million in 2001 compared to 2000 primarily due to the level of construction expenditures.  NOx expenditures increased $50.6 million and CT expenditures increased $27.0 million in 2002.

 

Financing Activities

 

Net cash inflows from financing activities were $64.2 million in 2002 and outflows of $46.2 million and $82.4 million in 2001 and 2000, respectively.  In 2002, short-term debt increased $72.0 million from 2001.  In 2001, short-term debt decreased $13.4 million from 2000 and KU paid $32.8 million in dividends.

 

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

 

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

 

Future Capital Requirements

 

Future capital requirements may be affected in varying degrees by factors such as load growth, changes in construction expenditure levels, rate actions by regulatory agencies, new legislation, market entry of competing

 

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electric power generators, changes in environmental regulations and other regulatory requirements.  KU anticipates funding future capital requirements through operating cash flow, debt, and/or infusion of capital from its parent.

 

KU’s debt ratings as of December 31, 2002, were:

 

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

 

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

 

Contractual Obligations

 

The following is provided to summarize KU’s contractual cash obligations for periods after December 31, 2002 (in thousands of $):

 

		Payments Due by Period
Contractual cash Obligations		2003			2004- 2005			2006- 2007			After 2007			Total
Short-term debt(a)		$	119,490		$	—		$	—		$	—		$	119,490
Long-term debt(b)		153,930			—			89,000			257,562			500,492
Unconditional purchase obligations(c)		34,317			79,306			79,878			643,946			837,447
Other long-term obligations(d)		128,199			201,249			—			—			329,448
Total contractual cash obligations(e)		$	435,936		$	280,555		$	168,878		$	901,508		$	1,786,877

 

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

(b)                                 Includes long-term debt of $91.9 million is classified as a current liability because the bonds are subject to tender for purchase at the option of the holder and to mandatory tender for purchase upon the occurrence of certain events.  Maturity dates for the bonds range from 2024 to 2032.

(c)                                  Represents future minimum payments under purchased power agreements through 2020.

(d)                                 Represents construction commitments.

(e)                                  KU does not expect to pay the $91.9 million of long-term debt classified as a current liability in the consolidated balance sheets in 2003 as explained in (b) above.  KU anticipates cash from operations and external financing will be sufficient to fund future obligations.  KU anticipates refinancing a portion of its short-term debt with long-term debt in 2003.

 

Market Risks

 

KU is exposed to market risks from changes in interest rates and commodity prices.  To mitigate changes in

 

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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, 2002, the potential change in interest expense associated with a 1% change in base interest rates of KU’s variable rate debt is estimated at $5.2 million after 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.

 

As of December 31, 2002, KU has swaps with a combined notional value of $153 million.  The swaps exchange fixed-rate interest payments for floating rate interest payments on KU’s Series P, R, and PCS-9 Bonds.  The potential loss in fair value resulting from a hypothetical 1% adverse movement in base interest rates is estimated at $6.9 million as of December 31, 2002.  This estimate is derived from third party valuations. Changes in the market value of these swaps if held to maturity, as KU intends to do, will have no effect on KU’s net income or cash flow.  See Note 4 of KU’s Notes to Financial Statements under Item 8.

 

Commodity Price Sensitivity

 

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

 

Energy Trading & Risk Management Activities

 

KU conducts energy trading and risk management activities to maximize the value of power sales from physical assets it owns, in addition to the wholesale sale of excess asset capacity.  Certain energy trading activities are accounted for on a mark-to-market basis in accordance with EITF 98-10 Accounting for Contracts Involved in Energy Trading and Risk Management Activities, SFAS No. 133 Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138 Accounting for Certain Derivative Instruments and Certain Hedging Activities.  Wholesale sales of excess asset capacity and wholesale purchases are treated as normal sales and purchases under SFAS No. 133 and SFAS No. 138 and are not marked-to-market.

 

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

 

The table below summarizes KU’s energy trading and risk management activities for 2002 and 2001(in thousands of $).

 

		2002			2001
Fair value of contracts at beginning of period, net liability		$	(186	)	$	(17	)
Fair value of contracts when entered into during the period		(65		)	3,441
Contracts realized or otherwise settled during the period		448			(2,894		)
Changes in fair values due to changes in assumptions		(353		)	(716		)
Fair value of contracts at end of period, net liability		$	(156	)	$	(186	)

 

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No changes to valuation techniques for energy trading and risk management activities occurred during 2002.  Changes in market pricing, interest rate and volatility assumptions were made during both years. All contracts outstanding at December 31, 2002 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, 2002, 86% of the trading and risk management commitments were with counterparties rated BBB- equivalent or better.

 

Accounts Receivable Securitization

 

On February 6, 2001, KU implemented an accounts receivable securitization program.  The purpose of this program is to enable KU to accelerate the receipt of cash from the collection of retail accounts receivable, thereby reducing dependence upon more costly sources of working capital. The securitization program allows for a percentage of eligible receivables to be sold.  Eligible receivables are generally all receivables associated with retail sales that have standard terms and are not past due.  KU is able to terminate this program at any time without penalty. If there is a significant deterioration in the payment record of the receivables by the retail customers or if KU fails to meet certain covenants regarding the program, the program may terminate at the election of the financial institutions.  In this case, payments from retail customers would first be used to repay the financial institutions participating in the program, and would then be available for use by KU.

 

As part of the program, KU sold retail accounts receivables to a wholly owned subsidiary KU R.  Simultaneously, KU R entered into two separate three-year accounts receivable securitization facilities with two financial institutions and their affiliates whereby KU R can sell, on a revolving basis, an undivided interest in certain of their receivables and receive up to $50 million from an unrelated third party purchaser.  The effective cost of the receivables programs is comparable to KU’s lowest cost source of capital, and is based on prime rated commercial paper.  KU retains servicing rights of the sold receivables through two separate servicing agreements with the third party purchaser.  KU has obtained an opinion from independent legal counsel indicating these transactions qualify as a true sale of receivables.  As of December 31, 2002, the outstanding program balance was $49.3 million.  KU is considering unwinding the accounts receivable securitization arrangements involving KU R during 2003.

 

The allowance for doubtful accounts associated with the eligible securitized receivables was $520,000 at December 31, 2002.  This allowance is based on historical experience of KU. Each securitization facility contains a fully funded reserve for uncollectible receivables.

 

RATES AND REGULATION

 

Following the purchase of Powergen by E.ON, E.ON became a registered holding company under PUHCA.  As a result, E.ON, its utility subsidiaries, including KU, and certain of its non-utility subsidiaries are subject to extensive regulation by the SEC under PUHCA with respect to issuances and sales of securities, acquisitions and sales of certain utility properties, and intra-system sales of certain goods and services.  In addition, PUHCA generally limits the ability of registered holding companies to acquire additional public utility systems and to acquire and retain businesses unrelated to the utility operations of the holding company.  KU believes that it has

 

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adequate authority (including financing authority) under existing SEC orders and regulations to conduct its business.  KU will seek additional authorization when necessary.

 

KU is subject to the jurisdiction of the Kentucky Commission, the Virginia Commission and FERC in virtually all matters related to electric utility regulation, and as such, its accounting is subject to SFAS No. 71, Accounting for the Effects of Certain Types of Regulation.  Given KU’s competitive position in the market and the status of regulation in the states of Kentucky and Virginia, KU has no plans or intentions to discontinue its application of SFAS No. 71.  See Note 3 of KU’s Notes to Financial Statements under Item 8.

 

Kentucky Commission Settlement Order - VDT Costs, ESM and Depreciation

 

During the first quarter 2001, KU recorded a $64 million charge for a workforce reduction program.  Primary components of the charge were separation benefits, enhanced early retirement benefits, and health care benefits. The result of this workforce reduction was the elimination of approximately 300 positions, accomplished primarily through a voluntary enhanced severance program.

 

On June 1, 2001, KU filed an application (VDT case) with the Kentucky Commission to create a regulatory asset relating to these first quarter 2001 charges.  The application requested permission to amortize these costs over a four-year period.  The Kentucky Commission also opened a case to review the new depreciation study and resulting depreciation rates implemented in 2001.

 

KU reached a settlement in the VDT case as well as the other cases involving depreciation rates and ESM with all intervening parties.  The settlement agreement was approved by the Kentucky Commission on December 3, 2001.  The order allowed KU to set up a regulatory asset of $54 million for the workforce reduction costs and begin amortizing these costs over a five year period starting in April 2001. The first quarter 2001 charge of $64 million represented all employees who had accepted a voluntary enhanced severance program.  Some employees rescinded their participation in the voluntary enhanced severance program and, along with the non-recurring charge of $6.9 million for FERC and Virginia jurisdictions, thereby decreasing the original charge of the regulatory asset from $64 million to $54 million. The settlement will also reduce revenues approximately $11 million through a surcredit on future bills to customers over the same five year period.  The surcredit represents stipulated net savings KU is expected to realize from implementation of best practices through the VDT. The agreement also established KU’s new depreciation rates in effect December 2001, retroactive to January 1, 2001.  The new depreciation rates decreased depreciation expense by $6.0 million in 2001.

 

Environmental Cost Recovery

 

In June 2000, the Kentucky Commission approved KU’s application for a CCN to construct up to four SCR NOx reduction facilities. The construction and subsequent operation of the SCRs is intended to reduce NOx emission levels to meet the EPA’s mandated NOx emission level of 0.15 lbs./ Mmbtu by May 2004.  In its order, the Kentucky Commission ruled that KU’s proposed plan for construction was “reasonable, cost-effective and will not result in the wasteful duplication of facilities”.  In October 2000, KU filed an application with the Kentucky Commission to amend its Environmental Compliance Plan to reflect the addition of the proposed NOx reduction technology projects and to amend its Environmental Cost Recovery Tariff to include an overall rate of return on capital investments. Approval of KU’s application in April 2001, allowed KU to begin to recover the costs associated with these new projects, subject to Kentucky Commission oversight during normal six-month and two-year reviews.

 

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In August 2002, KU filed an application with the Kentucky Commission to amend its compliance plan to allow recovery of the cost of a new and additional environmental compliance facility.  The estimated capital cost of the additional facilities is $17.3 million.  The Kentucky Commission conducted a public hearing on the case on December 20, 2002, final briefs were filed on January 15, 2003, and a final order was issued February 11, 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 will begin with bills rendered in April 2003.

 

ESM

 

KU’s electric rates are subject to an ESM.  The ESM, initially in place for three years beginning in 2000, sets an upper and lower point for rate of return on equity, whereby if KU’s rate of return for the calendar year falls within the range of 10.5% to 12.5%, no action is necessary.  If earnings are above the upper limit, the excess earnings are shared 40% with ratepayers and 60% with shareholders; if earnings are below the lower limit, the earnings deficiency is recovered 40% from ratepayers and 60% from shareholders.  By order of the Kentucky Commission, rate changes prompted by the ESM filing go into effect in April of each year subject to a balancing adjustment in successive periods.  KU made its second ESM filing on March 1, 2002 for the calendar year 2001 reporting period.  KU is in the process of refunding $1 million to customers for the 2001 reporting period.  KU estimated that the rate of return will fall below the lower limit, subject to Kentucky Commission approval, for the year ended December 31, 2002. The 2002 financial statements include an accrual to reflect the earnings deficiency of $13.5 million to be recovered from customers commencing in April 2003.

 

On November 27, 2002, KU filed a revised ESM tariff which proposed continuance of the existing ESM through December 2005.  The Kentucky Commission issued an Order suspending the ESM tariff one day making the effective date January 2, 2003.  In addition, the Kentucky Commission is conducting a management audit to review the ESM plan and reassess its reasonableness in 2003.  KU and interested parties will have the opportunity to provide recommendations for modification and continuance of the ESM or other forms of alternative or incentive regulation.

 

DSM

 

In May 2001, the Kentucky Commission approved a plan that would expand LG&E’s current DSM programs into the service territory served by KU.  The filing 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 program based on program planning engineering estimates and post-implementation evaluations.

 

FAC

 

KU employs an FAC mechanism, which allows KU to recover from customers the actual fuel costs associated with retail electric sales.  In July 1999, the Kentucky Commission issued a series of orders requiring KU to refund approximately $10.1 million resulting from reviews of the FAC from November 1994 to October 1998.  In August 1999, after a rehearing request by KU, the Kentucky Commission issued a final order that reduced the refund obligation to $ 6.7 million ($5.8 million on Kentucky jurisdictional basis) from the original order amount of $10.1 million.  KU implemented the refund from October 1999 through September 2000.  Both KU and the KIUC appealed the order.   Pending a decision on this appeal, a comprehensive settlement was reached by all parties and approved by the Kentucky Commission on May 17, 2002.  Thereunder, KU agreed to credit

 

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its fuel clause in the amount of $954,000 (refund made in June and July 2002), and the parties agreed on a prospective interpretation of the state’s fuel adjustment clause regulation to ensure consistent and mutually acceptable application on a going-forward basis.

 

In December 2002, the Kentucky Commission initiated a two year review of the operation of KU’s fuel adjustment clause for the period November 2000 through October 2002.  Testimony in the review case was filed on January 20, 2003 and a public hearing was held February 18, 2003.  Issues addressed at that time included the establishment of the current base fuel factor to be included in KU’s base rates, verification of proper treatment of purchased power costs during unit outages, and compliance with fuel procurement policies and practices.

 

In January 2003, the Kentucky Commission reviewed the FAC of KU 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 $673,000. 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 KU’s fuel procurement functions.

 

Kentucky Commission Administrative Case for Affiliate Transactions

 

In December 1997, the Kentucky Commission opened Administrative Case No. 369 to consider Kentucky Commission policy regarding cost allocations, affiliate transactions and codes of conduct governing the relationship between utilities and their non-utility operations and affiliates.  The Kentucky Commission intended to address two major areas in the proceedings: the tools and conditions needed to prevent cost shifting and cross-subsidization between regulated and non-utility operations; and whether a code of conduct should be established to assure that non-utility segments of the holding company are not engaged in practices that could result in unfair competition caused by cost shifting from the non-utility affiliate to the utility.  During the period September 1998 to February 2000, the Kentucky Commission issued draft codes of conduct and cost allocation guidelines.  In early 2000, the Kentucky General Assembly enacted legislation, House Bill 897, which authorized the Kentucky Commission to require utilities that provide nonregulated activities to keep separate accounts and allocate costs in accordance with procedures established by the Kentucky Commission. In the same bill, the General Assembly set forth provisions to govern a 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.  On February 14, 2001, the Kentucky Commission published notice of their intent to promulgate new administrative regulation under the auspices of the new law.  This effort is still on going.

 

Kentucky Commission Administrative Case for System Adequacy

 

On June 19, 2001, Kentucky Governor Paul E. Patton issued Executive Order 2001-771, which directed the Kentucky Commission to review and study issues relating to the need for and development of new electric generating capacity in Kentucky.  The issues to be considered included the impact of new power plants on the electric supply grid, facility siting issues, and economic development matters, with the goal of ensuring a continued, reliable source of supply of electricity for the citizens of Kentucky and the continued environmental and economic vitality of Kentucky and its communities.  In response to that Executive Order, in July 2001 the Kentucky Commission opened Administrative Case No. 387 to review the adequacy of Kentucky’s generation

 

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capacity and transmission system.  Specifically, the items reviewed were the appropriate level of reliance on purchased power, the appropriate reserve margins to meet existing and future electric demand, the impact of spikes in natural gas prices on electric utility planning strategies, and the adequacy of Kentucky’s electric transmission facilities.  KU, as a party to this proceeding, filed written testimony and responded to two requests for information.  Public hearings were held and in October 2001, KU filed a final brief in the case.  In December 2001, the Kentucky Commission issued an order in which it noted that KU is responsibly addressing the long-term supply needs of native load customers and that current reserve margins are appropriate.  However, due to the rapid pace of change in the industry, the order also requires KU to provide an annual assessment of supply resources, future demand, reserve margin, and the need for new resources.

 

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

 

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

 

FERC SMD NOPR

 

On July 31, 2002, the FERC issued a NOPR in Docket No. RM01-12-000 which would substantially alter the regulations governing the nation’s wholesale electricity markets by establishing a common set of rules — 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 a final rule is expected during 2003.  While it is expected that the SMD final rule will affect KU revenues and expenses, the specific impact of the rulemaking is not known at this time.

 

MISO

 

KU is a member of the MISO, which began commercial operations on February 1, 2002.  MISO now has operational control over KU’s high-voltage transmission facilities (100 kV and greater), while KU continues to control and operate the lower voltage transmission subject to the terms and conditions of the MISO OATT.  As a transmission-owning member of MISO, KU also incurs administrative costs of MISO pursuant to Schedule 10 of the MISO OATT.

 

MISO also proposed to implement a congestion management system.  FERC directed the MISO to coordinate its efforts with FERC’s Rulemaking on SMD. On September 24, 2002, the MISO filed new rate schedules designated as Schedules 16 and 17, which provide for the collection of costs incurred by the MISO to establish day-ahead and real-time energy markets. The MISO proposed to recover these costs under Schedules 16 and 17 once service commences. If approved by FERC, these schedules will cause KU to incur additional costs.  KU opposes the establishment of Schedules 16 and 17.  This effort is still on-going and the ultimate impact of the two schedules, if approved, is not known at this time.

 

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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 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 the Companies, 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 customers the then-projected non-fuel savings associated with the merger.  The Companies submitted this filing on January 13, 2003, proposing to continue to share with customers, on a 50%/50% basis, the estimated fifth-year gross level of non-fuel savings associated with the merger.  The filing is currently under review.

 

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

 

Environmental Matters

 

The Clean Air Act imposed stringent new SO2 and NOx emission limits on electric generating units.  KU met its Phase I SO2 requirements primarily through installation of a scrubber on Ghent Unit 1.  KU’s strategy for Phase II SO2 reductions, which commenced January 1, 2000, is to use accumulated emissions allowances to delay additional capital expenditures and may also include fuel switching or the installation of additional scrubbers.  KU met the NOx emission requirements of the Act through installation of low-NOx burner systems. KU’s compliance plans are subject to many factors including developments in the emission allowance and fuel markets, future regulatory and legislative initiatives, and advances in clean air control technology.  KU will continue to monitor these developments to ensure that its environmental obligations are met in the most efficient and cost-effective manner.

 

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

 

KU is currently implementing a plan for adding significant additional NOx controls to its generating units.  Installation of additional NOx controls will proceed on a phased basis, with installation of controls commencing in late 2000 and continuing through the final compliance date.  KU estimates that it will incur total capital costs

 

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of approximately $232 million to reduce its NOx emissions to the 0.15 lb./Mmbtu level on a company-wide basis.  In addition, KU will incur additional operating and maintenance costs in operating new NOx controls.  KU believes its costs in this regard to be comparable to those of similarly situated utilities with like generation assets.  KU had anticipated that such capital and operating costs are the type of costs that are eligible for recovery from customers under its environmental surcharge mechanism and believed that a significant portion of such costs could be recovered.  In April 2001, the Kentucky Commission granted recovery of these costs for KU.

 

KU is also monitoring several other air quality issues which may potentially impact coal-fired power plants, including the appeal of the D.C. Circuit’s remand of the EPA’s revised air quality standards for ozone and particulate matter, measures to implement EPA’s regional haze rule, and EPA’s December 2000 determination to regulate mercury emissions from power plants.

 

KU owns or formerly owned several properties that contained past MGP operations.  Various contaminants are typically found at such former MGP sites and environmental remediation measures are frequently required.  KU has completed the cleanup of a site owned by KU.  With respect to other former MGP sites no longer owned by KU, KU is unaware of what, if any, additional exposure or liability it may have.

 

In October 1999, approximately 38,000 gallons of diesel fuel leaked from a cracked valve in an underground pipeline at KU’s E.W. Brown Station.  Under the oversight of EPA and state officials, KU commenced immediate spill containment and recovery measures which prevented the spill from reaching the Kentucky River.  KU ultimately recovered approximately 34,000 gallons of diesel fuel.  In November 1999, the Kentucky Division of Water issued a notice of violation for the incident.  KU is currently negotiating with the state in an effort to reach a complete resolution of this matter.  KU incurred costs of approximately $1.8 million and received insurance reimbursement of $1.2 million.  In December 2002, the Department of Justice (DOJ) sent correspondence to KU regarding a potential per-day fine for failure to timely submit a spill control plan and a per-gallon fine for the amount of oil discharged.  KU and the DOJ have commenced settlement discussions using existing DOJ settlement guidelines on this matter.

 

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

 

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

 

Deferred Income Taxes

 

KU expects to have adequate levels of taxable income to realize its recorded deferred tax assets.  At December 31, 2002, deferred tax assets totaled $61 million  and were principally related to expenses attributable to KU’s pension plans and post retirement benefit obligations.

 

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FUTURE OUTLOOK

 

Competition and Customer Choice

 

KU has moved aggressively over the past decade to be positioned for the energy industry’s shift to customer choice and a competitive market for energy services.  Specifically, KU has taken many steps to prepare for the expected increase in competition in its business, including support for PBR structures, aggressive cost reduction activities; strategic acquisitions, dispositions and growth initiatives; write-offs of previously deferred expenses; an increase in focus on commercial and industrial customers; an increase in employee training; and necessary corporate and business unit realignments.

 

In December 1997, the Kentucky Commission issued a set of principles which was intended to serve as its guide in consideration of issues relating to industry restructuring.  Among the issues addressed by these principles are: consumer protection and benefit, system reliability, universal service, environmental responsibility, cost allocation, stranded costs and codes of conduct.  During 1998, the Kentucky Commission and a task force of the Kentucky General Assembly each initiated proceedings, including meetings with representatives of utilities, consumers, state agencies and other groups in Kentucky, to discuss the possible structure and effects of energy industry restructuring in Kentucky.

 

In November 1999, the task force issued a report to the Governor of Kentucky and a legislative agency recommending no general electric industry restructuring actions during the 2000 legislative session.  No general industry restructuring actions have been taken to date by the legislature.

 

Thus, at the time of this report, neither the Kentucky General Assembly nor the Kentucky Commission has adopted or approved a plan or timetable for retail electric industry competition in Kentucky.  The nature or timing of the ultimate legislative or regulatory actions regarding industry restructuring and their impact on KU, which may be significant, cannot currently be predicted.

 

While many states have moved forward in providing retail choice, many others have not.  Some are reconsidering their initiatives and have even delayed implementation.

 

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.  KU filed unbundled rates that became effective January 1, 2002.  KU was granted a waiver from the Virginia Commission on October 29, 2002, exempting KU from retail choice through December 31, 2004.  KU is also seeking a permanent legislative exemption to the Virginia Electric Restructuring Act.  The outcome of such legislative initiatives will not be known until mid-2003.

 

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

 

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

 

 

ITEM 8. Financial Statements and Supplementary Data.

 

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INDEX OF ABBREVIATIONS

 

Capital Corp.		LG&E Capital Corp.
Clean Air Act		The Clean Air Act, as amended in 1990
CCN		Certificate of Public Convenience and Necessity
CT		Combustion Turbines
DSM		Demand Side Management
ECR		Environmental Cost Recovery
EEI		Electric Energy, Inc.
EITF		Emerging Issues Task Force Issue
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
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 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 System Operator
Mmbtu		Million British thermal units
Moody’s		Moody’s Investor Services, Inc.
Mw		Megawatts
Mwh		Megawatt hours
NNS		No-Notice Service
NOPR		Notice of Proposed Rulemaking
NOx		Nitrogen Oxide
OATT		Open Access Transmission Tariff
OMU		Owensboro Municipal Utilities
OVEC		Ohio Valley Electric Corporation
PBR		Performance-Based Ratemaking
PJM		Pennsylvania, New Jersey, Maryland Interconnection
Powergen		Powergen Limited (formerly Powergen plc)
PUHCA		Public Utility Holding Company Act of 1935
ROE		Return on Equity
RTO		Regional Transmission Organization
S&P		Standard & Poor’s Rating Services
SCR		Selective Catalytic Reduction

 

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

 

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

 

		Years Ended December 31
		2002			2001			2000
OPERATING REVENUES:
Electric		$	746,224		$	706,645		$	713,458
Gas		267,693			290,775			272,489
Provision for rate collections (refunds) (Note 3)		12,267			(720		)	(2,500		)
Total operating revenues (Note 1)		1,026,184			996,700			983,447
OPERATING EXPENSES:
Fuel for electric generation		194,900			159,231			159,418
Power purchased		84,330			81,475			96,894
Gas supply expenses		182,108			206,165			196,912
Other operation expenses		208,322			167,818			135,943
Maintenance		60,210			58,687			63,709
Depreciation and amortization (Note 1)		105,906			100,356			98,291
Federal and state income taxes (Note 7)		55,035			63,452			64,425
Property and other taxes		17,459			17,743			18,985
Total operating expenses		908,270			854,927			834,577
Net operating income		117,914			141,773			148,870
Other income - net (Note 8)		820			2,930			4,921
Interest charges		29,805			37,922			43,218
Net income		88,929			106,781			110,573
Preferred stock dividends		4,246			4,739			5,210
Net income available for common stock		$	84,683		$	102,042		$	105,363

 

Consolidated Statements of Retained Earnings

(Thousands of $)

 

		Years Ended December 31
		2002			2001			2000
Balance January 1		$	393,636		$	314,594		$	259,231
Add net income		88,929			106,781			110,573
		482,565			421,375			369,804
Deduct:  Cash dividends declared on stock:
5% cumulative preferred		1,075			1,075			1,075
Auction rate cumulative preferred		1,702			2,195			2,666
$5.875 cumulative preferred		1,469			1,469			1,469
Common		69,000			23,000			50,000
		73,246			27,739			55,210
Balance December 31		$	409,319		$	393,636		$	314,594

 

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
		2002			2001			2000
Net income		$	88,929		$	106,781		$	110,573
Cumulative effect of change in accounting principle – Accounting for derivative instruments and hedging activities		—			(5,998		)	—
Losses on derivative instruments and hedging activities (Note 1)		(8,511		)	(2,606		)	—
Additional minimum pension liability adjustment (Note 6)		(25,999		)	(24,712		)	—
Income tax benefit related to items of other comprehensive income		13,898			13,416			—
Other comprehensive loss, net of tax		(20,612		)	(19,900		)	—
Comprehensive income		$	68,317		$	86,881		$	110,573

 

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
		2002			2001
ASSETS:
Utility plant, at original cost (Note 1):
Electric		$	2,717,187		$	2,598,152
Gas		435,235			409,994
Common		169,577			159,817
		3,321,999			3,167,963
Less:  reserve for depreciation		1,463,674			1,381,874
		1,858,325			1,786,089
Construction work in progress		300,986			255,074
		2,159,311			2,041,163
Other property and investments – less reserve of $63 in 2002 and 2001		764			1,176
Current assets:
Cash		17,015			2,112
Accounts receivable - less reserve of $2,125 in 2002 and $1,575 in 2001		68,440			85,667
Materials and supplies - at average cost:
Fuel (predominantly coal) (Note 1)		36,600			22,024
Gas stored underground (Note 1)		50,266			46,395
Other		25,651			29,050
Prepayments and other		5,298			4,688
		203,270			189,936
Deferred debits and other assets:
Unamortized debt expense (Note 1)		6,532			5,921
Regulatory assets (Note 3)		153,446			197,142
Other		37,755			13,016
		197,733			216,079
		$	2,561,078		$	2,448,354
CAPITAL AND LIABILITIES:
Capitalization (see statements of capitalization):
Common equity		$	833,141		$	838,070
Cumulative preferred stock		95,140			95,140
Long-term debt (Note 9)		328,104			370,704
		1,256,385			1,303,914
Current liabilities:
Current portion of long-term debt (Note 9)		288,800			246,200
Notes payable (Note 10)		193,053			94,197
Accounts payable		122,771			149,070
Accrued taxes		1,450			20,257
Other		19,536			18,658
		625,610			528,382
Deferred credits and other liabilities:
Accumulated deferred income taxes (Notes 1 and 7)		313,225			298,143
Investment tax credit, in process of amortization		54,536			58,689
Accumulated provision for pensions and related benefits (Note 6)		224,703			167,526
Regulatory liabilities (Note 3)		52,424			65,349
Other		34,195			26,351
		679,083			616,058
Commitments and contingencies (Note 11)
.		$	2,561,078		$	2,448,354

 

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
		2002			2001			2000
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	88,929		$	106,781		$	110,573
Items not requiring cash currently:
Depreciation and amortization		105,906			100,356			98,291
Deferred income taxes - net		11,915			3,021			31,020
Investment tax credit - net		(4,153		)	(4,290		)	(4,274		)
Other		37,260			(528		)	8,481
Change in certain net current assets:
Accounts receivable		(3,973		)	43,185			(56,993		)
Materials and supplies		(15,048		)	(2,018		)	(4,311		)
Accounts payable		(26,299		)	14,678			21,384
Accrued taxes		(18,807		)	12,184			(15,686		)
Prepayments and other		321			(10,500		)	(7,816		)
Sale of accounts receivable (Note 1)		21,200			42,000			—
Other		15,130			(17,806		)	(24,431		)
Net cash flows from operating activities		212,381			287,063			156,238
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchases of securities		—			—			(708		)
Proceeds from sales of securities		412			4,237			4,089
Construction expenditures		(220,416		)	(252,958		)	(144,216		)
Net cash flows from investing activities		(220,004		)	(248,721		)	(140,835		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term borrowings and repayments		98,856			(20,392		)	(5,508		)
Issuance of pollution control bonds		158,635			9,662			106,545
Retirement of first mortgage bonds and pollution control bonds		(161,665		)	—			(130,627		)
Additional paid-in capital		—			—			40,000
Payment of dividends		(73,300		)	(27,995		)	(78,079		)
Net cash flows from financing activities		22,526			(38,725		)	(67,669		)
Change in cash and temporary cash investments		14,903			(383		)	(52,266		)
Cash and temporary cash investments at beginning of year		2,112			2,495			54,761
Cash and temporary cash investments at end of year		$	17,015		$	2,112		$	2,495
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Income taxes		$	51,540		$	35,546		$	46,562
Interest on borrowed money		25,673			30,989			42,958

 

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
		2002			2001
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		(40,512		)	(19,900		)
Retained earnings		409,319			393,636
		833,141			838,070

 

CUMULATIVE PREFERRED STOCK:

Redeemable on 30 days notice by LG&E

 

		Shares Outstanding		Current Redemption Price
$25 par value, 1,720,000 shares authorized - 5% series		860,287		$	28.00		21,507			21,507
Without par value, 6,750,000 shares authorized - Auction rate		500,000		100.00			50,000			50,000
$5.875 series		250,000		101.18			25,000			25,000
Preferred stock expense							(1,367		)	(1,367		)
							95,140			95,140
LONG-TERM DEBT (Note 9):
First mortgage bonds - Series due August 15, 2003, 6%							42,600			42,600
Pollution control series:
R due November 1, 2020, 6.55%							—			41,665
S due September 1, 2017, variable%							31,000			31,000
T due September 1, 2017, variable%							60,000			60,000
U due August 15, 2013, variable%							35,200			35,200
V due August 15, 2019, 5.625%							102,000			102,000
W due October 15, 2020, 5.45%							26,000			26,000
X due April 15, 2023, 5.90%							40,000			40,000
Y due May 1, 2027, variable%							25,000			25,000
Z due August 1, 2030, variable%							83,335			83,335
AA due September 1, 2027, variable%							10,104			10,104
BB due September 1, 2026, variable%							22,500			—
CC due September 1, 2026, variable%							27,500			—
DD due November 1, 2027, variable%							35,000			—
EE due November 1, 2027, variable%							35,000			—
FF due October 1, 2032, variable%							41,665			—
Total first mortgage bonds							616,904			496,904
Pollution control bonds (unsecured) - Series due September 1, 2026, variable%							—			22,500
Series due September 1, 2026, variable%							—			27,500
Series due November 1, 2027, variable%							—			35,000
Series due November 1, 2027, variable%							—			35,000
Total unsecured pollution control bonds							—			120,000
Total bonds outstanding							616,904			616,904
Less current portion of long-term debt							288,800			246,200
Long-term debt							328,104			370,704
Total capitalization							$	1,256,385		$	1,303,914

 

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

 

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

 

Note 1 - Summary of Significant Accounting Policies

 

LG&E, a subsidiary of LG&E Energy and an indirect subsidiary of Powergen and 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 the LG&E’s Common Stock is held by LG&E Energy.  LG&E has one wholly owned consolidated subsidiary, LG&E R.

 

On December 11, 2000, LG&E Energy was acquired by Powergen.   On July 1, 2002, E.ON, a German company, completed its acquisition of Powergen plc (now Powergen Limited).  E.ON had announced its pre-conditional cash offer of £5.1 billion ($7.3 billion) for Powergen on April 9, 2001.  E.ON and Powergen are registered public utility holding companies under PUHCA.  No costs associated with these acquisitions nor any of the effects of purchase accounting have been reflected in the financial statements of LG&E.

 

Certain reclassification entries have been made to the previous year’s financial statements to conform to the 2002 presentation with no impact on the balance sheet totals or previously reported income.

 

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

 

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

 

Depreciation and Amortization.  Depreciation is provided on the straight-line method over the estimated service lives of depreciable plant.  Pursuant to a final order of the Kentucky Commission dated December 3, 2001, LG&E implemented new depreciation rates effective January 1, 2001.  The amounts provided were approximately 3.1% in 2002 (2.9% electric, 2.8% gas and 6.6% common); 3.0% for 2001 (2.9% electric, 2.9% gas and 5.7% common); and 3.6% for 2000 (3.3% electric, 3.8% gas and 7.3% common), of average depreciable plant.  Of the amount provided for depreciation, at December 31, 2002, 2001 and 2000, respectively, approximately 0.4 % electric, 0.9 % gas and 0.04% common were related to the retirement, removal and disposal costs of long lived assets.

 

Fuel Inventory.  Fuel inventories of $36.6 million and $22.0 million at December 31, 2002, and 2001, 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 $50.3 million and $46.4 million at December 31, 2002, and 2001, respectively, are included in gas stored underground in the balance sheet.  The inventory is accounted for using the average-cost method.

 

Financial Instruments.  LG&E uses over-the-counter interest-rate swap agreements to hedge its exposure to fluctuations in the interest rates it pays on variable-rate debt.  Gains and losses on interest-rate swaps used to hedge interest rate risk are reflected in other comprehensive income.  In 2000, LG&E used exchange traded U.S.

 

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Treasury note and bond futures to hedge its exposure to fluctuations in the value of its investments in the preferred stocks of other companies.  Gains and losses on U.S. Treasury note and bond futures were charged or credited to other income-net. See Note 4 - Financial Instruments.

 

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

 

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

 

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

 

Revenue Recognition.  Revenues are recorded based on service rendered to customers through month-end.  LG&E accrues an estimate for unbilled revenues from each meter reading date to the end of the accounting period.  The unbilled revenue estimates included in accounts receivable were approximately $40.7 million and $37.3 million, at December 31, 2002 and 2001, respectively.  See Note 3, Rates and Regulatory Matters.  LG&E recorded electric revenues that resulted from sales to a related party, KU, of $46.5 million, $28.5 million and $20.9 million for years ended December 31, 2002, 2001 and 2000, respectively.

 

Fuel and Gas Costs.  The cost of fuel for electric generation is charged to expense as used, and the cost of gas supply is charged to expense as delivered to the distribution system.  LG&E implemented a Kentucky Commission-approved performance-based ratemaking mechanism related to gas procurement and off-system gas sales activity.  See Note 3, Rates and Regulatory Matters.

 

Management’s Use of Estimates.  The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported assets and liabilities and disclosure of contingent items at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates. See Note 11, Commitments and Contingencies, for a further discussion.

 

Accounts Receivable Securitization.  SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, revises the standards for accounting for securitizations and other transfers of financial assets and collateral and requires certain disclosures, and provides accounting and reporting standards for transfers and servicing of financial assets and extinguishments of liabilities. SFAS No. 140 was adopted in the first quarter of 2001, when LG&E entered into an accounts receivable securitization transaction.

 

On February 6, 2001, LG&E implemented an accounts receivable securitization program.  The purpose of this program is to enable LG&E to accelerate the receipt of cash from the collection of retail accounts receivable, thereby reducing dependence upon more costly sources of working capital. The securitization program allows for a percentage of eligible receivables to be sold.  Eligible receivables are generally all receivables associated with retail sales that have standard terms and are not past due.  LG&E is able to terminate this program at any time without penalty. If there is a significant deterioration in the payment record of the receivables by the retail customers or if LG&E fails to meet certain covenants regarding the program, the program may terminate at the election of the financial institutions.  In this case, payments from retail customers would first be used to repay the financial institutions participating in the program, and would then be available for use by LG&E.

 

As part of the program, LG&E sold retail accounts receivables to a wholly owned subsidiary, LG&E R. 

 

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Simultaneously, LG&E R entered into two separate three-year accounts receivable securitization facilities with two financial institutions and their affiliates whereby LG&E R can sell, on a revolving basis, an undivided interest in certain of its receivables and receive up to $75 million from an unrelated third party purchaser.  The effective cost of the receivables programs is comparable to LG&E’s lowest cost source of capital, and is based on prime rated commercial paper. LG&E retains servicing rights of the sold receivables through two separate servicing agreements with the third party purchaser.  LG&E has obtained an opinion from independent legal counsel indicating these transactions qualify as true sale of receivables.  As of December 31, 2002, the outstanding program balance was $63.2 million.  LG&E is considering unwinding its accounts receivable securitization arrangements involving LG&E R during 2003.

 

The allowance for doubtful accounts associated with the eligible securitized receivables was $2.125 million at December 31, 2002.  This allowance is based on historical experience of LG&E. Each securitization facility contains a fully funded reserve for uncollectible receivables.

 

New Accounting Pronouncements. The following accounting pronouncements were issued that affected LG&E in 2002:

 

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 is January 1, 2003.  Management has calculated the impact of SFAS No. 143 and the recently released FERC NOPR No. RM02-7, Accounting, Financial Reporting, and Rate Filing Requirements for Asset Retirement Obligations.  As of January 1, 2003, LG&E recorded asset retirement obligation (ARO) assets in the amount of $4.6 million and liabilities in the amount of $9.3 million.  LG&E also recorded a cumulative effect adjustment in the amount of $5.3 million to reflect the accumulated depreciation and accretion of ARO assets at the transition date less amounts previously accrued under regulatory depreciation.  LG&E recorded offsetting regulatory assets of $5.3 million, pursuant to regulatory treatment prescribed under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation.  Also pursuant to SFAS No. 71, LG&E recorded regulatory liabilities in the amount of $60,000 offsetting removal costs previously accrued under regulatory accounting in excess of amounts allowed  under SFAS No. 143.

 

LG&E also expects to record ARO accretion expense of approximately $617,000, ARO depreciation expense of approximately $117,000 and an offsetting regulatory credit in the income statement of approximately $734,000 in 2003, pursuant to regulatory treatment prescribed under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation.  The accretion, depreciation and regulatory credit will be annual adjustments.  SFAS No. 143 will have no impact on the results of the operation of LG&E.

 

LG&E asset retirement obligations are primarily related to the final retirement of generating units.  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 will be recorded for transmission and distribution assets.

 

LG&E adopted EITF No. 98-10, Accounting for Energy Trading and Risk Management Activities, effective January 1, 1999.  This pronouncement required that energy trading contracts be marked to market on the balance sheet, with the gains and losses shown net in the income statement.  In October 2002, the Emerging Issues Task Force reached a consensus to rescind EITF 98-10.  The effective date for the full rescission is for fiscal periods beginning after December 15, 2002.  With the recession 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

 

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derivatives under SFAS No. 133 must be restated to historical cost through a cumulative effect adjustment.  LG&E does not expect the rescission of this standard to have a material impact on financial position or results of operations.

 

In January 2003, the Financial Accounting Standards Board issued Financial Accounting Standards Board Interpretation No. 46, Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51 (FIN 46).  FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties.  FIN 46 is 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 be applied for the first interim or annual period beginning after June 15, 2003.  LG&E does not expect the adoption of this standard to have any impact on the financial position or results of operations.

 

Note 2 – Mergers and Acquisitions

 

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

 

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 in Kentucky under its present name.

 

Note 3 - Rates and Regulatory Matters

 

Accounting for the regulated utility business conforms with generally accepted accounting principles as applied to regulated public utilities and as prescribed by FERC and the Kentucky Commission.  LG&E is subject to SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, under which certain costs that would otherwise be charged to expense are deferred as regulatory assets based on expected recovery from customers in future rates.  Likewise, certain credits that would otherwise be reflected as income are deferred as regulatory liabilities based on expected return to customers in future rates.  LG&E’s current or expected recovery of deferred costs and expected return of deferred credits is generally based on specific ratemaking decisions or precedent for each item.  The following regulatory assets and liabilities were included in LG&E’s balance sheets

as of December 31 (in thousands of $):

 

		2002			2001
VDT Costs		$	98,044		$	127,529
Gas supply adjustments due from customers		13,714			30,135
Unamortized loss on bonds		18,843			17,902
ESM provision		12,500			—
LGE/KU merger costs		1,815			5,444
Manufactured gas sites		1,757			2,062
One utility costs		954			3,643
Other		5,819			10,427
Total regulatory assets		153,446			197,142
Deferred income taxes - net		(45,536		)	(48,703		)
Gas supply adjustments due to customers		(3,154		)	(15,702		)
Other		(3,734		)	(944		)
Total regulatory liabilities		(52,424		)	(65,349		)
Regulatory assets – net		$	101,022		$	131,793

 

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Kentucky Commission Settlement - VDT Costs. During the first quarter 2001, LG&E recorded a $144 million charge for a workforce reduction program.  Primary components of the charge were separation benefits, enhanced early retirement benefits, and health care benefits.  The result of this workforce reduction was the elimination of approximately 700 positions, accomplished primarily through a voluntary enhanced severance program.

 

On June 1, 2001, LG&E filed an application (VDT case) with the Kentucky Commission to create a regulatory asset relating to these first quarter 2001 charges.  The application requested permission to amortize these costs over a four-year period.  The Kentucky Commission also opened a case to review a new depreciation study and resulting depreciation rates implemented in 2001.

 

LG&E reached a settlement in the VDT case as well as the other cases involving depreciation rates and ESM with all intervening parties.  The settlement agreement was approved by the Kentucky Commission on December 3, 2001. The order allowed LG&E to set up a regulatory asset of $141 million for the workforce reduction costs and begin amortizing these costs over a five year period starting in April 2001. The first quarter 2001 charge of $144 million represented all employees who had accepted a voluntary enhanced severance program.  Some employees rescinded their participation in the voluntary enhanced severance program, thereby decreasing the original charge from $144 million to $141 million. The settlement will also reduce revenues approximately $26 million through a surcredit on future bills to customers over the same five year period.  The surcredit represents net savings stipulated by LG&E.  The agreement also established LG&E’s new depreciation rates in effect December 2001, retroactive to January 1, 2001.  The new depreciation rates decreased depreciation expense by $5.6 million in 2001.

 

PUHCA.  LG&E Energy was purchased by Powergen on December 11, 2000.  Effective July 1, 2002, Powergen was acquired by E.ON, which became a registered holding company under PUHCA.  As a result, E.ON, its utility subsidiaries, including LG&E, and certain of its non-utility subsidiaries are subject to extensive regulation by the SEC under PUHCA with respect to issuances and sales of securities, acquisitions and sales of certain utility properties, and intra-system sales of certain goods and services.  In addition, PUHCA generally limits the ability of registered holding companies to acquire additional public utility systems and to acquire and retain businesses unrelated to the utility operations of the holding company.  LG&E believes that it has adequate authority (including financing authority) under existing SEC orders and regulations to conduct its business.  LG&E will seek additional authorization when necessary.

 

Environmental Cost Recovery. In June 2000, the Kentucky Commission approved LG&E’s application for a CCN to construct up to three SCR NOx reduction facilities. The construction and subsequent operation of the SCRs is intended to reduce NOx emission levels to meet the EPA’s mandated NOx emission level of 0.15 lbs./ Mmbtu by May 2004.  In its order, the Kentucky Commission ruled that LG&E’s proposed plan for construction was “reasonable, cost-effective and will not result in the wasteful duplication of facilities.”  In October 2000,

 

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LG&E filed an application with the Kentucky Commission to amend its Environmental Compliance Plan to reflect the addition of the proposed NOx reduction technology projects and to amend its ECR Tariff to include an overall rate of return on capital investments. Approval of LG&E’s application in April 2001 allowed LG&E to begin to recover the costs associated with these new projects, subject to Kentucky Commission oversight during normal six-month and two-year reviews.

 

In 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.  The Kentucky Commission conducted a public hearing on the case on December 20, 2002, final briefs were filed on January 15, 2003, and a final order was issued February 11, 2003.  The final order approved recovery of four new environmental compliance facilities totaling $43.1 million.  A fifth project, expansion of the land fill 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 will begin with the bills rendered in April 2003.

 

ESM. LG&E’s electric rates are subject to an ESM.  The ESM, initially in place for three years beginning in 2000, sets an upper and lower point for rate of return on equity, whereby if LG&E’s rate of return for the calendar year falls within the range of 10.5% to 12.5%, no action is necessary.  If earnings are above the upper limit, the excess earnings are shared 40% with ratepayers and 60% with shareholders; if earnings are below the lower limit, the earnings deficiency is recovered 40% from ratepayers and 60% from shareholders.  By order of the Kentucky Commission, rate changes prompted by the ESM filing go into effect in April of each year subject to a balancing adjustment in successive periods.  LG&E made its second ESM filing on March 1, 2002 for the calendar year 2001 reporting period.  LG&E is in the process of refunding $441,000 to customers for the 2001 reporting period.  LG&E estimated that the rate of return will fall below the lower limit, subject to Kentucky Commission approval, for the year ended December 31, 2002.  The 2002 financial statements include an accrual to reflect the earnings deficiency of $12.5 million to be recovered from customers commencing in April 2003.

 

On November 27, 2002, LG&E filed a revised ESM tariff which proposed continuance of the existing ESM through December 2005.  The Kentucky Commission issued an Order suspending the ESM tariff one day making the effective date January 2, 2003.  In addition, the Kentucky Commission is conducting a management audit to review the ESM plan and reassess its reasonableness in 2003.  LG&E and interested parties will have the opportunity to provide recommendations for modification and continuance of the ESM or other forms of alternative or incentive regulation.

 

DSM. LG&E’s rates contain a DSM provision.  The provision includes a rate mechanism that provides concurrent recovery of DSM costs and provides an incentive for implementing DSM programs.  This program had allowed LG&E to recover revenues from lost sales associated with the DSM program.  In May 2001, the Kentucky Commission approved LG&E’s plan to continue DSM programs.  This filing called for the expansion of the DSM programs into the service territory served by KU and proposed a mechanism to recover revenues from lost sales associated with DSM programs based on program planning engineering estimates and post-implementation evaluation.

 

Gas PBR.  Since November 1, 1997, LG&E has operated under an experimental PBR mechanism related to its gas procurement activities.   For each of the last five years, LG&E’s rates have been adjusted to recover its portion of the savings (or expenses) incurred during each of the five 12-month periods beginning November 1 and ending October 31. Since its implementation on November 1, 1997, through October 31, 2001, LG&E has achieved $38.1 million in savings. Of the total savings, LG&E has retained $16.5 million, and the remaining portion of $21.6 million has been distributed to customers.  In December 2000, LG&E filed an application reporting on the operation of the experimental PBR and requested the Kentucky Commission to extend the PBR

 

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as a result of the benefits provided to both LG&E and its customers during the experimental period. Following the discovery and hearing process, the Kentucky Commission issued an order effective November 1, 2001, extending the experimental PBR program for an additional four years, and making other modifications, including changes to the sharing levels applicable to savings or expenses incurred under the PBR.  Specifically, the Kentucky Commission modified the savings mechanism to a 25%/75% Company/Customer sharing for all savings (and expenses) up to 4.5% of the benchmarked gas costs.  Savings (and expenses) in excess of 4.5% of the benchmarked gas costs are shared at a 50%/50% level.

 

FAC.  Prior to implementation of the electric PBR in July 1999, and following its termination in March 2000, LG&E employed an FAC mechanism, which under Kentucky law allowed LG&E to recover from customers the actual fuel costs associated with retail electric sales.  In February 1999, LG&E received orders from the Kentucky Commission requiring a refund to retail electric customers of approximately $3.9 million resulting from reviews of the FAC from November 1994, through April 1998.  While legal challenges to the Kentucky Commission order were pending, a comprehensive settlement was reached by all parties and approved by the  Kentucky Commission on May 17, 2002.  Thereunder, LG&E agreed to credit its fuel clause in the amount of $720,000 (such credit provided over the course of June and July 2002), and the parties agreed on a prospective interpretation of the state’s FAC regulation to ensure consistent and mutually acceptable application on a going-forward basis.

 

In December 2002, the Kentucky Commission initiated a two year review of the operation of LG&E’s FAC for the period November 2000 through October 2002.  Testimony in the review case was filed on January 20, 2003 and a public hearing was held February 18, 2003.  Issues addressed at that time included the establishment of the current base fuel factor to be included in LG&E’s base rates, verification of proper treatment of purchased power costs during unit outages, and compliance with fuel procurement policies and practices.

 

Gas Rate Case.   In March 2000, LG&E filed an application with the Kentucky Commission requesting an adjustment in LG&E’s gas rates.  In September 2000, the Kentucky Commission granted LG&E an annual increase in its base gas revenues of $20.2 million effective September 28, 2000.  The Kentucky Commission authorized a return on equity of 11.25%.  The Kentucky Commission approved LG&E’s proposal for a weather normalization billing adjustment mechanism that will normalize the effect of weather on base gas revenues from gas sales.

 

Wholesale Natural Gas Prices.  On September 12, 2000, the Kentucky Commission issued an order establishing Administrative Case No. 384 – “An Investigation of Increasing Wholesale Natural Gas Prices and the Impacts of such Increase on the Retail Customers Served by Kentucky’s Jurisdictional Natural Gas Distribution Companies”.  The impetus for this administrative proceeding was the escalation of wholesale natural gas prices during the summer of 2000.

 

The Kentucky Commission directed Kentucky’s natural gas distribution companies, including LG&E, to file selected information regarding the individual companies’ natural gas purchasing practices, expectations for the then-approaching winter heating season of 2000-2001, and potential actions which these companies might take to mitigate price volatility.  On July 17, 2001, the Kentucky Commission issued an order encouraging the natural gas distribution companies in Kentucky to take various actions, among them to propose a natural gas hedge plan, consider performance-based ratemaking mechanisms, and to increase the use of storage.

 

In April 2002, in Case No. 2002-00136, LG&E proposed a hedging plan for the 2002/2003 winter heating season with three alternatives, the first two using a combination of storage and financial hedge instruments and the third relying upon storage alone.  LG&E and the Attorney General, who represents Kentucky consumers, entered into a settlement which selected the third option.  In August 2002, the Kentucky Commission approved the plan contemplated in the settlement.  The Kentucky Commission validated the effectiveness of storage to

 

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mitigate potentially high winter gas prices by approving this natural gas hedging plan.

 

The Kentucky Commission also decided in Administrative Case No. 384 to engage a consultant to conduct a forward-looking audit of the gas procurement and supply procedures of Kentucky’s largest natural gas distribution companies.  The Kentucky Commission completed its audit in late 2002.  The audit recognized LG&E as “efficient and effective [in the] procurement and management of significant quantities of natural gas supplies.”  The auditors also recognized that “the Company’s residential gas prices have long been below averages for the U. S. and for the Commonwealth of Kentucky” which “demonstrates [LG&E’s] effectiveness in [the] procurement and management of natural gas supplies.”  The audit also stated that the “Company’s very impressive record in keeping its rates down provides sound evidence on the excellent job done in the area of gas supply procurement and management.”

 

Kentucky Commission Administrative Case for Affiliate Transactions. In December 1997, the Kentucky Commission opened Administrative Case No. 369 to consider Kentucky Commission policy regarding cost allocations, affiliate transactions and codes of conduct governing the relationship between utilities and their non-utility operations and affiliates.  The Kentucky Commission intended to address two major areas in the proceedings: the tools and conditions needed to prevent cost shifting and cross-subsidization between regulated and non-utility operations; and whether a code of conduct should be established to assure that non-utility segments of the holding company are not engaged in practices that could result in unfair competition caused by cost shifting from the non-utility affiliate to the utility.  During the period September 1998 to February 2000, the Kentucky Commission issued draft codes of conduct and cost allocation guidelines.  In early 2000, the Kentucky General Assembly enacted legislation, House Bill 897, which authorized the Kentucky Commission to require utilities that provide nonregulated activities to keep separate accounts and allocate costs in accordance with procedures established by the Kentucky Commission.  In the same bill, the General Assembly set forth provisions to govern a 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.  On February 14, 2001, the Kentucky Commission published notice of its intent to promulgate new administrative regulations under the auspices of this new law.  This effort is still on going.

 

Kentucky Commission Administrative Case for System Adequacy.  On June 19, 2001, Kentucky Governor Paul E. Patton issued Executive Order 2001-771, which directed the Kentucky Commission to review and study issues relating to the need for and development of new electric generating capacity in Kentucky.  The issues to be considered included the impact of new power plants on the electric supply grid, facility citing issues, and economic development matters, with the goal of ensuring a continued, reliable source of supply of electricity for the citizens of Kentucky and the continued environmental and economic vitality of Kentucky and its communities.  In response to that Executive Order, in July 2001 the Kentucky Commission opened Administrative Case No. 387 to review the adequacy of Kentucky’s generation capacity and transmission system.  Specifically, the items reviewed were the appropriate level of reliance on purchased power, the appropriate reserve margins to meet existing and future electric demand, the impact of spikes in natural gas prices on electric utility planning strategies, and the adequacy of Kentucky’s electric transmission facilities.  LG&E, as a party to this proceeding, filed written testimony and responded to two requests for information.  Public hearings were held and in October 2001, LG&E filed a final brief in the case.  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

 

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

 

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

 

FERC SMD NOPR.  On July 31, 2002, FERC issued a NOPR in Docket No. RM01-12-000 which would substantially alter the regulations governing the nation’s wholesale electricity markets by establishing a common set of rules — 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 a final rule is expected during 2003.  While it is expected that the SMD final rule will affect LG&E revenues and expenses, the specific impact of the rulemaking is not known at this time.

 

MISO.  LG&E is a member of the MISO, which began commercial operations on February 1, 2002.  MISO now has operational control over LG&E’s high-voltage transmission facilities (100 kV and greater), while LG&E continues to control and operate the lower voltage transmission subject to the terms and conditions of the MISO OATT.  As a transmission-owning member of MISO, LG&E also incurs administrative costs of MISO pursuant to Schedule 10 of the MISO OATT.

 

MISO also proposed to implement a congestion management system.  FERC directed the MISO to coordinate its efforts with FERC’s Rulemaking on SMD. On September 24, 2002, the MISO filed new rate schedules designated as Schedules 16 and 17, which provide for the collection of costs incurred by the MISO to establish day-ahead and real-time energy markets. The MISO proposed to recover these costs under Schedules 16 and 17 once service commences. If approved by FERC, these schedules will cause LG&E to incur additional costs.  LG&E opposes the establishment of Schedules 16 and 17.  This effort is still on-going and the ultimate impact of the two schedules, if approved, is not known at this time.

 

ARO.  In 2003, LG&E expects to record approximately $6.0 million in regulatory assets and approximately $60,000 in regulatory liabilities related to SFAS No. 143, Accounting for Asset Retirement Obligations.

 

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 the Companies, 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 customers the then-projected non-fuel savings associated with the merger.  The Companies submitted this filing on January 13, 2003, proposing to continue to share with customers, on a 50%/50% basis, the estimated fifth-year gross level of non-fuel savings associated with the merger.  The filing is currently under

 

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review.

 

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

 

Note 4 - Financial Instruments

 

The cost and estimated fair values of LG&E’s non-trading financial instruments as of December 31, 2002, and 2001 follow (in thousands of $):

		2002						2001
		Cost			Fair Value			Cost			Fair Value
Preferred stock subject to mandatory redemption		$	25,000		$	25,188		$	25,000		$	25,125
Long-term debt (including current portion)		616,904			623,325			616,904			620,504
Interest-rate swaps		—			(17,115		)	—			(8,604		)

 

All of the above valuations reflect prices quoted by exchanges except for the swaps. The fair values of the swaps reflect price quotes from dealers or amounts calculated using accepted pricing models.

 

Interest Rate Swaps.  LG&E uses interest rate swaps to hedge exposure to market fluctuations in certain of its debt instruments.  Pursuant to policy, use of these financial instruments is intended to mitigate risk and earnings volatility and is not speculative in nature.  Management has designated all of the interest rate swaps as hedge instruments.  Financial instruments designated as cash flow hedges have resulting gains and losses recorded within other comprehensive income and stockholders’ equity.  To the extent a financial instrument or the underlying item being hedged is prematurely terminated or the hedge becomes ineffective, the resulting gains or losses are reclassified from other comprehensive income to net income.  Financial instruments designated as fair value hedges are periodically marked to market with the resulting gains and losses recorded directly into net income to correspond with income or expense recognized from changes in market value of the items being hedged.

 

As of December 31, 2002 and 2001, LG&E was party to various interest rate swap agreements with aggregate notional amounts of $117.3 million.  Under these swap agreements, LG&E paid fixed rates averaging 5.13% and received variable rates based on the Bond Market Association’s municipal swap index averaging 1.52% and 1.61% at December 31, 2002 and 2001, respectively. The swap agreements in effect at December 31, 2002 have been designated as cash flow hedges and mature on dates ranging from 2003 to 2020.  The hedges have been deemed to be fully effective resulting in a pretax loss of $8.5 million for 2002, recorded in other comprehensive income.  Upon expiration of these hedges, the amount recorded in other comprehensive income will be reclassified into earnings.  The amounts expected to be reclassified from other comprehensive income to earnings in the next twelve months is immaterial.

 

Energy Trading & Risk Management Activities.  LG&E conducts energy trading and risk management activities to maximize the value of power sales from physical assets it owns, in addition to the wholesale sale of excess asset capacity.  Certain energy trading activities are accounted for on a mark-to-market basis in accordance with EITF 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities, SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities.  Wholesale sales of excess asset capacity and wholesale purchases are treated as normal sales and purchases under SFAS No. 133 and SFAS No. 138 and are not marked-to-market.

 

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The rescission of EITF 98-10, effective for fiscal years after December 15, 2002, will have no impact on LG&E’s energy trading and risk management reporting as all contracts marked to market under EITF 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 2002 and 2001 (in thousands of $).

 

		2002			2001
Fair value of contracts at beginning of period, net liability		$	(186	)	$	(17	)
Fair value of contracts when entered into during the period		(65		)	3,441
Contracts realized or otherwise settled during the period		448			(2,894		)
Changes in fair values due to changes in assumptions		(353		)	(716		)
Fair value of contracts at end of period, net liability		$	(156	)	$	(186	)

 

No changes to valuation techniques for energy trading and risk management activities occurred during 2002.  Changes in market pricing, interest rate and volatility assumptions were made during both years.  All contracts outstanding at December 31, 2002, 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, 2002, 86% of the trading and risk management commitments were with counterparties rated BBB- equivalent or better.

 

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 310,000 customers and electricity to approximately 382,000 customers in Louisville and adjacent areas in Kentucky.  For the year ended December 31, 2002, 74% of total revenue was derived from electric operations and 26% from gas operations.

 

In November 2001, LG&E and IBEW Local 2100 employees, which represent approximately 70% of LG&E’s workforce, entered into a four-year collective bargaining agreement.

 

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Note 6 - Pension Plans and Retirement Benefits

 

LG&E sponsors several qualified and non-qualified pension plans and other postretirement benefit plans for its employees.  The following tables provide a reconciliation of the changes in the plans’ benefit obligations and fair value of assets over the three-year period ending December 31, 2002, and a statement of the funded status as of December 31 for each of the last three years (in thousands of $):

 

		2002			2001			2000
Pension Plans:
Change in benefit obligation
Benefit obligation at beginning of year		$	356,293		$	310,822		$	283,267
Service cost		1,484			1,311			3,408
Interest cost		24,512			25,361			22,698
Plan amendments		576			1,550			17,042
Curtailment loss		—			24,563			—
Special termination benefits		—			53,610			—
Benefits paid		(34,823		)	(53,292		)	(16,656		)
Actuarial (gain) or loss and other		16,752			(7,632		)	1,063
Benefit obligation at end of year		$	364,794		$	356,293		$	310,822
Change in plan assets
Fair value of plan assets at beginning of year		$	233,944		$	333,378		$	360,095
Actual return on plan assets		(15,648		)	(27,589		)	(6,150		)
Employer contributions and plan transfers		14,150			(17,134		)	(1,804		)
Benefits paid		(34,824		)	(53,292		)	(16,656		)
Administrative expenses		(1,308		)	(1,419		)	(2,107		)
Fair value of plan assets at end of year		$	196,314		$	233,944		$	333,378
Reconciliation of funded status
Funded status		$	(168,480	)	$	(122,349	)	$	22,556
Unrecognized actuarial (gain) or loss		60,313			18,800			(74,086		)
Unrecognized transition (asset) or obligation		(3,199		)	(4,215		)	(5,853		)
Unrecognized prior service cost		32,265			35,435			47,984
Net amount recognized at end of year		$	(79,101	)	$	(72,329	)	$	(9,399	)
Other Benefits:
Change in benefit obligation
Benefit obligation at beginning of year		$	89,946		$	56,981		$	44,997
Service cost		444			358			822
Interest cost		5,956			5,865			4,225
Plan amendments		—			1,487			5,826
Curtailment loss		—			8,645			—
Special termination benefits		—			18,089			—
Benefits paid		(4,988		)	(4,877		)	(4,889		)
Actuarial (gain) or loss		1,875			3,398			6,000
Benefit obligation at end of year		$	93,233		$	89,946		$	56,981
Change in plan assets
Fair value of plan assets at beginning of year		$	2,802		$	7,166		$	10,526
Actual return on plan assets		(533		)	(765		)	(92		)
Employer contributions and plan transfers		4,213			1,282			1,621
Benefits paid		(5,004		)	(4,881		)	(4,889		)
Fair value of plan assets at end of year		$	1,478		$	2,802		$	7,166
Reconciliation of funded status
Funded status		$	(91,755	)	$	(87,144	)	$	(49,815	)
Unrecognized actuarial (gain) or loss		16,971			15,947			5,623
Unrecognized transition (asset) or obligation		6,697			7,346			13,374
Unrecognized prior service cost		5,995			5,302			8,960
Net amount recognized at end of year		$	(62,092	)	$	(58,549	)	$	(21,858	)

 

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There are no plan assets in the nonqualified plans due to the nature of the plans.

 

LG&E made a contribution to the pension plan of $83.1 million in January 2003.

 

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, 2002, 2001 and 2000 (in thousands of $):

 

		2002			2001			2000
Pension Plans:
Amounts recognized in the balance sheet consisted of:
Prepaid benefits cost		$	—		$	—		$	18,880
Accrued benefit liability		(162,611		)	(108,977		)	(28,279		)
Intangible asset		32,799			11,936			—
Accumulated other comprehensive income		50,711			24,712			—
Net amount recognized at year-end		$	(79,101	)	$	(72,329	)	$	(9,399	)
Additional year-end information for plans with accumulated benefit obligations in excess of plan assets (1):
Projected benefit obligation		$	364,794		$	356,293		$	4,088
Accumulated benefit obligation		358,956			352,477			3,501
Fair value of plan assets		196,314			233,944			—

 

(1)  2002 and 2001 includes all plans. 2000 includes SERPs only.

 

 

Other Benefits:
Amounts recognized in the balance sheet consisted of:
Accrued benefit liability		$	(62,092	)	$	(58,549	)	$	(21,858	)
Additional year-end information for plans with benefit obligations in excess of plan assets:
Projected benefit obligation		$	93,233		$	89,946		$	56,981
Fair value of plan assets		1,478			2,802			7,166

 

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The following table provides the components of net periodic benefit cost for the plans for 2002, 2001 and 2000 (in thousands of $):

 

		2002			2001			2000
Pension Plans:
Components of net periodic benefit cost
Service cost		$	1,484		$	1,311		$	3,408
Interest cost		24,512			25,361			22,698
Expected return on plan assets		(21,639		)	(26,360		)	(33,025		)
Amortization of prior service cost		3,777			3,861			4,646
Amortization of transition (asset) or obligation		(1,016		)	(1,000		)	(1,112		)
Recognized actuarial (gain) or loss		21			(777		)	(6,856		)
Net periodic benefit cost		$	7,139		$	2,396		$	(10,241	)
Special charges
Prior service cost recognized		$	—		$	10,237		$	—
Special termination benefits		—			53,610			—
Settlement loss		—			(2,244		)	—
Total charges		$	—		$	61,603		$	—
Other Benefits:
Components of net periodic benefit cost
Service cost		$	444		$	358		$	822
Interest cost		5,956			5,865			4,225
Expected return on plan assets		(204		)	(420		)	(683		)
Amortization of prior service cost		920			951			1,158
Amortization of transition (asset) or obligation		650			719			1,114
Recognized actuarial (gain) or loss		116			(32		)	(485		)
Net periodic benefit cost		$	7,882		$	7,441		$	6,151
Special charges
Curtailment loss		$	—		$	6,671		$	—
Prior service cost recognized		—			2,391			—
Transition obligation recognized		—			4,743			—
Special termination benefits		—			18,089			—
Total charges		$	—		$	31,894		$	—

 

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

 

		2002		2001		2000
Weighted-average assumptions as of December 31:
Discount rate		6.75	%	7.25	%	7.75	%
Expected long-term rate of return on plan assets		9.00	%	9.50	%	9.50	%
Rate of compensation increase		3.75	%	4.25	%	4.75	%

 

For measurement purposes, a 12.00% annual increase in the per capita cost of covered health care benefits was assumed for 2003.  The rate was assumed to decrease gradually to 5.00% for 2014 and remain at that level thereafter.

 

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A 1% change in assumed health care cost trend rates would have the following effects (in thousands of $):

 

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		1% Decrease		1% Increase
Effect on total of service and interest cost components for 2002		(201	)	227
Effect on year-end 2002 postretirement benefit obligations		(3,001	)	3,347

 

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 $1.7 million for 2002, $1.2 million for 2001 and $2.7 million for 2000.

 

Note 7 - Income Taxes

 

Components of income tax expense are shown in the table below (in thousands of $):

 

		2002			2001			2000
Included in operating expenses:
Current        - federal		$	26,231		$	42,997		$	32,612
- state		8,083			8,668			5,018
Deferred      - federal – net		20,464			12,310			24,272
- state – net		4,410			3,767			6,797
Amortization of investment tax credit		(4,153		)	(4,290		)	(4,274		)
Total		55,035			63,452			64,425
Included in other income - net:
Current        - federal		(1,667		)	(1,870		)	(2,187		)
- state		(430		)	(483		)	(568		)
Deferred      - federal – net		(206		)	285			(39		)
- state – net		(53		)	73			(10		)
Total		(2,356		)	(1,995		)	(2,804		)
Total income tax expense		$	52,679		$	61,457		$	61,621

 

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

 

		2002			2001
Deferred tax liabilities:
Depreciation and other plant-related items		$	346,737		$	334,914
Other liabilities		64,734			77,611
		411,471			412,525
Deferred tax assets:
Investment tax credit		22,012			23,713
Income taxes due to customers		18,431			19,709
Pensions		21,056			6,621
Accrued liabilities not currently deductible and other		36,747			64,339
		98,246			114,382
Net deferred income tax liability		$	313,225		$	298,143

 

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

 

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tax rate follows:

 

		2002		2001		2000
Statutory federal income tax rate		35.0	%	35.0	%	35.0	%
State income taxes, net of federal benefit		5.6		4.7		4.3
Amortization of investment tax credit		(2.9	)	(2.6	)	(2.6	)
Other differences – net		(0.5	)	(0.6	)	(0.9	)
Effective income tax rate		37.2	%	36.5	%	35.8	%

 

Note 8 - Other Income - net

 

Other income – net consisted of the following at December 31 (in thousands of $):

 

		2002			2001			2000
Interest and dividend income		$	457		$	748		$	3,103
Gains on fixed asset disposals		421			1,217			1,014
Income taxes and other		(58		)	965			804
Other income – net		$	820		$	2,930		$	4,921

 

Note 9 - First Mortgage Bonds and Pollution Control Bonds

 

Long-term debt and the current portion of long-term debt, summarized below (in thousands of $), consists primarily of first mortgage bonds and pollution control bonds.  Interest rates and maturities in the table below are for the amounts outstanding at December 31, 2002.

 

		Stated Interest Rates		Weighted Average Interest Rate		Maturities		Principal Amounts
Noncurrent portion		Variable - 5.90	%	3.53	%	2019-2032		$	328,104
Current portion		Variable - 6.00	%	2.08	%	2003-2027		288,800

 

Under the provisions for some of LG&E’s variable-rate pollution control bonds, the bonds are subject to tender for purchase at the option of the holder and to mandatory tender for purchase upon the occurrence of certain events, causing the bonds to be classified as current portion of long-term debt in the consolidated balance sheets.  The average annualized interest rate for these bonds during 2002 was 1.61%.

 

LG&E’s First Mortgage Bond, 6% Series of $42.6 million is scheduled to mature in 2003.  There are no other scheduled maturities of pollution control bonds for the five years subsequent to December 31,2002.

 

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

 

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

 

In September 2001, LG&E issued $10.1 million variable rate tax-exempt environmental facility revenue bonds due September 1, 2027.

 

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In January 2000, LG&E exercised its call option on its $20 million 7.50% First Mortgage Bonds due July 1, 2002.  The bonds were redeemed utilizing proceeds from issuance of commercial paper.

 

In May 2000, LG&E issued $25 million variable rate pollution control bonds due May 1, 2027 and exercised its call option on $25 million, 7.45%, pollution control bonds due June 15, 2015.  In August 2000, LG&E issued $83 million in variable rate pollution control bonds due August 1, 2030 and exercised its call option on its $83 million, 7.625%, pollution control bonds due November 1, 2020.

 

Annual requirements for the sinking funds of LG&E’s First Mortgage Bonds (other than the First Mortgage Bonds issued in connection with certain Pollution Control Bonds) are the amounts necessary to redeem 1% of the highest principal amount of each series of bonds at any time outstanding.  Property additions (166 2/3% of principal amounts of bonds otherwise required to be so redeemed) have been applied in lieu of cash.

 

Substantially all of LG&E’s utility plants are pledged as security for its first mortgage bonds.  LG&E’s indenture, as supplemented, provides that portions of retained earnings will not be available for the payment of dividends on common stock, under certain specified conditions. No portion of retained earnings is restricted by this provision as of December 31, 2002.

 

Note 10 - Notes Payable

 

LG&E participates in an intercompany money pool agreement wherein LG&E Energy can make funds available to LG&E at market based rates up to $400 million.  The balance of the money pool loan from LG&E Energy was $193.1 million at a rate of 1.61% and $64.2 million at an average rate of 2.37%, at December 31, 2002 and 2001, respectively.  LG&E also had outstanding commercial paper of $30 million at an average rate of 2.54% at December 31, 2001.  The remaining money pool availability at December 31, 2002, was $206.9 million.  LG&E Energy maintains facilities of $450 million with affiliates to ensure funding availability for the money pool.  The outstanding balance under these facilities as of December 31, 2002 was $230 million, and availability of $220 million remained.

 

Note 11 - - Commitments and Contingencies

 

Construction Program.  LG&E had approximately $15.1 million of commitments in connection with its construction program at December 31, 2002.  Construction expenditures for the years 2003 and 2004 are estimated to total approximately $340.0 million, although all of this amount is not currently committed, including the purchase of four jointly owned CTs, $89.0 million, and construction of NOx equipment, $34.0 million.

 

Operating Lease.  LG&E leases office space and accounts for its office space lease as an operating lease.  Total lease expense for 2002, 2001, and 2000, less amounts contributed by the parent company, was $1.6 million, $1.1 million, and $0.9 million, respectively.  The future minimum annual lease payments under this lease agreement for years subsequent to December 31, 2002, are as follows (in thousands of $):

 

2003		$	3,371
2004		3,399
2005		3,467
2006		3,536
2007		3,607
Thereafter		29,794
Total		$	47,174

 

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In December 1999, LG&E and KU entered into an 18-year cross-border lease of its two jointly owned combustion turbines recently installed at KU’s Brown facility (Units 6 and 7).  LG&E’s obligation was defeased upon consummation of the cross-border lease.  The transaction produced a pre-tax gain of approximately $1.2 million which was recorded in other income on the income statement in 2000, pursuant to a Kentucky Commission order.

 

Environmental.  The Clean Air Act imposed stringent new SO₂ and NOx emission limits on electric generating units.  LG&E previously had installed scrubbers on all of its generating units.  LG&E’s strategy for Phase II SO₂ reductions, which commenced January 1, 2000, is to increase scrubber removal efficiency to delay additional capital expenditures and may also include fuel switching or upgrading scrubbers.  LG&E met the NOx emission requirements of the Act through installation of low-NOx burner systems.  LG&E’s compliance plans are subject to many factors including developments in the emission allowance and fuel markets, future regulatory and legislative initiatives, and advances in clean air control technology.  LG&E will continue to monitor these developments to ensure that its environmental obligations are met in the most efficient and cost-effective manner.

 

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

 

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

 

LG&E is also monitoring several other air quality issues which may potentially impact coal-fired power plants, including the appeal of the D.C. Circuit’s remand of the EPA’s revised air quality standards for ozone and particulate matter, measures to implement EPA’s regional haze rule, and EPA’s December 2000 determination to regulate mercury emissions from power plants.  In addition, LG&E is currently working with local regulatory authorities to review the effectiveness of remedial measures aimed at controlling particulate matter emissions from its Mill Creek Station.  LG&E previously settled a number of property damage claims from adjacent residents and completed significant remedial measures as part of its ongoing capital construction program.  LG&E is in the process of converting the Mill Creek Station to wet stack operation in an effort to resolve all outstanding issues related to particulate matter emissions.

 

LG&E owns or formerly owned three properties which are the location of past MGP operations.  Various contaminants are typically found at such former MGP sites and environmental remediation measures are frequently required.  With respect to the sites, LG&E has completed cleanups, obtained regulatory approval of site management plans, or reached agreements for other parties to assume responsibility for cleanup.  Based on

 

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currently available information, management estimates that it will incur additional costs of $400,000.  Accordingly, an accrual of $400,000 has been recorded in the accompanying financial statements at December 31, 2002 and 2001.

 

Purchased Power. LG&E has a contract for purchased power with OVEC for various Mw capacities.  The estimated future minimum annual payments under purchased power agreements for the years subsequent to December 31, 2002, are as follows (in thousands of $):

 

2003		$	10,773
2004		10,116
2005		10,152
2006		10,816
2007		10,816
Thereafter		184,544
Total		$	237,217

 

Note 12 - - Jointly Owned Electric Utility Plant

 

LG&E owns a 75% undivided interest in Trimble County Unit 1 which the Kentucky Commission has allowed to be reflected in customer rates.

 

Of the remaining 25% of the Unit, IMEA owns a 12.12% undivided interest, and IMPA owns a 12.88% undivided interest.  Each company is responsible for its proportionate ownership share of fuel cost, operation and maintenance expenses, and incremental assets.

 

The following data represent shares of the jointly owned property:

 

		Trimble County
		LG&E			IMPA		IMEA		Total
Ownership interest		75		%	12.88	%	12.12	%	100	%
Mw capacity		386.2			66.4		62.4		515.0
LG&E’s 75% ownership (in thousands of $):
Cost		$	595,747
Accumulated depreciation		182,711
Net book value		$	413,036
Construction work in progress (included above)		$	12,867

 

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LG&E and KU jointly own the following combustion turbines (in thousands of $):

 

				LG&E			KU			Total
Paddy’s Run 13		Ownership %		53		%	47		%	100		%
		Mw capacity		84			74			158
		Cost		$	33,919		$	29,973		$	63,892
		Depreciation		1,711			1,499			3,210
		Net book value		$	32,208		$	28,474		$	60,682
E.W. Brown 5		Ownership %		53		%	47		%	100		%
		Mw capacity		71			63			134
		Cost		$	23,973		$	21,106		$	45,079
		Depreciation		1,206			1,052			2,258
		Net book value		$	22,767		$	20,054		$	42,821
E.W. Brown 6		Ownership %		38		%	62		%	100		%
		Mw capacity		59			95			154
		Cost		$	23,696		$	36,957		$	60,653
		Depreciation		1,770			4,201			5,971
		Net book value		$	21,926		$	32,756		$	54,682
E.W. Brown 7		Ownership %		38		%	62		%	100		%
		Mw capacity		59			95			154
		Cost		$	23,607		$	44,792		$	68,399
		Depreciation		4,054			4,502			8,556
		Net book value		$	19,553		$	40,290		$	59,843
Trimble 5		Ownership %		29		%	71		%	100		%
		Mw capacity		45			110			155
		Cost		$	15,970		$	39,045		$	55,015
		Depreciation		251			614			865
		Net book value		$	15,719		$	38,431		$	54,150
Trimble 6		Ownership %		29		%	71		%	100		%
		Mw capacity		45			110			155
		Cost		$	15,961		$	39,025		$	54,986
		Depreciation		251			614			865
		Net book value		$	15,710		$	38,411		$	54,121
Trimble CT Pipeline		Ownership %		29		%	71		%	100		%
		Cost		$	1,835		$	4,475		$	6,310
		Depreciation		39			96			135
		Net book value		$	1,796		$	4,379		$	6,175

 

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

 

Note 13 - - Segments of Business and Related Information

 

Effective December 31, 1998, LG&E adopted SFAS No. 131, Disclosure About Segments of an Enterprise and Related Information.  LG&E is a regulated public utility engaged in the generation, transmission, distribution, and sale of electricity and the storage, distribution, and sale of natural gas.  Financial data for business segments, follow (in thousands of $):

 

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		Electric			Gas			Total
2002
Operating revenues		$	758,491	(a)	$	267,693		$	1,026,184
Depreciation and amortization		90,248			15,658			105,906
Interest income		381			76			457
Interest expense		24,837			4,968			29,805
Operating income taxes		49,010			6,025			55,035
Net income		79,246			9,683			88,929
Total assets		2,105,956			455,122			2,561,078
Construction expenditures		195,662			24,754			220,416
2001
Operating revenues		$	705,925	(b)	$	290,775		$	996,700
Depreciation and amortization		85,572			14,784			100,356
Interest income		616			132			748
Interest expense		31,295			6,627			37,922
Operating income taxes		55,527			7,925			63,452
Net income		95,103			11,768			106,781
Total assets		1,985,252			463,102			2,448,354
Construction expenditures		227,107			25,851			252,958
2000
Operating revenues		$	710,958	(c)	$	272,489		$	983,447
Depreciation and amortization		84,761			13,530			98,291
Interest income		2,551			552			3,103
Interest expense		35,604			7,614			43,218
Operating income taxes		57,869			6,556			64,425
Net income		100,395			10,178			110,573
Total assets		1,760,305			465,779			2,226,084
Construction expenditures		109,798			34,418			144,216

 

(a)                                  Net of provision for rate collections of $12.3 million.

(b)                                 Net of provision for rate refunds of $.7 million.

(c)                                  Net of provision for rate refunds of $2.5 million.

 

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Note 14 - - Selected Quarterly Data (Unaudited)

 

Selected financial data for the four quarters of 2002 and 2001 are shown below.  Because of seasonal fluctuations in temperature and other factors, results for quarters may fluctuate throughout the year.

 

		Quarters Ended
		March			June			September			December
		(Thousands of $)
2002
Operating revenues		$	283,365		$	222,751		$	245,817		$	274,251
Net operating income		28,748			22,410			41,652			25,104
Net income		20,943			15,256			34,204			18,526
Net income available for common stock		19,878			14,207			33,129			17,469
2001
Operating revenues		$	313,271		$	228,841		$	231,885		$	222,703
Net operating income (loss)(a)		(43,732		)	37,624			49,092			98,789
Net income (loss)(a)		(54,115		)	28,467			40,270			92,159
Net income (loss) available for common stock(a)		(55,413		)	27,247			39,160			91,048

 

(a)  Loss resulted from the VDT pre-tax charge of $144.0 million in March 2001, which was reversed in December 2001.  See Note 3.

 

Note 15 - - Subsequent Events

 

LG&E made a contribution to the pension plan of $83.1 million in January 2003.

 

On March 18, 2003, the Kentucky Commission approved LG&E and KU's joint application for the acquisition of four CTs from an unregulated affiliate, LG&E Capital Corp.  The total projected construction cost for the turbines, expected to be available for June 2004 in-service, is $227.4 million.  The requested ownership share of the turbines is 63% for KU and 37% for LG&E.

 

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Louisville Gas and Electric Company
REPORT OF MANAGEMENT

 

The management of Louisville Gas and Electric Company is responsible for the preparation and integrity of the financial statements and related information included in this Annual Report.  These statements have been prepared in accordance with accounting principles generally accepted in the United States applied on a consistent basis and, necessarily, include amounts that reflect the best estimates and judgment of management.

 

LG&E’s 2002 and 2001 financial statements have been audited by PricewaterhouseCoopers LLP, independent accountants, and the 2000 financial statements were audited by Arthur Andersen LLP.  Management made available to PricewaterhouseCoopers LLP and Arthur Andersen LLP (in prior years) all LG&E’s financial records and related data as well as the minutes of shareholders’ and directors’ meetings.

 

Management has established and maintains a system of internal controls that provides reasonable assurance that transactions are completed in accordance with management’s authorization, that assets are safeguarded and that financial statements are prepared in conformity with generally accepted accounting principles.  Management believes that an adequate system of internal controls is maintained through the selection and training of personnel, appropriate division of responsibility, establishment and communication of policies and procedures and by regular reviews of internal accounting controls by LG&E’s internal auditors.  Management reviews and modifies its system of internal controls in light of changes in conditions and operations, as well as in response to recommendations from the internal and external auditors.  These recommendations for the year ended December 31, 2002, did not identify any material weaknesses in the design and operation of LG&E’s internal control structure.

 

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

 

Louisville Gas and Electric Company maintains and internally communicates a written code of business conduct that addresses, among other items, potential conflicts of interest, compliance with laws, including those relating to financial disclosure, and the confidentiality of proprietary information.

 

S. Bradford Rives

Senior Vice President-Finance and Controller

 

Louisville Gas and Electric Company

Louisville, Kentucky

 

97

 

Louisville Gas and Electric Company and Subsidiary

REPORT OF INDEPENDENT ACCOUNTANTS

 

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

 

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of capitalization, income, retained earnings, cash flows and comprehensive income present fairly, in all material respects, the financial position of Louisville Gas and Electric Company and Subsidiary (the “Company”), a wholly-owned subsidiary of LG&E Energy Corp., at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America.  These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audits.  We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

 

/s/ PricewaterhouseCoopers LLP
January 21, 2003 Louisville, Kentucky

 

98

 

Louisville Gas and Electric Company
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

 

To the Shareholders of Louisville Gas and Electric Company:

 

We have audited the accompanying balance sheet and statement of capitalization of Louisville Gas and Electric Company (a Kentucky corporation and a wholly-owned subsidiary of LG&E Energy Corp.) as of December 31, 2000, and the related statements of income, retained earnings, cash flows and comprehensive income for each of the two years in the period ended December 31, 2000.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.

 

We conducted our audits in accordance with auditing standards generally accepted in the United States.  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.  An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

 

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Louisville Gas and Electric Company as of December 31, 2000, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States.

 

Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed under Item 14(a)2 is presented for purposes of complying with the Securities and Exchange Commission’s rules and is not part of the basic financial statements.  This schedule has been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.

 

 

Louisville, Kentucky January 26, 2001

Arthur Andersen LLP

 

 

THIS IS A COPY OF A PREVIOUSLY ISSUED REPORT OF ARTHUR ANDERSEN LLP (“ANDERSEN”) RELATING TO A PRIOR PERIOD FOR WHICH ANDERSEN WAS ENGAGED AS INDEPENDENT PUBLIC ACCOUNTANTS. THE REPORT HAS NOT BEEN REISSUED BY ANDERSEN.

 

99

 

INDEX OF ABBREVIATIONS

 

Capital Corp.		LG&E Capital Corp.
Clean Air Act		The Clean Air Act, as amended in 1990
CCN		Certificate of Public Convenience and Necessity
CT		Combustion Turbines
DSM		Demand Side Management
ECR		Environmental Cost Recovery
EEI		Electric Energy, Inc.
EITF		Emerging Issues Task Force Issue
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
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 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 System Operator
Mmbtu		Million British thermal units
Moody’s		Moody’s Investor Services, Inc.
Mw		Megawatts
Mwh		Megawatt hours
NNS		No-Notice Service
NOPR		Notice of Proposed Rulemaking
NOx		Nitrogen Oxide
OATT		Open Access Transmission Tariff
OMU		Owensboro Municipal Utilities
OVEC		Ohio Valley Electric Corporation
PBR		Performance-Based Ratemaking
PJM		Pennsylvania, New Jersey, Maryland Interconnection
Powergen		Powergen Limited (formerly Powergen plc)
PUHCA		Public Utility Holding Company Act of 1935
ROE		Return on Equity
RTO		Regional Transmission Organization
S&P		Standard & Poor’s Rating Services
SCR		Selective Catalytic Reduction
SEC		Securities and Exchange Commission

 

100

 

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

 

101

 

Kentucky Utilities Company and Subsidiary

Consolidated Statements of Income

(Thousands of $)

 

		Years Ended December 31
		2002			2001			2000
OPERATING REVENUES:
Electric (Note 1)		$	875,192		$	860,426		$	851,941
Provision for rate collections (refunds) (Note 3)		13,027			(954		)	—
Total operating revenues		888,219			859,472			851,941
OPERATING EXPENSES:
Fuel for electric generation		250,117			236,985			219,923
Power purchased		157,955			157,161			166,918
Other operation expenses		144,118			118,359			108,072
Non-recurring charge (Note 3)		—			6,867			—
Maintenance		62,909			57,021			61,643
Depreciation and amortization (Note 1)		95,462			90,299			98,256
Federal and state income taxes (Note 7)		54,032			57,482			51,963
Property and other taxes		14,983			13,928			17,030
Total operating expenses		779,576			738,102			723,805
Net operating income		108,643			121,370			128,136
Other income – net (Note 8)		10,429			8,932			6,843
Interest charges		25,688			34,024			39,455
Net income before cumulative effect of a change in accounting principle		93,384			96,278			95,524
Cumulative effect of a change in accounting principle-accounting for Derivative instruments and hedging activities, net of tax		—			136			—
Net income		93,384			96,414			95,524
Preferred stock dividends		2,256			2,256			2,256
Net income available for common stock		$	91,128		$	94,158		$	93,268

 

Consolidated Statements of Retained Earnings

(Thousands of $)

 

		Years Ended December 31
		2002			2001			2000
Balance January 1		$	410,896		$	347,238		$	329,470
Add net income		93,384			96,414			95,524
		504,280			443,652			424,994
Deduct:  Cash dividends declared on stock:
4.75% cumulative preferred		950			950			950
6.53% cumulative preferred		1,306			1,306			1,306
Common		—			30,500			75,500
		2,256			32,756			77,756
Balance December 31		$	502,024		$	410,896		$	347,238

 

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

 

102

 

Kentucky Utilities Company and Subsidiary

Consolidated Statements of Comprehensive Income

(Thousands of $)

 

		Years Ended December 31
		2002			2001			2000
Net income		$	93,384		$	96,414		$	95,524
Cumulative effect of change in accounting principle – Accounting for derivative instruments and hedging activities		—			2,647			—
Losses on derivative instruments and hedging activities		(2,647		)	—			—
Additional minimum pension liability adjustment (Note 6)		(17,543		)	—			—
Income tax benefit (expense) related to items of other comprehensive income		8,140			(1,059		)	—
Other comprehensive (loss) income, net of tax		(12,050		)	1,588			—
Comprehensive income		$	81,334		$	98,002		$	95,524

 

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

 

103

 

Kentucky Utilities Company and Subsidiary

Consolidated Balance Sheets

(Thousands of $)

 

		December 31
		2002			2001
ASSETS:
Utility plant, at original cost (Note 1)		$	3,089,529		$	2,960,818
Less:  reserve for depreciation		1,536,658			1,457,754
		1,552,871			1,503,064
Construction work in progress		191,233			103,402
		1,744,104			1,606,466
Other property and investments - less reserve of $130 in 2002 and 2001		14,358			9,629
Current assets:
Cash and temporary cash investments (Note 1)		5,391			3,295
Accounts receivable-less reserve of $800 in 2002 and 2001		49,588			45,291
Materials and supplies - at average cost:
Fuel (predominantly coal) (Note 1)		46,090			43,382
Other		26,408			26,188
Prepayments and other		6,584			4,942
		134,061			123,098
Deferred debits and other assets:
Unamortized debt expense (Note 1)		4,991			4,316
Regulatory assets (Note 3)		65,404			66,467
Other		35,465			16,926
		105,860			87,709
		$	1,998,383		$	1,826,902
CAPITAL AND LIABILITIES:
Capitalization (see statements of capitalization):
Common equity		$	814,107		$	735,029
Cumulative preferred stock		40,000			40,000
Long-term debt (Note 9)		346,562			434,506
		1,200,669			1,209,535
Current liabilities:
Current portion of long-term debt (Note 9)		153,930			54,000
Notes payable to parent (Note 10)		119,490			47,790
Accounts payable		95,374			85,149
Accrued taxes		4,955			20,520
Other		21,442			22,150
		395,191			229,609
Deferred credits and other liabilities:
Accumulated deferred income taxes (Notes 1 and 7)		241,184			239,204
Investment tax credit, in process of amortization		8,500			11,455
Accumulated provision for pensions and related benefits (Note 6)		110,927			91,235
Regulatory liabilities (Note 3)		29,876			33,889
Other		12,036			11,975
		402,523			387,758
Commitments and contingencies (Note 11)
		$	1,998,383		$	1,826,902

 

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

 

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

 

		Years Ended December 31
		2002			2001			2000
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	93,384		$	96,414		$	95,524
Items not requiring cash currently:
Depreciation and amortization		95,462			90,299			98,256
Deferred income taxes - net		(2,038		)	(12,088		)	(2,449		)
Investment tax credit - net		(2,955		)	(3,446		)	(3,674		)
Other		(1,267		)	11,776			(8,136		)
Change in certain net current assets:
Accounts receivable		(8,497		)	28			(1,870		)
Materials and supplies		(2,928		)	(31,263		)	18,131
Accounts payable		10,225			8,810			(60,774		)
Accrued taxes		(15,565		)	898			9,120
Prepayments and other		(2,350		)	(6,033		)	850
Sale of accounts receivable (Note 1)		4,200			45,100			—
Other		8,086			(12,364		)	31,272
Net cash flows from operating activities		175,757			188,131			176,250
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sales of securities		—			3,480			—
Construction expenditures		(237,909		)	(142,425		)	(100,328		)
Net cash flows from investing activities		(237,909		)	(138,945		)	(100,328		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term borrowings and repayments		71,700			(13,449		)	61,239
Retirement of long-term debt		(133,930		)	—			(74,784		)
Issuance of long-term debt		128,734			—			12,900
Additional paid-in capital		—			—			15,000
Payment of dividends		(2,256		)	(32,756		)	(96,756		)
Net cash flows used for financing activities		64,248			(46,205		)	(82,401		)
Change in cash and temporary cash investments		2,096			2,981			(6,479		)
Cash and temporary cash investments at beginning of year		3,295			314			6,793
Cash and temporary cash investments at end of year		$	5,391		$	3,295		$	314
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Income taxes		$	59,580		$	72,432		$	49,871
Interest on borrowed money		37,866			39,829			35,196

 

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

 

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Kentucky Utilities Company and Subsidiary

Consolidated Statements of Capitalization

(Thousands of $)

 

		December 31
		2002			2001
COMMON EQUITY:
Common stock, without par value - authorized 80,000,000 shares, outstanding 37,817,878 shares		$	308,140		$	308,140
Additional paid-in-capital		15,000			15,000
Accumulated other comprehensive income		(10,462		)	1,588
Other		(595		)	(595		)
Retained earnings		502,024			410,896
		814,107			735,029

 

CUMULATIVE PREFERRED STOCK:

 

		Shares Outstanding		Current Redemption Price
Without par value, 5,300,000 shares authorized - 4.75% series, $100 stated value
Redeemable on 30 days notice by KU		200,000		$	101.00		20,000			20,000
6.53% series, $100 stated value		200,000		Not redeemable			20,000			20,000
							40,000			40,000
LONG-TERM DEBT (Note 9);
First mortgage bonds - Q due June 15, 2003, 6.32%							62,000			62,000
S due January 15, 2006, 5.99%							36,000			36,000
P due May 15, 2007, 7.92%							53,000			53,000
R due June 1, 2025, 7.55%							50,000			50,000
P due May 15, 2027, 8.55%							33,000			33,000
Pollution control series:
1B due February 1, 2018, 6.25%							—			20,930
2B due February 1, 2018, 6.25%							—			2,400
3B due February 1, 2018, 6.25%							—			7,200
4B due February 1, 2018, 6.25%							—			7,400
8, due September 15, 2016, 7.45%							—			96,000
9, due December 1, 2023, 5.75%							50,000			50,000
10, due November 1, 2024, variable%							54,000			54,000
11, due May 1, 2023, variable%							12,900			12,900
12, due February 1, 2032, variable%							20,930			—
13, due February 1, 2032, variable%							2,400			—
14, due February 1, 2032, variable%							7,400			—
15, due February 1, 2032, variable%							7,200			—
16, due October 1, 2032, variable%							96,000			—
Long-term debt marked to market (Note 4)							15,662			3,676
Total bonds outstanding							500,492			488,506
Less current portion of long-term debt							153,930			54,000
Long-term debt							346,562			434,506
Total capitalization							$	1,200,669		$	1,209,535

 

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

 

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Kentucky Utilities Company and Subsidiary
Notes to Consolidated Financial Statements

 

Note 1 - Summary of Significant Accounting Policies

 

KU, a subsidiary of LG&E Energy and an indirect subsidiary of Powergen and 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 the KU’s Common Stock is held by LG&E Energy.  KU has one wholly owned consolidated subsidiary, KU R.

 

On December 11, 2000, LG&E Energy was acquired by Powergen.  On July 1, 2002, E.ON, a German company, completed its acquisition of Powergen plc (now Powergen Limited).  E.ON had announced its pre-conditional cash offer of £5.1 billion ($7.3 billion) for Powergen on April 9, 2001.  Powergen and E.ON are registered public utility holding companies under PUHCA.  No costs associated with these acquisitions nor any of the effects of purchase accounting have been reflected in the financial statements of KU.

 

Certain reclassification entries have been made to the previous year’s financial statements to conform to the 2002 presentation with no impact on the balance sheet totals or previously reported income.

 

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

 

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

 

Depreciation and Amortization.  Depreciation is provided on the straight-line method over the estimated service lives of depreciable plant. Pursuant to a final order of the Kentucky Commission dated December 3, 2001, KU implemented new deprecation rates effective January 1, 2001.  The amounts provided were approximately 3.1% in 2002, 3.1% in 2001 and 3.5% in 2000, of average depreciable plant. Of the amount provided for depreciation at December 31, 2002, 2001 and 2000, respectively, approximately 0.7% was related to the retirement, removal and disposal costs of long lived assets.

 

Cash and Temporary Cash Investments.  KU considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents.  Temporary cash investments are carried at cost, which approximates fair value.

 

Fuel Inventories.  Fuel inventories of $46.1 million and $43.4 million at December 31, 2002 and 2001, respectively, are included in Fuel in the balance sheet.  The inventory is 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.  See Note 4 - Financial Instruments.

 

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

 

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

 

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

 

Revenue Recognition.  Revenues are recorded based on service rendered to customers through month-end.  KU accrues an estimate for unbilled revenues from each meter reading date to the end of the accounting period.  The unbilled revenue estimates included in accounts receivable were approximately $36.4 million and $33.4 million at December 31, 2002, and 2001, respectively.  KU recorded electric revenues that resulted from sales to a related party, LG&E, of $34.6 million, $31.1 million and $22.1 million for years ended December 31, 2002, 2001 and 2000, respectively.  See Note 3, Rates and Regulatory Matters.

 

Fuel Costs.  The cost of fuel for electric generation is charged to expense as used.

 

Management’s Use of Estimates.  The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported assets and liabilities and disclosure of contingent items at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.  See Note 11, Commitments and Contingencies, for a further discussion.

 

Accounts Receivable Securitization. SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, revises the standards for accounting for securitizations and other transfers of financial assets and collateral and requires certain disclosures, and provides accounting and reporting standards for transfers and servicing of financial assets and extinguishments of liabilities. SFAS No. 140 was adopted in the first quarter of 2001, when KU entered into an accounts receivable securitization transaction.

 

On February 6, 2001, KU implemented an accounts receivable securitization program.  The purpose of this program is to enable KU to accelerate the receipt of cash from the collection of retail accounts receivable, thereby reducing dependence upon more costly sources of working capital. The securitization program allows for a percentage of eligible receivables to be sold.  Eligible receivables are generally all receivables associated with retail sales that have standard terms and are not past due.  KU is able to terminate this program at any time without penalty. If there is a significant deterioration in the payment record of the receivables by the retail customers or if KU fails to meet certain covenants regarding the program, the program may terminate at the election of the financial institutions.  In this case, payments from retail customers would first be used to repay the financial institutions participating in the program, and would then be available for use by KU.

 

As part of the program, KU sold retail accounts receivables to a wholly owned subsidiary, KU R. Simultaneously, KU R entered into two separate three-year accounts receivable securitization facilities with two financial institutions and their affiliates whereby KU R can sell, on a revolving basis, an undivided interest in certain of its receivables and receive up to $50 million from an unrelated third party purchaser.  The effective cost of the receivables programs is comparable to KU’s lowest cost source of capital, and is based on prime rated commercial paper. KU retains servicing rights of the sold receivables through two separate servicing agreements with the third party purchaser.  KU has obtained an opinion from independent legal counsel

 

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indicating these transactions qualify as a true sale of receivables.  As of December 31, 2002, the outstanding program balance was $49.3 million.  KU is considering unwinding its accounts receivable securitization arrangements involving KU R during 2003.

 

The allowance for doubtful accounts associated with the eligible securitized receivables was $520,000 at December 31, 2002.  This allowance is based on historical experience of KU. Each securitization facility contains a fully funded reserve for uncollectible receivables.

 

New Accounting Pronouncements.  The following accounting pronouncements were issued that affected KU in 2002:

 

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 is January 1, 2003.  Management has calculated the impact of SFAS No. 143 and the recently released FERC NOPR No. RM02-7, Accounting, Financial Reporting, and Rate Filing Requirements for Asset Retirement Obligations.  As of January 1, 2003, KU recorded asset retirement obligation (ARO) assets in the amount of $8.6 million and liabilities in the amount of $18.5 million.  KU also recorded a cumulative effect adjustment in the amount of $9.9 million to reflect the accumulated depreciation and accretion of ARO assets at the transition date less the amounts previously accrued under reglatory depreciation. KU recorded offsetting regulatory assets of $9.9 million, pursuant to regulatory treatment prescribed under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation.  Also pursuant to SFAS No. 71, KU recorded regulatory liabilities in the amount of $888,000 offsetting removal costs previously accrued under regulatory accounting in excess of amounts allowed under SFAS No. 143.

 

KU also expects to record ARO accretion expense of approximately $1.2 million, ARO depreciation expense of approximately $176,000 and an offsetting regulatory credit in the income statement of approximately $1.4 million in 2003, pursuant to regulatory treatment prescribed under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation.  The accretion, depreciation and regulatory credit will be annual adjustments.  SFAS No. 143 will have no impact on the results of the operation of KU.

 

KU’s asset retirement obligations are primarily related to the final retirement of generating units.  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 will be recorded for transmission and distribution assets.

 

KU adopted EITF No. 98-10, Accounting for Energy Trading and Risk Management Activities, effective January 1, 1999.  This pronouncement required that energy trading contracts be marked to market on the balance sheet, with the gains and losses shown net in the income statement.  In October 2002, the Emerging Issues Task Force reached a consensus to rescind EITF 98-10.  The effective date for the full rescission will be for fiscal periods beginning after December 15, 2002.  With the recession 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.  KU does not expect the rescission of this standard to have a material impact on financial position or results of operations.

 

In January 2003, the Financial Accounting Standards Board issued Financial Accounting Standards Board

 

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Interpretation No. 46, Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51 (FIN 46).  FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties.  FIN 46 is 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 be applied for the first interim or annual period beginning after June 15, 2003.  KU does not expect the adoption of this standard to have any impact on the financial position or results of operations.

 

Note 2 – Mergers and Acquisitions

 

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

 

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

 

Accounting for the regulated utility business conforms with generally accepted accounting principles as applied to regulated public utilities and as prescribed by FERC, the Kentucky Commission and the Virginia Commission.  KU is subject to SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, under which certain costs that would otherwise be charged to expense are deferred as regulatory assets based on expected recovery from customers in future rates.  Likewise, certain credits that would otherwise be reflected as income are deferred as regulatory liabilities based on expected return to customers in future rates.  KU’s current or expected recovery of deferred costs and expected return of deferred credits is generally based on specific ratemaking decisions or precedent for each item.  The following regulatory assets and liabilities were included in KU’s balance sheets as of December 31 (in thousands of $):

 

		2002			2001
VDT costs		$	38,375		$	48,811
Unamortized loss on bonds		9,456			6,142
LG&E/KU merger costs		2,046			6,139
One utility costs		873			4,365
ESM provision		13,500			—
Other		1,154			1,010
Total regulatory assets		65,404			66,467
Deferred income taxes - net		(28,854		)	(32,872		)
Other		(1,022		)	(1,017		)
Total regulatory liabilities		(29,876		)	(33,889		)
Regulatory assets - net		$	35,528		$	32,578

 

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Kentucky Commission Settlement Order - VDT Costs. During the first quarter 2001, KU recorded a $64 million charge for a workforce reduction program.  Primary components of the charge were separation benefits, enhanced early retirement benefits, and health care benefits.  The result of this workforce reduction was the elimination of approximately 300 positions, accomplished primarily through a voluntary enhanced severance program.

 

On June 1, 2001, KU filed an application (VDT case) with the Kentucky Commission to create a regulatory asset relating to these first quarter 2001 charges.  The application requested permission to amortize these costs over a four-year period.  The Kentucky Commission also opened a case to review a new depreciation study and resulting depreciation rates implemented in 2001.

 

KU reached a settlement in the VDT case as well as the other cases involving depreciation rates and ESM with all intervening parties.  The settlement agreement was approved by the Kentucky Commission on December 3, 2001.  The order allowed KU to set up a regulatory asset of $54 million for the workforce reduction costs and begin amortizing these costs over a five year period starting in April 2001. The first quarter 2001 charge of $64 million represented all employees who had accepted a voluntary enhanced severance program.  Some employees rescinded their participation in the voluntary enhanced severance program and, along with the non-recurring charge of $6.9 million for FERC and Virginia jurisdictions, thereby decreasing the original charge of the regulatory asset from $64 million to $54 million. The settlement will also reduce revenues approximately $11 million through a surcredit on future bills to customers over the same five year period.  The surcredit represents net savings stipulated by KU.  The agreement also established KU’s new depreciation rates in effect December 2001, retroactive to January 1, 2001.  The new depreciation rates decreased depreciation expense by $6.0 million in 2001.

 

PUHCA.  LG&E Energy was purchased by Powergen on December 11, 2000.  Effective July 1, 2002, Powergen was acquired by E.ON, which became a registered holding company under PUHCA.  As a result, E.ON, its utility subsidiaries, including KU, and certain of its non-utility subsidiaries are subject to extensive regulation by the SEC under PUHCA with respect to issuances and sales of securities, acquisitions and sales of certain utility properties, and intra-system sales of certain goods and services.  In addition, PUHCA generally limits the ability of registered holding companies to acquire additional public utility systems and to acquire and retain businesses unrelated to the utility operations of the holding company.  KU believes that it has adequate authority (including financing authority) under existing SEC orders and regulations to conduct its business.   KU will seek additional authorization when necessary.

 

Environmental Cost Recovery.  In June 2000, the Kentucky Commission approved KU’s application for a CCN to construct up to four SCR NOx reduction facilities. The construction and subsequent operation of the SCRs is intended to reduce NOx emission levels to meet the EPA’s mandated NOx emission level of 0.15 lbs./ Mmbtu by May 2004.  In its order, the Kentucky Commission ruled that KU’s proposed plan for construction was “reasonable, cost-effective and will not result in the wasteful duplication of facilities.”  In October 2000, KU filed an application with the Kentucky Commission to amend its Environmental Compliance Plan to reflect the addition of the proposed NOx reduction technology projects and to amend its ECR Tariff to include an overall rate of return on capital investments.  Approval of KU’s application in April 2001 allowed KU to begin to recover the costs associated with these new projects, subject to Kentucky Commission oversight during normal six-month and two-year reviews.

 

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In August 2002, KU filed an application with the Kentucky Commission to amend its compliance plan to allow recovery of the cost of a new and additional environmental compliance facility.  The estimated capital cost of the additional facilities is $17.3 million.  The Kentucky Commission conducted a public hearing on the case on December 20, 2002, final briefs were filed on January 15, 2003, and a final order was issued February 11, 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 will begin with bills rendered in April 2003.

 

ESM. KU’s electric rates are subject to an ESM.  The ESM, initially in place for three years beginning in 2000, sets an upper and lower point for rate of return on equity, whereby if KU’s rate of return for the calendar year falls within the range of 10.5% to 12.5%, no action is necessary.  If earnings are above the upper limit, the excess earnings are shared 40% with ratepayers and 60% with shareholders; if earnings are below the lower limit, the earnings deficiency is recovered 40% from ratepayers and 60% from shareholders.  By order of the Kentucky Commission, rate changes prompted by the ESM filing go into effect in April of each year subject to a balancing adjustment in successive periods.  KU made its second ESM filing on March 1, 2002 for the calendar year 2001 reporting period.  KU is in the process of refunding $1 million to customers for the 2001 reporting period.  KU estimated that the rate of return will fall below the lower limit, subject to Kentucky Commission approval, for the year ended December 31, 2002.   The 2002 financial statements include an accrual to reflect the earnings deficiency of $13.5 million to be recovered from customers commencing in April 2003.

 

On November 27, 2002, KU filed a revised ESM tariff which proposed continuance of the existing ESM through December 2005.  The Kentucky Commission issued an order suspending the ESM tariff one day making the effective date January 2, 2003.  In addition, the Kentucky Commission is conducting a management audit to review the ESM plan and reassess its reasonableness in 2003.  KU and interested parties will have the opportunity to provide recommendations for modification and continuance of the ESM or other forms of alternative or incentive regulation.

 

DSM. In May 2001, the Kentucky Commission approved a plan that would expand LG&E’s current DSM programs into the service territory served by KU.  The filing 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 program based on program planning engineering estimates and post-implementation evaluation.

 

FAC.   KU employs a FAC mechanism which allows KU to recover from customers’ fuel costs associated with retail electric sales.  In July 1999, the Kentucky Commission issued a series of orders requiring KU to refund approximately $10.1 million resulting from reviews of the FAC from November 1994 to October 1998.  In August 1999, after a rehearing request by KU, the Kentucky Commission issued a final order that reduced the refund obligation to $6.7 million ($5.8 million on a Kentucky jurisdictional basis) from the original order amount of $10.1 million.  KU implemented the refund from October 1999 through September 2000.  Both KU and the KIUC appealed the order.   Pending a decision on this appeal, a comprehensive settlement was reached by all parties and approved by the Kentucky Commission on May 17, 2002.  Thereunder, KU agreed to credit its fuel clause in the amount of $954,000 (refund made in June and July 2002), and the parties agreed on a prospective interpretation of the state’s FAC regulation to ensure consistent and mutually acceptable application on a going-forward basis.

 

In December 2002, the Kentucky Commission initiated a two year review of the operation of KU’s FAC for the period November 2000 through October 2002.  Testimony in the review case was filed on January 20, 2003 and a public hearing was held February 18, 2003.  Issues addressed at that time included the establishment of the

 

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current base fuel factor to be included in KU’s base rates, verification of proper treatment of purchased power costs during unit outages, and compliance with fuel procurement policies and practices.

 

Kentucky Commission Administrative Case for Affiliate Transactions. In December 1997, the Kentucky Commission opened Administrative Case No. 369 to consider Kentucky Commission policy regarding cost allocations, affiliate transactions and codes of conduct governing the relationship between utilities and their non-utility operations and affiliates.  The Kentucky Commission intended to address two major areas in the proceedings: the tools and conditions needed to prevent cost shifting and cross-subsidization between regulated and non-utility operations; and whether a code of conduct should be established to assure that non-utility segments of the holding company are not engaged in practices that could result in unfair competition caused by cost shifting from the non-utility affiliate to the utility.  During the period September 1998 to February 2000, the Kentucky Commission issued draft codes of conduct and cost allocation guidelines.  In early 2000, the Kentucky General Assembly enacted legislation, House Bill 897, which authorized the Kentucky Commission to require utilities that provide nonregulated activities to keep separate accounts and allocate costs in accordance with procedures established by the Kentucky Commission. In the same Bill, the General Assembly set forth provisions to govern a 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.  On February 14, 2001, the Kentucky Commission published notice of their intent to promulgate new administrative regulations under the auspices of this new law.  This effort is still on-going.

 

Kentucky Commission Administrative Case for System Adequacy.  On June 19, 2001, Kentucky Governor Paul E. Patton issued Executive Order 2001-771, which directed the Kentucky Commission to review and study issues relating to the need for and development of new electric generating capacity in Kentucky.  The issues to be considered included the impact of new power plants on the electric supply grid, facility citing issues, and economic development matters, with the goal of ensuring a continued, reliable source of supply of electricity for the citizens of Kentucky and the continued environmental and economic vitality of Kentucky and its communities.  In response to that Executive Order, in July 2001 the Kentucky Commission opened Administrative Case No. 387 to review the adequacy of Kentucky’s generation capacity and transmission system.  Specifically, the items reviewed were the appropriate level of reliance on purchased power, the appropriate reserve margins to meet existing and future electric demand, the impact of spikes in natural gas prices on electric utility planning strategies, and the adequacy of Kentucky’s electric transmission facilities.  KU, as a party to this proceeding, filed written testimony and responded to two requests for information.  Public hearings were held October 2001 and KU filed a final brief in the case.  In December 2001, the Kentucky Commission issued an order in which it noted that KU is responsibly addressing the long-term supply needs of native load customers and that current reserve margins are appropriate.  However, due to the rapid pace of change in the industry, the order also requires KU to provide an annual assessment of supply resources, future demand, reserve margin, and the need for new resources.

 

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

 

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

 

FERC SMD NOPR.  On July 31, 2002, the FERC issued a NOPR in Docket No. RM01-12-000 which would

 

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substantially alter the regulations governing the nation’s wholesale electricity markets by establishing a common set of rules — SMD. The SMD NOPR would require each public utility that owns, operates, or controls interstate transmission facilities to become an Independent Transmission Provider (ITP), belong to 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 a final rule is expected during 2003.  While it is expected that the SMD final rule will affect KU revenues and expenses, the specific impact of the rulemaking is not known at this time.

 

MISO.  KU is a member of the MISO, which began commercial operations on February 1, 2002.  MISO now has operational control over KU’s high-voltage transmission facilities (100 kV and greater), while KU continues to control and operate the lower voltage transmission subject to the terms and conditions of the MISO OATT.  As a transmission-owning member of MISO, KU also incurs administrative costs of MISO pursuant to Schedule 10 of the MISO OATT.

 

MISO also proposed to implement a congestion management system.  FERC directed the MISO to coordinate its efforts with FERC’s Rulemaking on SMD. On September 24, 2002, the MISO filed new rate schedules designated as Schedules 16 and 17, which provide for the collection of costs incurred by the MISO to establish day-ahead and real-time energy markets. The MISO proposed to recover these costs under Schedules 16 and 17 once service commences. If approved by FERC, these schedules will cause KU to incur additional costs.  KU opposes the establishment of Schedules 16 and 17.  This effort is still on-going and the ultimate impact of the two schedules, if approved, is not known at this time.

 

ARO.  In 2003, KU expects to record approximately $11.3 million in regulatory assets and approximately $888,000 in regulatory liabilities related to SFAS No. 143, Accounting for Asset Retirement Obligations.

 

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

 

In approving the merger, the Kentucky Commission adopted KU’s proposal to reduce its retail customers’ bills based on one-half of the estimated merger-related savings, net of deferred and amortized amounts, over a five year period.  The surcredit mechanism provides that 50% of the net non-fuel cost savings estimated to be achieved from the merger would be provided to ratepayers through a monthly bill credit, and 50% retained by the Companies, 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 customers the then-projected non-fuel savings associated with the merger.  The Companies submitted this filing on January 13, 2003, proposing to continue to share with customers, on a 50%/50% basis, the estimated fifth-year gross level of non-fuel savings associated with the merger.  The filing is currently under review.

 

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

 

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Note 4 - Financial Instruments

 

The cost and estimated fair values of the KU’s non-trading financial instruments as of December 31, 2002, and 2001 follow (in thousands of $):

 

		2002						2001
		Cost			Fair Value			Cost			Fair Value
Long-term debt (including current portion)		$	484,830		$	503,194		$	484,830		$	499,618
Interest-rate swaps		—			16,928			—			6,906

 

All of the above valuations reflect prices quoted by exchanges except for the swaps.  The fair values of the swaps reflect price quotes from dealers or amounts calculated using accepted pricing models.

 

Interest Rate Swaps. KU uses interest rate swaps to hedge exposure to market fluctuations in certain of its debt instruments.  Pursuant to policy, use of these financial instruments is intended to mitigate risk and earnings volatility and is not speculative in nature.  Management has designated all of the interest rate swaps as hedge instruments.  Financial instruments designated as fair value hedges are periodically marked to market with the resulting gains and losses recorded directly into net income to correspond with income or expense recognized from changes in market value of the items being hedged.

 

As of December 31, 2002 and 2001, KU was party to various interest rate swap agreements with aggregate notional amounts of $153 million in 2002 and 2001.  Under these swap agreements, KU paid variable rates based on either LIBOR or the Bond Market Association’s municipal swap index averaging 2.36% and 2.54%, and received fixed rates averaging 7.13% and 7.13% at December 31, 2002 and 2001, respectively. The swap agreements in effect at December 31, 2002 have been designated as fair value hedges and mature on dates ranging from 2007 to 2025.  For 2002, the effect of marking these financial instruments and the underlying debt to market resulted in immaterial pretax gains recorded in interest expense.

 

Interest rate swaps hedge interest rate risk on the underlying debt under SFAS 133, in addition to swaps being marked to market, the item being hedged must also be marked to market, consequently at December 31, 2002, KU’s debt reflects a $15.7 million mark to market adjustment.

 

Energy Trading & Risk Management Activities.  KU conducts energy trading and risk management activities to maximize the value of power sales from physical assets it owns, in addition to the wholesale sale of excess asset capacity.  Certain energy trading activities are accounted for on a mark-to-market basis in accordance with EITF 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities, SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities.  Wholesale sales of excess asset capacity and wholesale purchases are treated as normal sales and purchases under SFAS No. 133 and SFAS No. 138 and are not marked-to-market.

 

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

 

The table below summarizes KU’s energy trading and risk management activities for 2002 and 2001 (in thousands of $).

 

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		2002			2001
Fair value of contracts at beginning of period, net liability		$	(186	)	$	(17	)
Fair value of contracts when entered into during the period		(65		)	3,441
Contracts realized or otherwise settled during the period		448			(2,894		)
Changes in fair values due to changes in assumptions		(353		)	(716		)
Fair value of contracts at end of period, net liability		$	(156	)	$	(186	)

 

No changes to valuation techniques for energy trading and risk management activities occurred during 2002.  Changes in market pricing, interest rate and volatility assumptions were made during both years.  All contracts outstanding at December 31, 2002, 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, 2002, 86% of the trading and risk management commitments were with counterparties rated BBB- equivalent or better.

 

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 477,000 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, 2002, 100% of total utility revenue was derived from electric operations.

 

In August 2001, KU and its employees represented by IBEW Local 2100 entered into a two-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 Retirement Benefits

 

KU sponsors qualified and non-qualified pension plans and other postretirement benefit plans for its employees. The following tables provide a reconciliation of the changes in the plans’ benefit obligations and fair value of assets over the three-year period ending December 31, 2002, and a statement of the funded status as of December 31 for each of the last three years (in thousands of $):

 

		2002			2001			2000
Pension Plans:
Change in benefit obligation
Benefit obligation at beginning of year		$	244,472		$	233,034		$	219,628
Service cost		2,637			2,761			4,312
Interest cost		16,598			17,534			17,205
Plan amendment		28			4			11,757
Change due to transfers		—			(16,827		)	—
Curtailment loss		—			1,400			—
Special termination benefits		—			24,274			—
Benefits paid		(23,291		)	(29,166		)	(16,512		)
Actuarial (gain) or loss and other		7,283			11,458			(3,356		)
Benefit obligation at end of year		$	247,727		$	244,472		$	233,034
Change in plan assets
Fair value of plans assets at beginning of year		$	216,947		$	244,677		$	274,109
Actual return on plan assets		(13,767		)	18,155			(10,943		)
Employer contributions and plan transfers		(99		)	(15,300		)	(994		)
Benefits paid		(23,291		)	(29,166		)	(16,512		)
Administrative expenses		(1,256		)	(1,419		)	(983		)
Fair value of plan assets at end of year		$	178,534		$	216,947		$	244,677
Reconciliation of funded status
Funded status		$	(69,193	)	$	(27,525	)	$	11,643
Unrecognized actuarial (gain) or loss		36,233			(20,581		)	(36,435		)
Unrecognized transition (asset) or obligation		(532		)	(664		)	(847		)
Unrecognized prior service cost		10,106			11,027			14,176
Net amount recognized at end of year		$	(23,386	)	$	(37,743	)	$	(11,463	)
Other Benefits:
Change in benefit obligation
Benefit obligation at beginning of year		$	83,223		$	64,213		$	54,201
Service cost		610			495			757
Interest cost		6,379			5,433			4,781
Plan amendments		—			—			7,127
Curtailment loss		—			6,381			—
Special termination benefits		—			3,824			—
Benefits paid net of retiree contributions		(4,640		)	(5,446		)	(4,318		)
Actuarial (gain) or loss		19,030			8,323			1,665
Benefit obligation at end of year		$	104,602		$	83,223		$	64,213
Change in plan assets
Fair value of plan assets at beginning of year		$	14,330		$	23,762		$	28,720
Actual return on plan assets		(2,698		)	(4,404		)	(1,162		)
Employer contributions and plan transfers		1,648			473			522
Benefits paid net of retiree contributions		(5,337		)	(5,501		)	(4,318		)
Fair value of plan assets at end of year		$	7,943		$	14,330		$	23,762
Reconciliation of funded status
Funded status		$	(96,659	)	$	(68,893	)	$	(40,451	)
Unrecognized actuarial (gain) or loss		22,667			(437		)	(23,561		)
Unrecognized transition (asset) or obligation		11,209			12,290			21,871
Unrecognized prior service cost		2,891			3,548			6,109
Net amount recognized at end of year		$	(59,892	)	$	(53,492	)	$	(36,032	)

 

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There are no plan assets in the non-qualified plan due to the nature of the plan.

 

KU made a contribution to the pension plan of $3.5 million in January 2003.

 

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, 2002, 2001 and 2000 (in thousands of $):

 

		2002			2001			2000
Pension Plans:
Amounts recognized in the balance sheet consisted of:
Accrued benefit liability		$	(51,035	)	$	(37,743	)	$	(11,463	)
Intangible asset		10,106			—			—
Accumulated other comprehensive income		17,543			—			—
Net amount recognized at year-end		$	(23,386	)	$	(37,743	)	$	(11,463	)
Additional year-end information for plans with accumulated benefit obligations in excess of plan assets (1):
Projected benefit obligation		$	247,727		$	244,472		$	1,505
Accumulated benefit obligation		229,569			224,261			336
Fair value of plan assets		178,534			216,947			—

 

(1) 2002 and 2001 includes all plans. 2000 includes SERPs only.
Other Benefits:
Amounts recognized in the balance sheet consisted of:
Accrued benefit liability		$	(59,892	)	$	(53,492	)	$	(36,032	)
Additional year-end information for plans with benefit obligations in excess of plan assets:
Projected benefit obligation		$	104,602		$	83,223		$	64,213
Fair value of plan assets		7,943			14,330			23,762

 

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The following table provides the components of net periodic benefit cost for the plans for 2002, 2001 and 2000 (in thousands of $):

 

		2002			2001			2000
Pension Plans:
Components of net periodic benefit cost
Service cost		$	2,637		$	2,761		$	4,312
Interest cost		16,598			17,534			17,205
Expected return on plan assets		(18,406		)	(19,829		)	(25,170		)
Amortization of transition (asset) or obligation		(133		)	(136		)	(141		)
Amortization of prior service cost		956			962			1,145
Recognized actuarial (gain) or loss		1			(120		)	(3,410		)
Net periodic benefit cost		$	1,653		$	1,172		$	(6,059	)
Special charges
Prior service cost recognized		$	—		$	1,238		$	—
Special termination benefits		—			24,274			—
Total charges		$	—		$	25,512		$	—
Other Benefits:
Components of net periodic benefit cost
Service cost		$	610		$	495		$	757
Interest cost		6,379			5,433			4,781
Expected return on plan assets		(1,022		)	(1,313		)	(1,768		)
Amortization of prior service cost		691			740			1,018
Amortization of transition (asset) or obligation		1,081			1,193			1,823
Recognized actuarial (gain) or loss		343			(40		)	(820		)
Net periodic benefit cost		$	8,082		$	6,508		$	5,791
Special charges
Transition obligation recognized		$	—		$	7,638		$	—
Prior service cost recognized		—			1,613			—
Special termination benefits		—			3,824			—
Total charges		$	—		$	13,075		$	—

 

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

 

		2002		2001		2000
Weighted-average assumptions as of December 31:
Discount rate		6.75	%	7.25	%	7.75	%
Expected long-term rate of return on plan assets		9.00	%	9.50	%	9.50	%
Rate of compensation increase		3.75	%	4.25	%	4.75	%

 

For measurement purposes, a 12.00% annual increase in the per capita cost of covered health care benefits was assumed for 2003.  The rate was assumed to decrease gradually to 5.00% for 2014 and remain at that level thereafter.

 

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A 1% change in assumed health care cost trend rates would have the following effects (in thousands of $):

 

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		1% Decrease		1% Increase
Effect on total of service and interest cost components for 2002		(422	)	479
Effect on year-end 2002 postretirement benefit obligations		(7,010	)	7,972

 

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 2002, $1.4 million for 2001 and $2.5 million for 2000.

 

Note 7 - Income Taxes

 

Components of income tax expense are shown in the table below (in thousands of $):

 

		2002			2001			2000
Included in operating expenses:
Current            - federal		$	38,524		$	58,337		$	44,927
- state		10,494			13,465			9,333
Deferred          - federal – net		3,467			(12,980		)	(3,254		)
- state – net		1,547			(1,340		)	957
Total		54,032			57,482			51,963
Included in other income - net:
Current            - federal		(685		)	(948		)	349
- state		15			(268		)	67
Deferred          - federal – net		(195		)	863			(122		)
- state – net		(88		)	222			(30		)
Amortization of investment tax credit		(2,955		)	(3,446		)	(3,674		)
Total		(3,908		)	(3,577		)	(3,410		)
Total income tax expense		$	50,124		$	53,905		$	48,553

 

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

 

		2002			2001
Deferred tax liabilities:
Depreciation and other plant-related items		$	271,792		$	269,752
Other liabilities		30,378			33,376
		302,170			303,128
Deferred tax assets:
Investment tax credit		3,431			4,623
Income taxes due to customers		11,609			13,263
Pensions		15,861			4,595
Accrued liabilities not currently deductible and other		30,085			41,443
		60,986			63,924
Net deferred income tax liability		$	241,184		$	239,204

 

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

 

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rate follows:

 

		2002		2001		2000
Statutory federal income tax rate		35.0	%	35.0	%	35.0	%
State income taxes, net of federal benefit		5.5		5.4		4.9
Amortization of investment tax credit		(2.4	)	(2.3	)	(2.6	)
Other differences – net		(3.2	)	(2.2	)	(3.6	)
Effective income tax rate		34.9	%	35.9	%	33.7	%

 

The change in other differences is due to increased non-taxable earnings from an unconsolidated KU investment.

 

Note 8 - Other Income - net

 

Other income – net consisted of the following at December 31 (in thousands of $):

 

		2002			2001			2000
Equity in earnings - subsidiary company		$	6,697		$	1,803		$	2,242
Interest and dividend income		641			1,368			1,206
Gains on fixed asset disposals		157			1,844			5
Income taxes and other		2,934			3,917			3,390
Other income – net		$	10,429		$	8,932		$	6,843

 

Note 9 - First Mortgage Bonds and Pollution Control Bonds

 

Long-term debt and the current portion of long-term debt, summarized below (in thousands of $), consists primarily of first mortgage bonds and pollution control bonds.  Interest rates and maturities in the table below are for the amounts outstanding at December 31, 2002.

 

		Stated Interest Rates		Weighted Average Interest Rate		Maturities		Principal Amounts
Noncurrent portion		Variable - 8.55%		5.21	%	2006-2032		$	346,562
Current portion		Variable - 6.32%		3.58	%	2003-2032		$	153,930

 

Under the provisions for KU’s variable-rate pollution control bonds Series PCS 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 2002 was 1.58%.

 

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

 

In 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

 

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February 1, 2018.

 

In May 2000, KU issued the Mercer County Solid Waste Disposal Facility Revenue Bonds, 2000 Series A variable rate debt, for $12.9 million.  These proceeds were used to redeem $4 million PCB Series 7, 7.38% bonds and $8.9 million of PCB Series 7, 7.6% bonds.  In June 2000, $61.5 million Series Q, 5.95% First Mortgage Bond matured and was paid in full.

 

KU’s First Mortgage Bond, 6.32% Series Q of $62 million is scheduled to mature in June 2003,  KU’s First Mortgage Bond, 5.99% Series S of $36 million matures in 2006, and KU’s First Mortgage Bond, 7.92% Series P of $53 million matures in 2007.  There are no scheduled maturities of Pollution Control Bonds for the five years subsequent to December 31, 2002.

 

Substantially all of KU’s utility plant is pledged as security for its First Mortgage Bonds.

 

Note 10 - - Notes Payable to Parent

 

KU participates in an intercompany money pool agreement wherein LG&E Energy can make funds available to KU at market based rates up to $400 million.  The balance of the money pool loan from LG&E Energy was $119.5 million at a  rate of 1.61% and $47.8 million at an average rate of 2.37% at December 31, 2002 and 2001, respectively.  The remaining money pool availability at December 31, 2002, was $280.5 million. LG&E Energy maintains facilities of $450 million with affiliates to ensure funding availability for the money pool.  The outstanding balance under these facilities as of December 31, 2002 was $230 million, and availability of $220 million remained.

 

Note 11 - Commitments and Contingencies

 

Construction Program.  KU had approximately $6.2 million of commitments in connection with its construction program at  December 31, 2002.  Construction expenditures for the years 2003 and 2004 are estimated to total approximately $550.0 million; although all of this is not currently committed, including the purchase of four jointly owned CTs, $152.0 million, and construction of NOx equipment, $177.0 million.

 

Operating Leases.  KU leases office space, office equipment, and vehicles.  KU accounts for these leases as operating leases.  Total lease expense for 2002, 2001, and 2000, was $2.6 million, $2.8 million and $2.3 million, respectively.

 

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

 

Environmental.  The Clean Air Act imposed stringent new SO₂ and NOx emission limits on electric generating units.  KU met its Phase I SO₂ requirements primarily through installation of a scrubber on Ghent Unit 1.  KU’s strategy for Phase II SO₂ reductions, which commenced January 1, 2000, is to use accumulated emissions allowances to delay additional capital expenditures and may also include fuel switching or the installation of additional scrubbers.  KU met the NOx emission requirements of the Act through installation of low-NOx burner systems.  KU’s compliance plans are subject to many factors including developments in the emission allowance and fuel markets, future regulatory and legislative initiatives, and advances in clean air control

 

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technology.  KU will continue to monitor these developments to ensure that its environmental obligations are met in the most efficient and cost-effective manner.

 

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

 

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

 

KU is also monitoring several other air quality issues which may potentially impact coal-fired power plants, including the appeal of the D.C. Circuit’s remand of the EPA’s revised air quality standards for ozone and particulate matter, measures to implement EPA’s regional haze rule, and EPA’s December 2000 determination to regulate mercury emissions from power plants.

 

KU owns or formerly owned several properties that contained past MGP operations.  Various contaminants are typically found at such former MGP sites and environmental remediation measures are frequently required.  KU has completed the cleanup of a site owned by KU.  With respect to other former MGP sites no longer owned by KU, KU is unaware of what, if any, additional exposure or liability it may have.

 

In October 1999, approximately 38,000 gallons of diesel fuel leaked from a cracked valve in an underground pipeline at KU’s E.W. Brown Station.  Under the oversight of EPA and state officials, KU commenced immediate spill containment and recovery measures which prevented the spill from reaching the Kentucky River.  KU ultimately recovered approximately 34,000 gallons of diesel fuel.  In November 1999, the Kentucky Division of Water issued a notice of violation for the incident.  KU is currently negotiating with the state in an effort to reach a complete resolution of this matter.  KU incurred costs of approximately $1.8 million and received insurance reimbursement of $1.2 million.  In December 2002, the Department of Justice (DOJ) sent correspondence to KU regarding a potential per-day fine for failure to timely submit a spill control plan and a per-gallon fine for the amount of oil discharged.  KU and the DOJ have commenced settlement discussions using existing DOJ settlement guidelines on this matter.

 

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

 

122

 

Purchased Power.  KU has purchase power arrangements with OMU, EEI and other parties.  Under the OMU agreement, which expires on January 1, 2020, KU purchases all of the output of a 400-Mw generating station not required by OMU.  The amount of purchased power available to KU during 2003-2007, which is expected to be approximately 8% of KU’s total kWh native load energy requirements, is dependent upon a number of factors including the units’ availability, maintenance schedules, fuel costs and OMU requirements.  Payments are based on the total costs of the station allocated per terms of the OMU agreement, which generally follow delivered kWh.  Included in the total costs is KU’s proportionate share of debt service requirements on $149.6 million of OMU bonds outstanding at December 31, 2002.  The debt service is allocated to KU based on its annual allocated share of capacity, which averaged approximately 50% in 2002.

 

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 several other contracts for purchased power of various Mw capacities.

 

The estimated future minimum annual payments under purchased power agreements for the years subsequent to December 31, 2002, are as follows (in thousands of $):

 

2003		$	34,317
2004		39,653
2005		39,653
2006		39,884
2007		39,994
Thereafter		643,946
Total		$	837,447

 

Note 12 – Jointly Owned Electric Utility Plant

 

LG&E and KU jointly own the following combustion turbines (in thousands of $):

 

				LG&E			KU			Total
Paddy’s Run 13		Ownership%		53		%	47		%	100		%
		Mw capacity		84			74			158
		Cost		$	33,919		$	29,973		$	63,892
		Depreciation		1,711			1,499			3,210
		Net book value		$	32,208		$	28,474		$	60,682
E.W. Brown 5		Ownership%		53		%	47		%	100		%
		Mw capacity		71			63			134
		Cost		$	23,973		$	21,106		$	45,079
		Depreciation		1,206			1,052			2,258
		Net book value		$	22,767		$	20,054		$	42,821
E.W. Brown 6		Ownership%		38		%	62		%	100		%
		Mw capacity		59			95			154
		Cost		$	23,696		$	36,957		$	60,653
		Depreciation		1,770			4,201			5,971
		Net book value		$	21,926		$	32,756		$	54,682
E.W. Brown 7		Ownership%		38		%	62		%	100		%
		Mw capacity		59			95			154
		Cost		$	23,607		$	44,792		$	68,399
		Depreciation		4,054			4,502			8,556
		Net book value		$	19,553		$	40,290		$	59,843
Trimble 5		Ownership%		29		%	71		%	100		%
		Mw capacity		45			110			155
		Cost		$	15,970		$	39,045		$	55,015
		Depreciation		251			614			865
		Net book value		$	15,719		$	38,431		$	54,150
Trimble 6		Ownership%		29		%	71		%	100		%
		Mw capacity		45			110			155
		Cost		$	15,961		$	39,025		$	54,986
		Depreciation		251			614			865
		Net book value		$	15,710		$	38,411		$	54,121
Trimble CT Pipeline		Ownership%		29		%	71		%	100		%
		Cost		$	1,835		$	4,475		$	6,310
		Depreciation		39			96			135
		Net book value		$	1,796		$	4,379		$	6,175

 

123

 

See also Note 11, Construction Program, for KU’s planned purchase of four jointly owned CTs in 2004.

 

Note 13 - - Selected Quarterly Data (Unaudited)

 

Selected financial data for the four quarters of 2002 and 2001 are shown below.  Because of seasonal fluctuations in temperature and other factors, results for quarters may fluctuate throughout the year.

 

		Quarters Ended
		March			June			September			December
		(Thousands of $)
2002
Revenues		$	215,168		$	203,555		$	239,020		$	230,476
Net operating income		28,200			20,047			31,028			29,368
Net income		24,357			12,752			31,085			25,190
Net income available for common stock		23,793			12,188			30,521			24,626
2001
Revenues		$	211,793		$	219,360		$	216,370		$	211,949
Net operating income (loss)(a)		(344		)	28,422			30,253			63,039
Net income (loss)(a)		(7,995		)	22,080			26,340			55,989
Net income (loss) available for common stock(a)		(8,559		)	21,516			25,776			55,425

 

(a)                                  Loss resulted from the VDT pre-tax charge of $64.0 million in March 2001, which $57.1 million was reversed in

 

124

 

December 2001.  See Note 3.

 

Note 14 – Subsequent Events

 

In January 2003, the Kentucky Commission reviewed the FAC of KU 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 $673,000. 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 KU’s fuel procurement functions.

 

 On February 15, 2003, KU experienced a severe ice storm in Lexington, Kentucky, and surrounding service area causing over 140,000 customers to lose power.  KU is still in the process of accumulating the costs of the storm.  Costs relate to repair of transmission and distribution system, property damage, and significant labor costs, including contractor costs.  A portion of the costs may be offset by insurance proceeds.

 

On March 18, 2003, the Kentucky Commission approved LG&E and KU's joint application for the acquisition of four CTs from an unregulated affiliate, LG&E Capital Corp.  The total projected construction cost for the turbines, expected to be available for June 2004 in-service, is $227.4 million.  The requested ownership share of the turbines is 63% for KU and 37% for LG&E.

 

 

125

 

Kentucky Utilities Company

REPORT OF MANAGEMENT

 

The management of Kentucky Utilities Company is responsible for the preparation and integrity of the financial statements and related information included in this Annual Report.  These statements have been prepared in accordance with accounting principles generally accepted in the United States applied on a consistent basis and, necessarily, include amounts that reflect the best estimates and judgment of management.

 

KU’s 2002 and 2001 financial statements have been audited by PricewaterhouseCoopers LLP, independent accountants and the 2000 financial statements were audited by Arthur Andersen LLP.  Management made available to PricewaterhouseCoopers LLP and to Arthur Andersen LLP (in prior years) all KU’s financial records and related data as well as the minutes of shareholders’ and directors’ meetings.

 

Management has established and maintains a system of internal controls that provide reasonable assurance that transactions are completed in accordance with management’s authorization, that assets are safeguarded and that financial statements are prepared in conformity with generally accepted accounting principles.  Management believes that an adequate system of internal controls is maintained through the selection and training of personnel, appropriate division of responsibility, establishment and communication of policies and procedures and by regular reviews of internal accounting controls by KU’s internal auditors.  Management reviews and modifies its system of internal controls in light of changes in conditions and operations, as well as in response to recommendations from the internal and external auditors.  These recommendations for the year ended December 31, 2002, did not identify any material weaknesses in the design and operation of KU’s internal control structure.

 

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

 

Kentucky Utilities Company maintains and internally communicates a written code of business conduct that addresses, among other items, potential conflicts of interest, compliance with laws, including those relating to financial disclosure, and the confidentiality of proprietary information.

 

S. Bradford Rives

Senior Vice President-Finance and Controller

 

Kentucky Utilities Company

Louisville, Kentucky

 

126

 

Kentucky Utilities Company and Subsidiary

REPORT OF INDEPENDENT ACCOUNTANTS

 

To the Shareholders of Kentucky Utilities Company and Subsidiary:

 

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of capitalization, income, retained earnings, cash flows and comprehensive income present fairly, in all material respects, the financial position of Kentucky Utilities Company and Subsidiary (the “Company”), a wholly-owned subsidiary of LG&E Energy Corp., at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America.  These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audits.  We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audits 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.

 

/s/ PricewaterhouseCoopers LLP
January 21, 2003
Louisville, Kentucky

 

127

 

Kentucky Utilities Company

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

 

To the Shareholders of Kentucky Utilities Company:

 

We have audited the accompanying balance sheet and statement of capitalization of Kentucky Utilities Company (a Kentucky and Virginia corporation and a wholly-owned subsidiary of LG&E Energy Corp.) as of December 31, 2000, and the related statements of income, retained earnings and cash flows for each of the two years in the period ended December 31, 2000.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.

 

We conducted our audits in accordance with auditing standards generally accepted in the United States.  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.  An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

 

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Kentucky Utilities Company as of December 31, 2000, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States.

 

Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed under Item 14(a)2 is presented for purposes of complying with the Securities and Exchange Commission’s rules and is not part of the basic financial statements.  This schedule has been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.

 

Arthur Andersen LLP

 

Louisville, Kentucky

January 26, 2001

 

 

THIS IS A COPY OF A PREVIOUSLY ISSUED REPORT OF ARTHUR ANDERSEN LLP (“ANDERSEN”) RELATING TO A PRIOR PERIOD FOR WHICH ANDERSEN WAS ENGAGED AS INDEPENDENT PUBLIC ACCOUNTANTS. THE REPORT HAS NOT BEEN REISSUED BY ANDERSEN.

 

128

 

ITEM 9.  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

 

Not applicable.

 

PART III

 

ITEMS 10, 11, 12 and 13 are omitted pursuant to General Instruction G of Form 10-K.  The information required by ITEMS 10, 11, 12 and 13 for LG&E and KU are set forth in Exhibit 99.2 filed herewith and incorporated herein by reference.  Additionally, in accordance with General Instruction G, the information required by ITEM 10 relating to executive officers of LG&E and KU has been included in Part I of this Form 10-K.

 

PART IV

 

ITEM 14.  Controls and Procedures

 

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. During the 90 day period preceding the filing of this report, LG&E and KU conducted an evaluation of such controls and procedures under the supervision and 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. With respect to LG&E’s and KU’s internal controls, there have been no significant changes in internal controls or in other factors that could significantly affect these controls subsequent to the date of their most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

 

ITEM 15.  Exhibits, Financial Statement Schedules, and Reports on Form 8-K.

 

(a)	1.	Financial Statements (included in Item 8):
		LG&E:
		Consolidated statements of income for the three years ended December 31, 2002 (page 70).
		Consolidated statements of retained earnings for the three years ended December 31, 2002 (page 70).
		Consolidated statements of comprehensive income for the three years ended December 31, 2002 (page 71).
		Consolidated balance sheets-December 31, 2002, and 2001 (page 72).
		Consolidated statements of cash flows for the three years ended December 31, 2002 (page 73).
		Consolidated statements of capitalization-December 31, 2002, and 2001 (page 74).
		Notes to consolidated financial statements (pages 75-96).
		Report of management (page 97).
		Reports of independent accountants (pages 98-99).
		KU:
		Consolidated statements of income for the three years ended December 31, 2002 (page 102).
		Consolidated statements of retained earnings for the three years ended December 31, 2002 (page 102).
		Consolidated statements of comprehensive income for the three years ended December 31, 2002 (page 103).

 

129

 

		Consolidated balance sheets-December 31, 2002, and 2001 (page 104).
		Consolidated statements of cash flows for the three years ended December 31, 2002 (page 105).
		Consolidated statements of capitalization-December 31, 2002, and 2001 (page 106).
		Notes to consolidated financial statements (pages 107-125).
		Report of management (page 126).
		Reports of independent accountants (pages 127-128).
	2.	Financial Statement Schedules (included in Part IV):
		Schedule II	Valuation and Qualifying Accounts for the three years ended December 31, 2002, for LG&E (page 150), and KU (page 152).
		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				Description
		LG&E		KU
2.01		ý		ý		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		ý		ý		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		ý		ý		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		ý				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		ý				Copy of By-Laws of LG&E, as amended through June 2, 1999 [Filed as Exhibit 3.02 to LG&E’s Annual Report on Form 10-K for the year ended

 

130

 

		Applicable to Form 10-K of
Exhibit No.		LG&E		KU		Description
						December 31, 1999, and incorporated by reference herein]
3.03				ý		Copy of Amended and Restated Articles of Incorporation of KU [Filed as Exhibits 4.03 and 4.04 to Form 8-K Current Report of KU, dated December 10, 1993, and incorporated by reference herein]
3.04				ý		Copy of By-Laws of KU, as amended through June 2, 1999. [Filed as Exhibit 3.04 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1999, and incorporated by reference herein]
4.01		ý				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		ý				Copy of Supplemental Indenture dated February 1, 1952, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.05 to LG&E’s Registration Statement 2-9371 and incorporated by reference herein]
4.03		ý				Copy of Supplemental Indenture dated February 1, 1954, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.03 to LG&E’s Registration Statement 2-11923 and incorporated by reference herein]
4.04		ý				Copy of Supplemental Indenture dated September 1, 1957, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 2.04 to LG&E’s Registration Statement 2-17047 and incorporated by reference herein]
4.05		ý				Copy of Supplemental Indenture dated October 1, 1960, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 2.05 to LG&E’s Registration Statement 2-24920 and incorporated by reference herein]
4.06		ý				Copy of Supplemental Indenture dated June 1, 1966, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 2.06 to LG&E’s Registration Statement 2-28865 and incorporated by reference herein]
4.07		ý				Copy of Supplemental Indenture dated June 1, 1968, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 2.07 to LG&E’s Registration Statement 2-37368 and incorporated by reference herein]

 

131

 

		Applicable to Form 10-K of
Exhibit No.		LG&E		KU		Description
4.08		ý				Copy of Supplemental Indenture dated June 1, 1970, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 2.08 to LG&E’s Registration Statement 2-37368 and incorporated by reference herein]
4.09		ý				Copy of Supplemental Indenture dated August 1, 1971, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 2.09 to LG&E’s Registration Statement 2-44295 and incorporated by reference herein]
4.10		ý				Copy of Supplemental Indenture dated June 1, 1972, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 2.10 to LG&E’s Registration Statement 2-52643 and incorporated by reference herein]
4.11		ý				Copy of Supplemental Indenture dated February 1, 1975, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 2.11 to LG&E’s Registration Statement 2-57252 and incorporated by reference herein]
4.12		ý				Copy of Supplemental Indenture dated September 1, 1975, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 2.12 to LG&E’s Registration Statement 2-57252 and incorporated by reference herein]
4.13		ý				Copy of Supplemental Indenture dated September 1, 1976, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 2.13 to LG&E’s Registration Statement 2-57252 and incorporated by reference herein]
4.14		ý				Copy of Supplemental Indenture dated October 1, 1976, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 2.14 to LG&E’s Registration Statement 2-65271 and incorporated by reference herein]
4.15		ý				Copy of Supplemental Indenture dated June 1, 1978, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 2.15 to LG&E’s Registration Statement 2-65271 and incorporated by reference herein]
4.16		ý				Copy of Supplemental Indenture dated February 15, 1979, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 2.16 to

 

132

 

		Applicable to Form 10-K of
Exhibit No.		LG&E		KU		Description
						LG&E’s Registration Statement 2-65271 and incorporated by reference herein]
4.17		ý				Copy of Supplemental Indenture dated September 1, 1979, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.17 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1980, and incorporated by reference herein]
4.18		ý				Copy of Supplemental Indenture dated September 15, 1979, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.18 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1980, and incorporated by reference herein]
4.19		ý				Copy of Supplemental Indenture dated September 15, 1981, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.19 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1981, and incorporated by reference herein]
4.20		ý				Copy of Supplemental Indenture dated March 1, 1982, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.20 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1982, and incorporated by reference herein]
4.21		ý				Copy of Supplemental Indenture dated March 15, 1982, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.21 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1982, and incorporated by reference herein]
4.22		ý				Copy of Supplemental Indenture dated September 15, 1982, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.22 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1982, and incorporated by reference herein]
4.23		ý				Copy of Supplemental Indenture dated February 15, 1984, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.23 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1984, and incorporated by reference herein]
4.24		ý				Copy of Supplemental Indenture dated July 1, 1985, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.24 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1985, and incorporated by reference herein]

 

133

 

		Applicable to Form 10-K of
Exhibit No.		LG&E		KU		Description
4.25		ý				Copy of Supplemental Indenture dated November 15, 1986, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.25 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1986, and incorporated by reference herein]
4.26		ý				Copy of Supplemental Indenture dated November 16, 1986, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.26 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1986, and incorporated by reference herein]
4.27		ý				Copy of Supplemental Indenture dated August 1, 1987, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.27 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1987, and incorporated by reference herein]
4.28		ý				Copy of Supplemental Indenture dated February 1, 1989, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.28 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1988, and incorporated by reference herein]
4.29		ý				Copy of Supplemental Indenture dated February 2, 1989, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.29 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1988, and incorporated by reference herein]
4.30		ý				Copy of Supplemental Indenture dated June 15, 1990, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.30 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1990, and incorporated by reference herein]
4.31		ý				Copy of Supplemental Indenture dated November 1, 1990, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.31 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1990, and incorporated by reference herein]
4.32		ý				Copy of Supplemental Indenture dated September 1, 1992, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.32 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein]
4.33		ý				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,

 

134

 

		Applicable to Form 10-K of
Exhibit No.		LG&E		KU		Description
						1992, and incorporated by reference herein]
4.34		ý				Copy of Supplemental Indenture dated August 15, 1993, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.34 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
4.35		ý				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]
4.36		ý				Copy of Supplemental Indenture dated October 15, 1993, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.36 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
4.37		ý				Copy of Supplemental Indenture dated May 1, 2000, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.37 to LG&E’s Annual Report on Form 10-K/A for the year ended December 31, 2000, and incorporated by reference herein]
4.38		ý				Copy of Supplemental Indenture dated August 1, 2000, which is a supplemental instrument to Exhibit 4.01 hereto.  [Filed as Exhibit 4.38 to LG&E’s Annual report on Form 10-K/A for the year ended December 31, 2000, and incorporated by reference herein]
4.39		ý				Copy of Supplemental Indenture dated March 1, 2002, which is a supplemental instrument to Exhibit 4.01 hereto.
4.40		ý				Copy of Supplemental Indenture dated March 15, 2002, which is a supplemental instrument to Exhibit 4.01 hereto.
4.41		ý				Copy of Supplemental Indenture dated October 1, 2002, which is a supplemental instrument to Exhibit 4.01 hereto.
4.42				ý		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

 

135

 

		Applicable to Form 10-K of
Exhibit No.		LG&E		KU		Description
						Exhibit 4.02 in File No. 2-9658), April 1, 1953 (Amended Exhibit 4.02 in File No. 2-10120), April 1, 1955 (Amended Exhibit 4.02 in File No. 2-11476), April 1, 1956 (Amended Exhibit 2.02 in File No. 2-12322), May 1, 1969 (Amended Exhibit 2.02 in File No. 2-32602), April 1, 1970 (Amended Exhibit 2.02 in File No. 2-36410), September 1, 1971 (Amended Exhibit 2.02 in File No. 2-41467), December 1, 1972 (Amended Exhibit 2.02 in File No. 2-46161), April 1, 1974 (Amended Exhibit 2.02 in File No. 2-50344), September 1, 1974 (Exhibit 2.04 in File No. 2-59328), July 1, 1975 (Exhibit 2.05 in File No. 2-59328), May 15, 1976 (Amended Exhibit 2.02 in File No. 2-56126), April 15, 1977 (Exhibit 2.06 in File No. 2-59328), August 1, 1979 (Exhibit 2.04 in File No. 2-64969), May 1, 1980 (Exhibit 2 to Form 10-Q Quarterly Report of KU for the quarter ended June 30, 1980), September 15, 1982 (Exhibit 4.04 in File No. 2-79891), August 1, 1984 (Exhibit 4B to Form 10-K Annual Report of KU for the year ended December 31, 1984), June 1, 1985 (Exhibit 4 to Form 10-Q Quarterly Report of KU for the quarter ended June 30, 1985), May 1, 1990 (Exhibit 4 to Form 10-Q Quarterly Report of KU for the quarter ended June 30, 1990), May 1, 1991 (Exhibit 4 to Form 10-Q Quarterly Report of KU for the quarter ended June 30, 1991), May 15, 1992 (Exhibit 4.02 to Form 8-K of KU dated May 14, 1992), August 1, 1992 (Exhibit 4 to Form 10-Q Quarterly Report of KU for the quarter ended September 30, 1992), June 15, 1993 (Exhibit 4.02 to Form 8-K of KU dated June 15, 1993) and December 1, 1993 (Exhibit 4.01 to Form 8-K of KU dated December 10, 1993), November 1, 1994 (Exhibit 4.C to Form 10-K Annual Report of KU for the year ended December 31, 1994), June 1, 1995 (Exhibit 4 to Form 10-Q Quarterly Report of KU for the quarter ended June 30, 1995) and January 15, 1996 [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]
4.43				ý		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]
4.44				ý		Copy of Supplemental Indenture dated May 1, 2000, which is a supplemental instrument to Exhibit 4.42 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]
4.45		ý				Copy of Supplemental Indenture dated September 1, 2001, which is a supplemental instrument to Exhibit 4.42 hereto. [Filed as Exhibit 4.42 to

 

136

 

		Applicable to Form 10-K of
Exhibit No.		LG&E		KU		Description
						KU’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
4.46				ý		Receivables Purchase Agreement dated as of February 6, 2001 among KU Receivables LLC, Kentucky Utilities Company as Servicer, the Various Purchaser Groups From Time to Time Party Hereto and PNC Bank, National Association, as Administrator. [Filed as Exhibit 4.43 to KU’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
4.47				ý		Purchase and Sale Agreement dated as of February 6, 2001 between KU Receivables LLC and Kentucky Utilities Company. [Filed as Exhibit 4.44 to KU’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
4.48		ý				Receivables Purchase Agreement dated as of February 6, 2001 among LG&E Receivables LLC, Louisville Gas and Electric Company as Servicer, the Various Purchaser Groups From Time to Time Party Hereto and PNC Bank, National Association, as Administrator. [Filed as Exhibit 4.45 to KU’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
4.49		ý				Purchase and Sale Agreement dated as of February 6, 2001 between LG&E Receivables LLC and Louisville Gas and Electric Company. [Filed as Exhibit 4.46 to KU’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
4.50				ý		Copy of Supplemental Indenture dated May 1, 2002, which is a supplemental instrument to Exhibit 4.42 hereto.
4.51				ý		Copy of Supplemental Indenture dated September 1, 2002, which is a supplemental instrument to Exhibit 4.42 hereto.
10.01		ý				Copies of Agreement between Sponsoring Companies re:  Project D of Atomic Energy Commission, dated May 12, 1952, Memorandums of Understanding between Sponsoring Companies re:  Project D of Atomic Energy Commission, dated September 19, 1952 and October 28, 1952, and Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission, dated October 15, 1952. [Filed as Exhibit 13(y) to LG&E’s Registration Statement 2-9975 and incorporated by reference herein]
10.02		ý				Copy of Modification No. 1 dated July 23, 1953, to the Power Agreement

 

137

 

		Applicable to Form 10-K of
Exhibit No.		LG&E		KU		Description
						between Ohio Valley Electric Corporation and Atomic Energy Commission.  [Filed as Exhibit 4.03(b) to LG&E’s Regis­tration Statement 2-24920 and incorporated by reference herein]
10.03		ý				Copy of Modification No. 2 dated March 15, 1964, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission.  [Filed as Exhibit 5.02c to LG&E’s Registra­tion Statement 2-61607 and incorporated by reference herein]
10.04		ý				Copy of Modification No. 3 and No. 4 dated May 12, 1966 and January 7, 1967, respectively, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission.  [Filed as Exhibits 4(a)(13) and 4(a)(14) to LG&E’s Registration Statement 2-26063 and incorporated by reference herein]
10.05		ý				Copy of Modification No. 5 dated August 15, 1967, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission.  [Filed as Exhibit 13(c) to LG&E’s Registra­tion Statement 2-27316 and incorporated by reference herein]
10.06		ý		ý		Copies of (i) Inter-Company Power Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies (which Agreement includes as Exhibit A the Power Agree­ment, dated July 10, 1953, between Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation); (ii) First Supplementary Transmission Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies; (iii) Inter-Company Bond Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies; (iv) Inter-Company Bank Credit Agreement, dated July 10, 1953, between Ohio Valley Electric Corpo­ration and Sponsoring Companies.  [Filed as Exhibit 5.02f to LG&E’s Registration Statement 2-61607 and incorporated by reference herein]
10.07		ý		ý		Copy of Modification No. 1 and No. 2 dated June 3, 1966 and January 7, 1967, respectively, to Inter-Company Power Agreement dated July 10, 1953.  [Filed as Exhibits 4(a)(8) and 4(a)(10) to LG&E’s Registration Statement 2-26063 and incorporated by reference herein]
10.08		ý				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]

 

138

 

		Applicable to Form 10-K of
Exhibit No.		LG&E		KU		Description
10.09		ý				Copy of Modification No. 1, dated August 20, 1958, to First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies.  [Filed as Exhibit 5.02i to LG&E’s Registration Statement 2-61607 and incorporated by reference herein]
10.10		ý				Copy of Modification No. 2, dated April 1, 1965, to the First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies.  [Filed as Exhibit 5.02j to LG&E’s Registration Statement 2-61607 and incorporated by reference herein]
10.11		ý				Copy of Modification No. 3, dated January 20, 1967, to First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies.  [Filed as Exhibit 4(a)(7) to LG&E’s Registration Statement 2-26063 and incorporated by reference herein]
10.12		ý				Copy of Modification No. 6 dated November 15, 1967, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission.  [Filed as Exhibit 4(g) to LG&E’s Registration Statement 2-28524 and incorporated by reference herein]
10.13		ý		ý		Copy of Modification No. 3 dated November 15, 1967, to the Inter-Company Power Agreement dated July 10, 1953.  [Filed as Exhibit 4.02m to LG&E’s Registration Statement 2-37368 and incorporated by reference herein]
10.14		ý				Copy of Modification No. 7 dated November 5, 1975, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission.  [Filed as Exhibit 5.02n to LG&E’s Registration Statement 2-56357 and incorporated by reference herein]
10.15		ý		ý		Copy of Modification No. 4 dated November 5, 1975, to the Inter-Company Power Agreement dated July 10, 1953.  [Filed as Exhibit 5.02o to LG&E’s Registration Statement 2-56357 and incorporated by reference herein]
10.16		ý				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

 

139

 

		Applicable to Form 10-K of
Exhibit No.		LG&E		KU		Description
						reference herein]
10.17		ý				Copy of Modification No. 8 dated June 23, 1977, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission.  [Filed as Exhibit 5.02q to LG&E’s Registration Statement 2-61607 and incorporated by reference herein]
10.18		ý				Copy of Modification No. 9 dated July 1, 1978, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission.  [Filed as Exhibit 5.02r to LG&E’s Registration Statement 2-63149 and incorporated by reference herein]
10.19		ý				Copy of Modification No. 10 dated August 1, 1979, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission.  [Filed as Exhibit 2 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1979, and incorporated by reference herein]
10.20		ý				Copy of Modification No. 11 dated September 1, 1979, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission.  [Filed as Exhibit 3 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1979, and incorporated by reference herein]
10.21		ý		ý		Copy of Modification No. 5 dated September 1, 1979, to Inter-Company Power Agreement dated July 5, 1953, among Ohio Valley Electric Corporation and Sponsoring Companies.  [Filed as Exhibit 4 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1979, and incorporated by reference herein]
10.22		ý				Copy of Modification No. 12 dated August 1, 1981, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission.  [Filed as Exhibit 10.25 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1981, and incorporated by reference herein]
10.23		ý		ý		Copy of Modification No. 6 dated August 1, 1981, to Inter-Company Power Agreement dated July 5, 1953, among Ohio Valley Electric Corporation and Sponsoring Companies.  [Filed as Exhibit 10.26 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1981, and incorporated by reference herein]
10.24		ý				*  Copy of Non-Qualified Savings Plan covering officers of the Company,

 

140

 

		Applicable to Form 10-K of
Exhibit No.		LG&E		KU		Description
						effective January 1, 1992.  [Filed as Exhibit 10.43 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein]
10.25		ý				Copy of Modification No. 13 dated September 1, 1989, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission.  [Filed as Exhibit 10.42 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
10.26		ý				Copy of Modification No. 14 dated January 15, 1992, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission.  [Filed as Exhibit 10.43 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
10.27		ý		ý		Copy of Modification No. 7 dated January 15, 1992, to Inter-Company Power Agreement dated July 10, 1953, among Ohio Valley Electric Corporation and Sponsoring Companies.  [Filed as Exhibit 10.44 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
10.28		ý				Copy of Modification No. 15 dated February 15, 1993, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission.  [Filed as Exhibit 10.45 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
10.29		ý				Copies of Firm No-Notice Transportation Agreements each effective November 1, 1993, between Texas Gas Transmission Corporation and LG&E (expiring October 31, 2000, 2001 and 2003)  covering the transmission of natural gas.  [All filed as Exhibit 10.47 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
10.30		ý		ý		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]
10.31		ý				Copy of Amendment dated March 1, 1995, to Firm No-Notice Transportation Agreements dated November 1, 1993 (2-Year, 5-Year and 8-Year),

 

141

 

		Applicable to Form 10-K of
Exhibit No.		LG&E		KU		Description
						between Texas Gas Transmission Corporation and LG&E covering the transmission of natural gas.  [Filed as Exhibit 10.44 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.32		ý		ý		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]
10.34		ý				Copies of Firm Transportation Agreements, each dated March 1, 1995, between Texas Gas Transmission Corporation and LG&E (expiring October 31, 2001 and 2003) covering the transportation of natural gas.  [Both filed as Exhibit 10.45 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.35		ý				Copy of Firm Transportation Agreement, dated March 1, 1995, between Texas Gas Transmission Corporation and LG&E (expires October 31, 2000) covering the transportation of natural gas. [Filed as Exhibit 10.41 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1996, and incorporated by reference herein]
10.36		ý				*  Copy of Amendment to the Non-Qualified Savings Plan, effective January 1, 1992.  [Filed as Exhibit 10.55 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.37		ý				*  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]
10.38		ý				*  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]
10.39		ý		ý		*  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]

 

142

 

		Applicable to Form 10-K of
Exhibit No.		LG&E		KU		Description
10.40		ý				Copy of Coal Supply Agreement between LG&E and Kindill Mining, Inc., dated July 1, 1997.  [Filed as Exhibit 10.76 to LG&E Energy’s Annual Report on Form 10-K for the year ended December 31, 1997, and incorporated by reference herein]
10.41		ý				Copies of Amendments dated September 23, 1997, to Firm No-Notice Transportation Agreements dated November 1, 1993, between Texas Gas Transmission Corporation and LG&E, as amended.  [Filed as Exhibit 10.81 to LG&E Energy’s Annual Report on Form 10-K for the year ended December 31, 1997, and incorporated by reference herein]
10.42		ý				Copies of Amendments dated September 23, 1997, to Firm Transportation Agreements dated March 1, 1995, between Texas Gas Transmission Corporation and LG&E, as amended.  [Filed as Exhibit 10.82 to LG&E Energy’s Annual Report on Form 10-K for the year ended December 31, 1997, and incorporated by reference herein]
10.43		ý		ý		Copy of Coal Supply Agreement between LG&E and KU and Black Beauty Coal Company, dated as of January 1, 2002, covering the purchase of coal.  [Filed as Exhibit 10.51 to LG&E’s and KU’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
10.44		ý		ý		Copy of Coal Supply Agreement between LG&E and KU and McElroy Coal Company, Consolidation Coal Company, Consol Pennsylvania Coal Company, Greenon Coal Company, Nineveh Coal Company, Eighty Four Mining Company and Island Creek Coal Company, dated as of January 1, 2000, and Amendment No. 1 dated as of January 1, 2002, for the purchase of coal. [Filed as Exhibit 10.52 to LG&E’s and KU’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
10.45				ý		Copy of Coal Supply Agreement between KU and Arch Coal Sales Company, Inc., as agent for the independent operating subsidiaries of Arch Coal, Inc., dated as of July 22, 2001, for the purchase of coal. [Filed as Exhibit 10.53 to KU’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
10.46		ý				Copy of Coal Supply Agreement between LG&E and Hopkins County Coal, LLC and Alliance Coal Sales, a division of Alliance Coal, LLC, dated as of January 1, 2002, for the purchase of coal. [Filed as Exhibit 10.54 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]

 

143

 

		Applicable to Form 10-K of
Exhibit No.		LG&E		KU		Description
10.47				ý		Copy of Coal Supply Agreement between KU and Arch Coal Sales Company, Inc., as agent for the independent operating subsidiaries of Arch Coal, Inc., dated as of August 12, 2001, for the purchase of coal. [Filed as Exhibit 10.55 to KU’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
10.48				ý		Copy of Purchase Order dated December 26, 2000, by and between Kentucky Utilities Company and AEI Coal Sales Company, Inc., for the purchase of coal, commencing January 1, 2001. [Filed as Exhibit 10.56 to KU’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
10.49		ý				Copy of Amendment dated November 6, 2000, to Firm Transportation Agreement between LG&E and Texas Gas Transmission Corporation covering the transmission of natural gas (expires October 31, 2006). [Filed as Exhibit 10.57 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
10.50		ý				Copy of Amendment dated November 6, 2000, to Firm Transportation Agreement between LG&E and Texas Gas Transmission Corporation covering the transmission of natural gas (expires October 31, 2008). [Filed as Exhibit 10.58 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
10.51		ý				Copy of Amendment dated November 6, 2000, to Firm No-Notice Transportation Agreement between LG&E and Texas Gas Transmission Corporation covering the transmission of natural gas (expires October 31, 2006). [Filed as Exhibit 10.59 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
10.52		ý				Copy of Amendment dated September 15, 1999, to Firm Transportation Agreement between LG&E and Texas Gas Transmission Corporation covering the transmission of natural gas (expires October 31, 2006). [Filed as Exhibit 10.60 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated by reference herein]
10.53		ý		ý		*  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]

 

144

 

		Applicable to Form 10-K of
Exhibit No.		LG&E		KU		Description
10.54		ý		ý		* 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.
10.55		ý		ý		* 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]
10.56		ý		ý		* 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]
10.57		ý		ý		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]
10.58		ý		ý		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]
10.59		ý				Copy of Letter Amendment, dated September 15, 1999, to Transportation Agreement, dated November 1, 1993, between LG&E and Texas Gas Transmission Corporation. [Filed as Exhibit 10.106 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 1999, and incorporated by reference herein]
10.60		ý		ý		* 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]
10.61		ý		ý		* Copy of two forms of Change-In-Control Agreement applicable to certain employees of LG&E Energy Corp. and its subsidiaries. [Filed as

 

145

 

		Applicable to Form 10-K of
Exhibit No.		LG&E		KU		Description
						Exhibit 10.110 to LG&E’s Annual Report on Form 10-K for the year ended December 31, 2000, and incorporated by reference herein]
10.62		ý		ý		* 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]
10.63		ý		ý		* 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.
10.64		ý				Copy of Amendment dated June 5, 2002, to Firm No-Notice Transportation Agreement dated November 1, 1993, between LG&E and Texas Gas Transmission Corporation covering the transmission of natural gas (expires October 31, 2008).
10.65		ý				Copy of Firm Transportation Service Agreement dated November 1, 2002, between LG&E and Tennessee Gas Pipeline Company covering the transmission of natural gas (expires October 31, 2012).
10.66		ý				Copy of Amendment No. 1 dated January 1, 2001, to Coal Supply Agreement dated July 1, 1997, between LG&E and Kindill Mining, Inc.
10.67		ý				Copy of Amendment No. 2 dated January 1, 2002, to Coal Supply Agreement dated July 1, 1997, between LG&E and Kindill Mining, Inc.
10.68		ý		ý		Copy of Amendment No. 2 dated January 1, 2003, to Coal Supply Agreement dated January 1, 2000, between LG&E and KU and McElroy Coal Company, Consolidation Coal Company, Consol Pennsylvania Coal Company, Greenon Coal Company, Nineveh Coal Company, Eighty Four Mining Company and Island Creek Coal Company.
10.69		ý				Copy of Coal Supply Agreement dated January 1, 2003, between LG&E and Peabody Coalsales Company.
10.70		ý				Copy of Coal Supply Agreement dated January 1, 2002, between LG&E and Peabody Coalsales Company.

 

146

 

		Applicable to Form 10-K of
Exhibit No.		LG&E		KU		Description
10.71		ý				Copy of  Amendment No. 1 dated June 1, 2002, to Coal Supply Agreement dated January 1, 2002, between LG&E and Peabody Coalsales Company.
10.72		ý				Copy of  Amendment No. 2 dated January 1, 2003, to Coal Supply Agreement dated January 1, 2002, between LG&E and Peabody Coalsales Company.
10.73				ý		Copy of Coal Supply Agreement dated January 1, 2002, between KU and Massey Coal Sales Company, Inc.
10.74		ý		ý		*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.
10.75		ý		ý		*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.
10.76		ý		ý		*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.
10.77		ý		ý		*Copies of Contract of Employment, dated June 22, 1999, Terms of Condition of Assignment, dated December 19, 2000, and Amendment to the Terms and Conditions of Assignment, dated June 27, 2002, by and among, as applicable, Powergen UK plc, Powergen plc, LG&E Energy Corp. and an executive officer of the Companies.
10.78		ý		ý		*Copy of Powergen UK Long Term Incentive Plan, November 2002, applicable to certain executive officers of the Companies.
10.79		ý		ý		*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.
12		ý		ý		Computation of Ratio of Earnings to Fixed Charges for LG&E and KU.
21		ý		ý		Subsidiaries of the Registrants.
23.01		ý				Consents of Independent Accountants for LG&E.
23.02				ý		Consents of Independent Accountants for KU.
24		ý		ý		Powers of Attorney.
99.01		ý		ý		Cautionary Statement for purposes of the “Safe Harbor” provisions of the Private Securities Litigation Reform Act of 1995.
99.02		ý		ý		LG&E and KU Director and Officer Information.

 

(b)                                 Executive Compensation Plans and Arrangements:

 

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

 

(c)                                  Reports on Form 8-K:

 

147

 

On November 14, 2002, LG&E and KU filed a current report on Form 8-K, submitting certifications of the Chairman, President, and Chief Executive Officer and the Chief Financial Officer of each company, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 regarding the companies’ Quarterly Reports on Form 10-Q for the period ended September 30, 2002.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

148

 

Report of Independent Accountants
on Financial Statement Schedules

 

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

 

Our audits of the consolidated financial statements of Louisville Gas and Electric Company and Subsidiary as of December 31, 2002 and for each of the two years in the period ended December 31, 2002, referred to in our report dated January 21, 2003 also included an audit of the financial statement schedule listed in Item 14(a)2 of this Form 10-K.  In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein as of December 31, 2002 and for the year then ended when read in conjunction with the related consolidated financial statements.

 

/s/ PricewaterhouseCoopers LLP

January 21, 2003

Louisville, Kentucky

 

149

 

Schedule II

 

Louisville Gas and Electric Company
Schedule II - Valuation and Qualifying Accounts
For the Three Years Ended December 31, 2002
(Thousands of $)

 

		Other Property and Investments			Accounts Receivable (Uncollectible Accounts)
Balance December 31, 1999		$	63		$	1,233
Additions:
Charged to costs and expenses		—			2,803
Deductions:
Net charges of nature for which reserves were created		—			2,750
Balance December 31, 2000		63			1,286
Additions:
Charged to costs and expenses		—			4,953
Deductions:
Net charges of nature for which reserves were created		—			4,664
Balance December 31, 2001		63			1,575
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

 

150

 

Report of Independent Accountants
on Financial Statement Schedules

 

To the Shareholders of Kentucky Utilities Company and Subsidiary:

 

Our audits of the consolidated financial statements of Kentucky Utilities Company and Subsidiary as of December 31, 2002 and for each of the two years in the period ended December 31, 2002, referred to in our report dated January 21, 2003 also included an audit of the financial statement schedule listed in Item 14(a)2 of this Form 10-K.  In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein as of December 31, 2002 and for the year then ended when read in conjunction with the related consolidated financial statements.

 

/s/ PricewaterhouseCoopers LLP

January 21, 2003

Louisville, Kentucky

 

151

 

Schedule II

 

Kentucky Utilities Company
Schedule II - Valuation and Qualifying Accounts
For the Three Years Ended December 31, 2002
(Thousands of $)

 

		Other Property and Investments			Accounts Receivable (Uncollectible Accounts)
Balance December 31, 1999		$	687		$	800
Additions:
Charged to costs and expenses		64			1,430
Deductions:
Net charges of nature for which reserves were created		—			1,430
Balance December 31, 2000		751			800
Additions:
Charged to costs and expenses		9			1,528
Deductions:
Net charges of nature for which reserves were created		630			1,528
Balance December 31, 2001		130			800
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

 

152

 

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 25, 2003	/s/ S. Bradford Rives
(Date)

 

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

 

Signature				Title		Date
Victor A. Staffieri				Chairman of the Board, President and Chief Executive Officer (Principal Executive Officer);
Richard Aitken-Davies				Chief Financial Officer (Principal Financial Officer);
S. Bradford Rives				Senior Vice President – Finance and Controller (Principal Accounting Officer);
Michael Söhlke				Director;
Edmund A. Wallis				Director.
By	/s/ S. Bradford Rives					March 25, 2003
	(Attorney-In-Fact)

 

153

 

 

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 25, 2003	/s/ S. Bradford Rives
(Date)

 

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

 

Signature				Title		Date
Victor A. Staffieri				Chairman of the Board, President and Chief Executive Officer (Principal Executive Officer);
Richard Aitken-Davies				Chief Financial Officer (Principal Financial Officer);
S. Bradford Rives				Senior Vice President – Finance and Controller (Principal Accounting Officer);
Michael Söhlke				Director;
Edmund A. Wallis				Director.
By	/s/ S. Bradford Rives					March 25, 2003
	(Attorney-In-Fact)

 

154

 

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-14 and 15d-14) for the registrant and have:

 

a) designed such disclosure controls and procedures 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 as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

 

c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

 

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, 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 in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

 

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

 

6. The registrant’s other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

 

Date:  March 25, 2003
/s/  Victor A. Staffieri
Victor A. Staffieri
Chairman of the Board, President and Chief Executive Officer

 

155

 

Louisville Gas and Electric Company

 

I, Richard Aitken-Davies, 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-14 and 15d-14) for the registrant and have:

 

a) designed such disclosure controls and procedures 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 as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

 

c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

 

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, 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 in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

 

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

 

6. The registrant’s other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

 

Date:  March 25, 2003

 

/s/  Richard Aitken-Davies
Richard Aitken-Davies
Chief Financial Officer

 

156

 

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-14 and 15d-14) for the registrant and have:

 

a) designed such disclosure controls and procedures 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 as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

 

c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

 

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, 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 in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

 

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

 

6. The registrant’s other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

 

Date:  March 25, 2003

 

/s/  Victor A. Staffieri
Victor A. Staffieri
Chairman of the Board, President and Chief Executive Officer

 

157

 

Kentucky Utilities Company

 

I, Richard Aitken-Davies, 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-14 and 15d-14) for the registrant and have:

 

a) designed such disclosure controls and procedures 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 as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

 

c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

 

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, 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 in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

 

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

 

6. The registrant’s other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

 

Date:  March 25, 2003

 

/s/  Richard Aitken-Davies
Richard Aitken-Davies
Chief Financial Officer

 

158