UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549

FORM 10-K/A

(Mark One)
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)

/ / TRANSITION 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, 2000
-----------------

Commission Registrant, State of Incorporation, IRS Employer
File Number Address, and Telephone Number Identification Number
----------- ----------------------------- ---------------------
2-26720 LOUISVILLE GAS AND ELECTRIC COMPANY 61-0264150
(A Kentucky Corporation)
220 West Main Street
P. O. Box 32010
Louisville, Kentucky 40232
(502) 627-2000

1-3464 KENTUCKY UTILITIES COMPANY 61-0247570
(A Kentucky and Virginia Corporation)
One Quality Street
Lexington, Kentucky 40507-1428
(859) 255-2100

Securities registered pursuant to section 12(b) of the Act:

Kentucky Utilities Company
--------------------------

Name of each exchange on
Title of each class which registered
------------------- ----------------
Preferred Stock, 4.75% cumulative, Philadelphia Stock Exchange
stated value $100 per share

Securities registered pursuant to section 12(g) of the Act:

Louisville Gas and Electric Company
-----------------------------------
5% Cumulative Preferred Stock, $25 Par Value
$5.875 Cumulative Preferred Stock, Without Par Value
Auction Rate Series A Preferred Stock, Without Par Value
(Title of class)

Kentucky Utilities Company
--------------------------
Preferred Stock, cumulative, stated value $100 per share
(Title of class)

Indicate by check mark whether the registrants (1) have filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrants were required to file such reports), and (2) have

been subject to such filing requirements for the past 90 days. Yes X No
--- ---

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. /X/

As of February 28, 2001, 860,287 shares of voting preferred stock of Louisville
Gas and Electric Company, with an aggregate market value of $22,831,500, were
outstanding and held by non-affiliates. Additionally, Louisville Gas and
Electric Company had 21,294,223 shares of common stock outstanding, all held by
LG&E Energy Corp. Kentucky Utilities had 37,817,878 shares of common stock
outstanding, all held by LG&E Energy Corp.

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

DOCUMENTS INCORPORATED BY REFERENCE

Proxy statements for Louisville Gas and Electric Company and Kentucky Utilities
Company, currently anticipated to be prepared and filed with the Commission
during April 2001, are incorporated by reference into Part III of this Form
10-K.

TABLE OF CONTENTS

PART I

Item 1. Business........................................................ 7
Louisville Gas and Electric Company
General...................................................... 7
Electric Operations.......................................... 8
Gas Operations............................................... 9
Rates and Regulation......................................... 10
Construction Program and Financing........................... 11
Coal Supply.................................................. 11
Gas Supply................................................... 12
Environmental Matters........................................ 12
Competition.................................................. 13
Kentucky Utilities Company
General...................................................... 13
Electric Operations.......................................... 13
Rates and Regulation......................................... 14
Construction Program and Financing........................... 15
Coal Supply.................................................. 16
Environmental Matters........................................ 17
Competition.................................................. 17
Employees and Labor Relations................................... 17
Item 2. Properties...................................................... 17
Item 3. Legal Proceedings............................................... 20
Item 4. Submission of Matters to a Vote of Security Holders............. 21
Executive Officers of the Companies....................................... 21

PART II

Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters.......................................... 25
Item 6. Selected Financial Data......................................... 26
Item 7. Management's Discussion and Analysis of Results of
Operations and Financial Condition:
Louisville Gas and Electric Company....................... 27
Kentucky Utilities Company................................ 38
Item 7A. Quantitative and Qualitative Disclosures About Market Risk...... 48
Item 8. Financial Statements and Supplementary Data:
Louisville Gas and Electric Company.......................... 49
Kentucky Utilities Company................................... 74
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure..................................... 95

PART III

Item 10. Directors and Executive Officers of the Registrant (a).......... 95
Item 11. Executive Compensation (a)...................................... 95
Item 12. Security Ownership of Certain Beneficial Owners
and Management (a)........................................... 95
Item 13. Certain Relationships and Related Transactions (a).............. 95

PART IV

Item 14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K...................................... 95

Signatures ............................................................... 116

(a) Incorporated by reference.

INDEX OF ABBREVIATIONS

Capital Corp. LG&E Capital Corp.
Clean Air Act The Clean Air Act, as amended in 1990
CNN Certificate of Public Convenience and Necessity
CT Combustion Turbines
DSM Demand Side Management
ECR Environmental Cost Recovery
EEI Electric Energy, Inc.
EITF Emerging Issues Task Force Issue
EPA U.S. Environmental Protection Agency
ESM Earnings Sharing Mechanism
FAC Fuel Adjustment Clause
FERC Federal Energy Regulatory Commission
FPA Federal Power Act
FT Firm Transportation
GSC Gas Supply Clause
Holding Company Act Public Utility Holding Company Act of 1935
IBEW International Brotherhood of Electrical Workers
IMEA Illinois Municipal Electric Agency
IMPA Indiana Municipal Power Agency
Kentucky Commission Kentucky Public Service Commission
KIUC Kentucky Industrial Utility Consumers, Inc.
KU Kentucky Utilities Company
KU Energy KU Energy Corporation
Kva Kilovolt-ampere
LEM LG&E Energy Marketing Inc.
LG&E Louisville Gas and Electric Company
LG&E Energy LG&E Energy Corp.
LG&E Services LG&E Energy Services Inc.
Mcf Thousand Cubic Feet
Merger Agreement Agreement and Plan of Merger dated May 20, 1997
MGP Manufactured Gas Plant
Mmbtu Million British thermal units
Moody's Moody's Investor Services, Inc.
Mw Megawatts
Mwh Megawatt hours
NAAQS National Ambient Air Quality Standards
NNS No-Notice Service
NOx Nitrogen Oxide
OMU Owensboro Municipal Utilities
PBR Performance-Based Ratemaking
Powergen Powergen plc
PUHCA Public Utility Holding Company Act of 1935
S&P Standard & Poor's Rating Services
SCR Selective Catalytic Reduction
SEC Securities And Exchange Commission
SERP Supplemental Employee Retirement Plan
SFAS Statement of Financial Accounting Standards
SIP State Implementation Plan
SO2 Sulfur Dioxide
Virginia Staff Virginia Commission Staff
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
Virginia Commission Virginia State Corporation Commission

PART I.

Item 1. Business.

On December 11, 2000, LG&E Energy Corp. and Powergen plc successfully completed
the merger transaction involving the two companies. LG&E Energy had announced on
February 28, 2000, that its Board of Directors accepted the offer to be acquired
by Powergen for cash of approximately $3.2 billion or $24.85 per share and the
assumption of $2.2 billion of LG&E Energy's debt. Pursuant to the acquisition
agreement, among other things, LG&E Energy became a wholly owned subsidiary of
Powergen and, as a result, LG&E and KU became indirect subsidiaries of Powergen.
The utility operations (LG&E and KU) of LG&E Energy have continued their
separate identities and continue to serve customers in Kentucky and Virginia
under their existing names. The preferred stock and debt securities of the
utility operations were not affected by this transaction resulting in the
utility operations' obligation to continue to file SEC reports. Following the
merger, 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 merger and in order to comply with the Public
Utility Holding Company Act of 1935, LG&E Services was formed and became
effective on January 1, 2001. LG&E Services provides certain services to
affiliated entities, including LG&E and KU, at cost as required under the
Holding Company Act. On January 1, 2001, approximately 1,000 employees, mainly
from LG&E Energy, LG&E and KU, were moved to LG&E Services.

In January 2001, LG&E Energy announced voluntary workforce separation programs
for certain employee groups. It is estimated that the separation programs may
result in a workforce reduction of approximately 700 employees at LG&E and 250
employees at KU.

LOUISVILLE GAS AND ELECTRIC COMPANY

General

Incorporated on July 2, 1913, LG&E is a regulated public utility that supplies
natural gas to approximately 299,000 customers and electricity to approximately
364,000 customers in Louisville and adjacent areas in Kentucky. LG&E's service
area covers approximately 700 square miles in 17 counties and has an estimated
population of one million. Included in this area is the Fort Knox Military
Reservation, to which LG&E transports gas and provides electric service, but
which maintains its own distribution systems. LG&E also provides gas service in
limited additional areas. LG&E's coal-fired electric generating plants, which
are all equipped with systems to reduce sulfur dioxide emissions, produce most
of LG&E's electricity. The remainder is generated by a hydroelectric power plant
and combustion turbines. Underground natural gas storage fields help LG&E
provide economical and reliable gas service to customers. See Item 2,
Properties.

For the year ended December 31, 2000, 72% of total operating revenues was
derived from electric operations and 28% from gas operations. Electric and gas
operating revenues and the percentages by classes of service on a combined basis
for this period were as follows:

(Thousands of $)
Electric Gas Combined % Combined
--------- --------- --------- ---------

Residential $ 205,105 $ 159,670 $ 364,775 47%
Commercial 171,414 61,888 233,302 30

Industrial 104,738 15,898 120,636 15
Public authorities 54,270 9,193 63,463 8
------- --------- --------- ---------
Total retail 535,527 246,649 782,176 100%
=========
Wholesale sales 165,080 17,344 182,424
Gas transported - net -- 6,922 6,922
Provision for rate refunds (2,500) -- (2,500)
Miscellaneous 12,851 1,574 14,425
--------- --------- ---------
Total $ 710,958 $ 272,489 $ 983,447
========= ========= =========

See Note 14 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, 2000.

Electric Operations

The sources of LG&E's electric operating revenues and the volumes of sales for
the three years ended December 31, 2000, were as follows:

2000 1999 1998
---- ---- ----

ELECTRIC OPERATING REVENUES
(Thousands of $):
Residential $205,105 $214,733 $213,476
Commercial 171,414 176,457 170,954
Industrial 104,738 111,889 113,372
Public authorities 54,270 55,968 55,075
-------- ---------- --------
Total retail 535,527 559,047 552,877
Wholesale sales 165,080 221,336 99,340
Provision for rate refunds (2,500) (1,735) (4,500)
Miscellaneous 12,851 12,022 10,794
-------- -------- --------
Total $710,958 $790,670 $658,511
======== ======== ========

ELECTRIC SALES (Thousands of Mwh):

Residential 3,722 3,680 3,534
Commercial 3,350 3,290 3,133
Industrial 3,043 3,047 3,097
Public authorities 1,214 1,187 1,140
------- ------- -------
Total retail 11,329 11,204 10,904
Wholesale sales 6,834 8,428 4,970
------- ------- -------
Total 18,163 19,632 15,874
====== ====== ======

LG&E uses efficient coal-fired boilers, fully equipped with sulfur dioxide
removal systems, to generate most of its electricity. LG&E's weighted-average
system wide emission rate for sulfur dioxide in 2000 was approximately 0.65
lbs./Mmbtu of heat input and, every unit was below its emission limit.

The 2000 maximum local peak load of 2,542 Mw occurred on Wednesday, August 9,
2000. The record local peak load of 2,612 Mw occurred on Friday, July 30, 1999,
when the temperature was 106 degrees F.

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

LG&E's current reserve margin is 12%. At December 31, 2000, LG&E owned steam and
combustion turbine generating facilities with a capacity of 2,637 Mw and an 80
Mw hydroelectric facility on the Ohio River. See

Item 2, Properties.

LG&E is a participating owner with 14 other electric utilities of Ohio Valley
Electric Corporation whose primary customer is the Portsmouth Area
uranium-enrichment complex of the U.S. Department of Energy at Piketon, Ohio.
LG&E has direct interconnections with 11 utility companies in the area and has
agreements with each interconnected utility for the purchase and sale of
capacity and energy. LG&E also has agreements with an increasing number of
entities throughout the United States for the purchase and/or sale of capacity
and energy and for the utilization of their bulk transmission system.

Gas Operations

The sources of LG&E's gas operating revenues and the volumes of sales for the
three years ended December 31, 2000, were as follows:

2000 1999 1998
---- ---- ----

GAS OPERATING REVENUES
(Thousands of $):
Residential $159,670 $103,655 $113,430
Commercial 61,888 38,627 40,888
Industrial 15,898 10,401 11,969
Public authorities 9,193 9,013 8,884
-------- -------- --------
Total retail 246,649 161,696 175,171
Wholesale sales 17,344 8,118 8,720
Gas transported - net 6,922 6,350 6,926
Miscellaneous 1,574 1,415 728
-------- -------- --------
Total $272,489 $177,579 $191,545
======== ======== ========

GAS SALES (Millions of cu. ft.):
Residential 24,274 21,565 20,040
Commercial 10,132 9,033 8,448
Industrial 3,089 2,781 2,860
Public authorities 1,576 2,228 1,967
-------- -------- --------
Total retail 39,071 35,607 33,315
Wholesale sales 5,115 3,881 3,880
Gas transported 14,729 14,014 13,027
-------- -------- --------
Total 58,915 53,502 50,222
======== ======== =========

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 underground natural gas storage fields that help provide economical and
reliable gas service to ultimate consumers. By using gas storage fields
strategically, LG&E can buy gas when prices are low, store it, and retrieve the
gas when demand is high. Currently, LG&E buys competitively priced gas from
several large producers under contracts of varying duration. By purchasing from
multiple suppliers and storing any excess gas, LG&E is able to secure favorably
priced gas for its customers. Without storage capacity, LG&E would be forced to
buy additional gas when customer demand increases, which is usually when the
price is highest.

A number of industrial customers purchase their natural gas requirements
directly from alternate suppliers for delivery through LG&E's distribution
system. Generally, transportation of natural gas for LG&E's customers does not
have an adverse effect on earnings because of the offsetting decrease in gas
supply expenses. Transportation rates are designed to make LG&E economically
indifferent as to whether gas is sold or merely transported.

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
2000, maximum day gas sendout was 483,000 Mcf, occurring on December 17, when
the average temperature for the day was 10 degrees F. Supply on that day
consisted of 205,000 Mcf from purchases, 227,000 Mcf delivered from underground
storage, and 51,000 Mcf transported for industrial customers. For a further
discussion, see Gas Supply under Item 1.

Rates and Regulation

Following the merger transaction involving LG&E Energy and Powergen, Powergen
became a registered holding company under PUHCA. As a result, Powergen, its
utility subsidiaries, including LG&E, and certain of its non-utility
subsidiaries are subject to extensive regulation by the SEC under PUHCA with
respect to issuances and sales of securities, acquisitions and sales of certain
utility properties, and intra-system sales of certain goods and services. In
addition, PUHCA generally limits the ability of registered holding companies to
acquire additional public utility systems and to acquire and retain businesses
unrelated to the utility operations of the holding company. Powergen believes
that it has adequate authority (including financing authority) under existing
SEC orders and regulations for it and its subsidiaries to conduct their
businesses as proposed during 2001. Powergen will seek additional authorization
when necessary.

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

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

LG&E's electric rates contain a FAC, whereby increases and decreases in the cost
of fuel for electric generation are reflected in the rates charged to all
electric customers. The Kentucky Commission requires public hearings at
six-month intervals to examine past fuel adjustments, and at two-year intervals
to review past operations of the fuel clause and transfer of the then current
fuel adjustment charge or credit to the base charges. The Kentucky Commission
also requires that electric utilities, including LG&E, file certain documents
relating to fuel procurement and the purchase of power and energy from other
utilities.

LG&E's electric rates are subject to an Earnings Sharing Mechanism. The ESM, in
place for three years beginning in 2000, sets an upper and lower point for rate
of return on equity, whereby if LG&E's rate of return for the calendar year
falls within the range of 10.5% to 12.5%, no action is necessary. If earnings
are above the upper limit, then excess earnings are shared 40% with ratepayers
and 60% with shareholders; if earnings are below the lower limit, then earnings
deficiency is recovered 40% from ratepayers and 60% from shareholders. The first
ESM filing was made on March 1, 2001, for year ended December 31, 2000. By order
of the Kentucky Commission rate changes prompted by the ESM filing go into
effect in April of each year. At December 31, 2000, LG&E recorded in its
financial statements an estimated refund to ratepayers of $2.5 million.

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

LG&E's gas rates contain a GSC, whereby increases or decreases in the cost of
gas supply are reflected in LG&E's

rates, subject to approval of the Kentucky Commission. The GSC procedure
prescribed by order of the Kentucky Commission provides for quarterly rate
adjustments to reflect the expected cost of gas supply in that quarter. In
addition, the GSC contains a mechanism whereby any over- or under-recoveries of
gas supply cost from prior quarters will be refunded to or recovered from
customers through the adjustment factor determined for subsequent quarters. In
February 2001, the Kentucky Commission ordered LG&E to make monthly GSC filings.

Integrated resource planning regulations in Kentucky require LG&E and the other
major utilities to make triennial filings with the Kentucky Commission of
various historical and forecasted information relating to forecasted load,
capacity margins and demand-side management techniques. The last integrated
resource plan was filed in 1999.

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 which 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, 2000, gross property additions amounted
to $696 million. Internally generated funds and external financings for the
five-year period were sufficient to provide for all of these gross additions.
The gross additions during this period amounted to approximately 22% of total
utility plant at December 31, 2000, and consisted of $538 million for electric
properties and $158 million for gas properties. Gross retirements during the
same period were $108 million, consisting of $79 million for electric properties
and $29 million for gas properties.

Coal Supply

Coal-fired generating units provided more than 97% of LG&E's net kilowatt-hour
generation for 2000. The remainder of 2000 net generation was made up of a
hydroelectric plant and natural gas and oil fueled combustion turbine peaking
units. Coal will be the predominant fuel used by LG&E in the foreseeable future,
with natural gas and oil being used for peaking capacity and flame stabilization
in coal-fired boilers or in emergencies. LG&E has no nuclear generating units
and has no plans to build any in the foreseeable future. LG&E has entered into
coal supply agreements with various suppliers for coal deliveries for 2001 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
425,811 tons, or a 22-day supply, on hand at December 31, 2000.

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

Coal is delivered for LG&E's Mill Creek plant by rail and barge; Trimble County
plant by barge and Cane Run plant by rail.

The historical average delivered costs of coal purchased by LG&E were as
follows:

2000 1999 1998
---- ---- ----

Per ton $20.96 $21.49 $22.38
Per Mmbtu $ .92 $ .95 $ .98
Spot purchases as % of all sources 1% 5% 24%

The delivered cost of coal is expected to remain flat during 2001 due to
contracts to buy coal already in place, although there has been a recent coal
price increase for spot purchases.

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.

During 2000, Texas Gas filed with FERC for a change in its rates as required
under the settlement in its last rate case. The requested increase, the
resolution of that case, and the timing and amounts of refunds, if any, are not
known at this time. LG&E participates in that and other proceedings, as
appropriate.

LG&E transports on the Texas Gas system under NNS and FT rates. During the
winter months, LG&E has 184,900 Mmbtu per day in NNS. LG&E's summer NNS levels
are 60,000 Mmbtu per day and its summer FT levels are 54,000 Mmbtu per day. Each
of these NNS and FT agreements with Texas Gas expire in equal portions in 2001,
2003, and 2005. LG&E also transports on the Tennessee Gas system under
Tennessee's Gas Rate FT-A. LG&E's contract levels with Tennessee Gas are 51,000
Mmbtu per day annually. The FT-A agreement with Tennessee Gas expires 2002.

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

LG&E operates five underground gas storage fields with a current working gas
capacity of 14.6 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.

The estimated maximum deliverability from storage during the early part of the
1999-2000 heating season was approximately 373,000 Mcf per day. Deliverability
decreases during the latter portion of the heating season as the storage
inventory is reduced by seasonal withdrawals.

The average cost per Mcf of natural gas purchased by LG&E was $5.08 in 2000,
$2.99 in 1999 and $3.05 in 1998. Natural gas prices in the unregulated wholesale
market increased significantly throughout 2000, particularly as the year
progressed. Natural gas prices have increased above historic levels due to
record cold temperatures, decreased exploration and production levels, and
higher demand by electric generators.

Environmental Matters

Protection of the environment is a major priority for LG&E. LG&E engages in a
variety of activities within the jurisdiction of federal, state, and local
regulatory agencies. Those 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 2000, expenditures for pollution control facilities represented $124
million or 19% of total construction expenditures. LG&E estimates that
construction expenditures for the installation of nitrogen oxide control
equipment from 2001 through 2004 will be approximately $150 million. For a
discussion of environmental matters, see Rates and Regulation for LG&E under
Item 7 and Note 12 of LG&E's Notes to Financial Statements under Item 8.

Competition

In the last several years, LG&E has taken many steps to prepare for the expected
increase in competition in its industry, including a reduction in the number of
employees; aggressive cost cutting; write-offs of previously deferred expenses;
an increase in focus on commercial, industrial and residential customers; an
increase in employee involvement and training; a major realignment and formation
of new business units, and continuous modifications of its organizational
structure. LG&E will continue to take additional steps to better position itself
for competition in the future. See Note 16 of LG&E's Notes to Financial
Statements under Item 8.

KENTUCKY UTILITIES COMPANY

General

KU was incorporated in Kentucky in 1912 and incorporated in Virginia in 1991. KU
is a regulated public utility engaged in producing, transmitting and selling
electric energy. KU provides electric service to approximately 464,000 customers
in over 600 communities and adjacent suburban and rural areas in 77 counties in
central, southeastern and western Kentucky, and to approximately 29,000
customers in 5 counties in southwestern Virginia. In Virginia, KU operates under
the name Old Dominion Power Company. KU operates under appropriate franchises in
substantially all of the 160 Kentucky incorporated municipalities served. No
franchises are required in unincorporated Kentucky or Virginia communities. The
lack of franchises is not expected to have a material adverse effect on KU's
operations. KU also sells wholesale electric energy to 12 municipalities.

Electric Operations

The sources of KU's electric operating revenues and the volumes of sales for the
three years ended December 31, 2000, were as follows:

2000 1999 1998
---- ---- ----

ELECTRIC OPERATING REVENUES
(Thousands of $):
Residential $241,783 $242,304 $238,566
Commercial 161,291 160,895 158,340
Industrial 153,017 154,460 154,475
Mine Power 27,089 28,792 31,620
Public authorities 57,979 58,500 58,740
-------- -------- --------
Total retail 641,159 644,951 641,741
Wholesale sales 198,073 286,595 179,118
Provision for rate refunds - (5,900) (21,500)
Miscellaneous 12,709 11,664 10,755
-------- -------- --------
Total $851,941 $937,310 $810,114
======== ======== ========

ELECTRIC SALES (Thousands of Mwh):
Residential 5,714 5,447 5,247
Commercial 3,954 3,760 3,644

Industrial 5,044 4,911 4,747
Mine Power 767 752 838
Public authorities 1,495 1,437 1,424
-------- -------- --------
Total retail 16,974 16,307 15,900
Wholesale sales 7,573 10,188 7,224
-------- -------- --------
Total 24,547 26,495 23,124
======== ======== ========

KU's weighted-average system wide emission rate for sulfur dioxide in 2000 was
approximately 1.3 lbs./Mmbtu of heat input and, every unit was below its
emission limit.

KU's current reserve margin is 12%. At December 31, 2000, KU owned steam and
combustion turbine generating facilities with a capacity of 3,832 Mw and a 24 Mw
hydroelectric facility. See Item 2, Properties. KU obtains power from other
utilities under bulk power purchase and interchange contracts. At December 31,
2000, KU's system capability, including purchases from others, was 4,308 Mw. On
August 9, 2000, a record local peak load was set at 3,775 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 constituted about
7% of KU's net system output during 2000. See Note 11 of KU's Notes to Financial
Statements under Item 8.

KU owns 20% of the common stock of EEI, which owns and operates a 1,000-Mw
generating station in southern Illinois. KU is entitled to take 20% of the
available capacity of the station. Purchases from EEI are made under a
contractual formula which has resulted in costs which were and are expected to
be comparable to the cost of other power purchased or generated by KU. Such
power constituted about 6% of KU's net system output in 2000. See Note 11 of
KU's Notes to Financial Statements under Item 8.

Rates and Regulation

Following the merger transaction involving LG&E Energy and Powergen, Powergen
became a registered holding company under PUHCA. As a result, Powergen, its
utility subsidiaries, including KU, and certain of its non-utility subsidiaries
are subject to extensive regulation by the SEC under PUHCA with respect to
issuances and sales of securities, acquisitions and sales of certain utility
properties, and intra-system sales of certain goods and services. In addition,
PUHCA generally limits the ability of registered holding companies to acquire
additional public utility systems and to acquire and retain businesses unrelated
to the utility operations of the holding company. Powergen believes that it has
adequate authority (including financing authority) under existing SEC orders and
regulations for it and its subsidiaries to conduct their businesses as proposed
during 2001. Powergen will seek additional authorization when necessary.

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

other respects as provided in the FPA. In addition, the FERC has sole
jurisdiction over the issuance by KU of short-term securities.

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

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

KU's Kentucky retail electric rates are subject to an Earnings Sharing
Mechanism. The ESM, in place for three years beginning in 2000, sets an upper
and lower point for rate of return on equity, whereby if KU's rate of return for
the calendar year falls within the range of 10.5% to 12.5%, no action is
necessary. If earnings are above the upper limit, then excess earnings are
shared 40% with ratepayers and 60% with shareholders; if earnings are below the
lower limit, then earnings deficiency is recovered 40% from ratepayers and 60%
from shareholders. The first ESM filing was made on March 1, 2001, for year
ended December 31, 2000. By order of the Kentucky Commission rate changes
prompted by the ESM filing go into effect in April of each year. At December 31,
2000, KU expects to fall within the range, therefore no adjustment was made to
the financial statements.

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

Integrated resource planning regulations in Kentucky require KU and the other
major utilities to make triennial filings with the Kentucky Commission of
various historical and forecasted information relating to forecasted load,
capacity margins and demand-side management techniques. The last integrated
resource plan was filed in 1999.

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 which each such
supplier has the exclusive right to render retail electric service.

KU customers in Virginia will have retail choice beginning January 2002,
pursuant to the Virginia Electric Restructuring Act. KU has filed unbundled
rates that become effective January 1, 2002, for those customers who choose an
energy provider other than KU. 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. These filings are
subject to review by the Virginia Staff. The Virginia Staff issues a Staff
Report, which includes any findings or recommendations to the Virginia
Commission relating to the individual utility's financial performance during the
historic 12-month period, including previously accepted adjustments. The Staff
Report can lead to an adjustment in rates, but will be limited to decreases
through June 2007.

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, 2000, gross property additions amounted
to $574 million. Internally generated funds and external financings for the
five-year period were sufficient to provide for all of these gross additions.
The gross additions during this period amounted to approximately 20% of total
utility plant at December 31, 2000. Gross retirements during the same period
were $88 million.

Coal Supply

Coal-fired generating units provided more than 99% of KU's net kilowatt-hour
generation for 2000. The remainder of KU's net generation for 2000 was provided
by oil and/or natural gas burning units and hydroelectric plants. The historical
average delivered cost of coal purchased and the percentage of spot coal
purchases were as follows:

2000 1999 1998
---- ---- ----

Per ton $25.63 $26.65 $26.97
Per Mmbtu $1.07 $1.11 $1.12
Spot purchases as % of all sources 51% 53% 42%

The delivered cost of coal is expected to increase during 2001. 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.

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 403,436 tons, or an 18-day supply, on
hand at December 31, 2000.

KU expects to continue purchasing most of its coal, which has a sulfur content
in the .7% - 3.5% range, from western and eastern Kentucky, West Virginia,
southwest Indiana, Wyoming and Pennsylvania for the foreseeable future.

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

KU has no long-term contracts in place for the purchase of natural gas for its
combustion turbine peaking units. KU has met its gas requirements through spot
purchases and does not anticipate encountering any significant problems
acquiring an adequate supply of fuel necessary to operate its peaking units.

Environmental Matters

Protection of the environment is a major priority for KU. KU engages in a
variety of activities within the jurisdiction of federal, state, and local
regulatory agencies. Those 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 2000, expenditures for
pollution control facilities represented $42 million or 7% of total construction
expenditures. KU estimates that construction expenditures for the installation
of nitrogen oxide control equipment from 2001 through 2004 will be approximately
$190 million. See Note 11 of KU's Notes to Financial Statements under Item 8.

Competition

KU has taken many steps to prepare for the expected increase in competition in
its industry, including a reduction in the number of employees; aggressive cost
cutting; an increase in focus on not only commercial and industrial customers,
but residential customers as well; an increase in employee involvement and
training; and continuous modifications of its organizational structure. KU will
continue to take additional steps to better position itself for competition in
the future. See Note 14 of KU's Notes to Financial Statements under Item 8.

EMPLOYEES AND LABOR RELATIONS

LG&E had 2,003 full-time employees and KU had 1,475 full-time employees at
December 31, 2000. Of the LG&E total, 1,192 operating, maintenance, and
construction employees were members of IBEW Local 2100. The current three-year
contract with the IBEW will expire in November 2001. Of the KU total, 221
operating, maintenance, and construction employees were members of IBEW Local
2100 and USWA Local 9447-01. In August 2000, KU and employees represented by
IBEW Local 2100 entered into a one-year collective bargaining agreement. At the
same time, KU and employees represented by USWA entered into a two-year
collective bargaining agreement.

See Note 16 of LG&E's Notes to Financial Statements and Note 14 of KU's Notes to
Financial Statements under Item 8 for workforce separation program in effect for
2001. These separation programs are anticipated to result in workforce
reductions of approximately 700 and 250 employees at LG&E and KU, respectively.

ITEM 2. Properties.

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

Capability
Rating (Kw)
-----------

Steam Stations:
Mill Creek - Kosmosdale, KY.
Unit 1 303,000

Unit 2 301,000
Unit 3 386,000
Unit 4 480,000
---------
Total Mill Creek 1,470,000

Cane Run - near Louisville, KY.
Unit 4 155,000
Unit 5 168,000
Unit 6 240,000
---------
Total Cane Run 563,000

Trimble County - Bedford, KY. (a)
Unit 1 371,000

Combustion Turbine Generators (Peaking capability):
Zorn 16,000
Paddy's Run 43,000
Cane Run 16,000
Waterside 33,000
E.W. Brown (b) 125,000
---------
Total combustion turbine generators 233,000
---------

Total capability rating 2,637,000
=========

(a) Amount shown represents LG&E's 75% interest in Trimble County. See
Note 13 of LG&E's Notes to Financial Statements, Jointly Owned Electric
Utility Plant, under Item 8 for further discussion on ownership.

(b) Amount shown represents LG&E's 38% interest in Unit 6 and 7 at E.W.
Brown. See Notes 12 and 13 of LG&E's Notes to Financial Statements,
under Item 8 for further discussion on ownership.

LG&E also owns an 80 Mw hydroelectric generating station located in Louisville,
operated under license issued by the FERC.

At December 31, 2000, LG&E's electric transmission system included 21
substations with a total capacity of approximately 11,519,700 Kva and
approximately 652 structure miles of lines. The electric distribution system
included 84 substations with a total capacity of approximately 3,448,730 Kva,
3,693 structure miles of overhead lines, 366 miles of underground conduit, and
5,694 miles of underground conductors.

LG&E's gas transmission system includes 212 miles of transmission mains, and the
gas distribution system includes 3,885 miles of distribution mains.

LG&E operates underground gas storage facilities with a current working gas
capacity of approximately 14.6 million Mcf. See Gas Supply under Item 1.

In 1990, LG&E entered into an operating lease for its corporate office building
located in downtown Louisville, Kentucky. The lease is for a period of 15 years
and is scheduled to expire June 2005.

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

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

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

Capability
Rating (Kw)
-----------

Steam Stations:
Tyrone - Tyrone, KY.
Unit 1 27,000
Unit 2 31,000
Unit 3 71,000
---------
Total Tyrone 129,000

Green River - South Carrollton, KY.
Unit 1 26,000
Unit 2 27,000
Unit 3 71,000
Unit 4 103,000
---------
Total Green River 227,000

E.W. Brown - Burgin, KY.
Unit 1 104,000
Unit 2 168,000
Unit 3 439,000
---------
Total E.W. Brown 711,000

Pineville - Four Mile, KY.
Unit 3 34,000

Ghent - Ghent, KY.
Unit 1 483,000
Unit 2 492,000
Unit 3 493,000
Unit 4 494,000
---------
Total Ghent 1,962,000

Combustion Turbine Generators (Peaking capability):
E.W. Brown - Burgin, KY. (Units 6-11) (a) 724,000
Haefling - Lexington, KY. 45,000
---------

Total combustion turbine generators 769,000
---------

Total capability rating 3,832,000
=========

(a) Amount shown includes the KU's 62% interest in Unit 6 and 7 at
E.W. Brown and 100% of four other units. See Notes 11 and 12 of
KU's Notes to Financial Statements, under Item 8 for further
discussion on ownership.

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

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

At December 31, 2000, KU's electric transmission system included 112 substations
with a total capacity of approximately 14,855,396 Kva and approximately 4,227
structure miles of lines. The electric distribution system included 438
substations with a total capacity of approximately 5,046,307 Kva and 14,772
structure miles of lines.

ITEM 3. Legal Proceedings.

Rates and Regulatory Matters

For a discussion of current regulatory matters, including, among others, a
discussion of (a) rate matters related to the Kentucky Commission's proceeding
involving LG&E's and KU's PBR filings and ESM filings, (b) proceedings before
the Kentucky Supreme Court and the Kentucky Commission regarding environmental
cost recovery surcharge refunds, and (c) fuel adjustment clause proceedings
before the Kentucky Commission regarding electric line loss refunds, see Rates
and Regulation under Item 7 and Notes 3 and 12 of LG&E's Notes to Financial
Statements and Notes 3 and 11 of KU's Notes to Financial Statements under Item
8.

Performance-Based Ratemaking

In October, 1998, LG&E and KU filed applications with the Kentucky Commission
for approval of the PBR proposal for determining electric rates. In January
2000, the Kentucky Commission issued orders requiring LG&E and KU to reduce
annual base rates, effective March 1, 2000. The orders also eliminated the
temporary effectiveness of the PBR proposal, reinstated the FAC mechanism and
offered the utilities a three year ESM program whereby incremental annual
earnings above or below a range of 10.5% to 12.5% would be shared 60% with
shareholders and 40% with ratepayers. In February 2000, LG&E and KU filed
tariffs incorporating the ESM. In June 2000, the Kentucky Commission issued
orders reducing the original January 2000 base rate reductions to now require
reductions in base rates of approximately $26.3 million at LG&E and $30.4
million at KU, effective June 1, 2000. The orders implemented LG&E's and KU's
ESM tariffs, with certain modifications, for a three year term. No parties filed
appeals from the Kentucky Commission's orders within the time allowed by
statute. See Rates and Regulations under Item 7 and Note 3 to LG&E's Notes to
Financial Statements and Note 3 to KU's Notes to Financial Statements under Item
8.

Fuel Adjustment Clause Proceedings

Pursuant to Kentucky statute, LG&E and KU operate under six-month and
two-year reviews by the Kentucky Commission of the fuel cost incurred to
serve their customers. Both LG&E and KU have participated in proceedings in
front of the Kentucky Commission concerning the recovery of fuel costs
associated with wholesale sales and recovery of purchased power energy costs.
As a result of these proceedings, the Kentucky Commission issued orders in
August 1999 requiring aggregate refunds totaling approximately $800,000 for
LG&E and $6.7 million for KU for the periods between November 1996 to August
2000. The issue of whether interest on these amounts is to be refunded has
been appealed to the Kentucky Court of Appeals by LG&E, KU and the intervenor
group, with a final ruling expected in late 2001 or early 2002. See also Note
3 to LG&E's Notes to Financial Statements and Note 3 to KU's Notes to
Financial Statements under Item 8. See Rates and Regulatory Matters above
regarding further matters arising during LG&E's and KU's FAC proceedings.

Environmental

For a discussion of environmental matters concerning (a) currently proposed
reductions in NOx and SO2 emission limits, (b) issues at LG&E's Mill Creek
generating plant and LG&E's and KU's manufactured gas plant sites, and (c) other
environmental items affecting LG&E and KU, see Environmental Matters under Item
7 and Note 12 of LG&E's Notes to Financial Statements and Note 11 of KU's Notes
to Financial Statements under

Item 8, respectively.

Other

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

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

None.

Executive Officers of LG&E at December 31, 2000:

Effective Date of
Election to Present
Name Age Position Position
---- --- -------- --------

Roger W. Hale 56 Chairman of the January 1, 1992
Board, and Chief
Executive
Officer

Victor A. Staffieri 46 President and June 7, 2000
Chief Operating
Officer

R. Foster Duncan* 46 Executive Vice February 16, 1999
President and
Chief Financial
Officer

John R. McCall 57 Executive Vice July 1, 1994
President, General
Counsel and
Corporate
Secretary

Frederick J. Newton III 45 Senior Vice January 2, 1999
President and
Chief Administrative
Officer

S. Bradford Rives 42 Senior Vice December 11, 2000
President - Finance
and Controller

Paul W. Thompson 43 Senior Vice June 7, 2000
President - Energy
Services

Chris Hermann 53 Senior Vice December 11, 2000
President -
Distribution
Operations

Wendy C. Welsh 46 Senior Vice December 11, 2000
President -
Information
Technology

Martyn Gallus 36 Senior Vice December 11, 2000
President - Energy
Marketing

David A. Vogel 35 Vice President - December 11, 2000
Retail Services

Daniel K. Arbough 39 Treasurer December 11, 2000

* Effective January 31, 2001, Richard Aitken-Davies was appointed Chief
Financial Officer.

The present term of office of each of the above executive officers extends to
the meeting of the Board of Directors following the Annual Meeting of
Shareholders, scheduled to be held in June 2001.

There are no family relationships between or among executive officers of LG&E
and KU.

Before he was elected to his current positions, Mr. Hale was Chairman of the
Board and Chief Executive Officer of LG&E Energy Corp. from August 1990 to the
present and Chairman of the Board and Chief Executive Officer of LG&E from
January 1992 to the present.

Before he was elected to his current positions, Mr. Staffieri was President of
LG&E from January 1994 to May 1997; President --Distribution Services of LG&E
Energy Corp. from December 1995 to May 1997; Chief Financial Officer of LG&E
Energy Corp and LG&E from May 1997 to February 1999 and Chief Financial Officer
of KU from May 1998 to February 1999.

Before he was elected to his indicated positions, Mr. Duncan was Vice President
and Corporate Treasurer of Freeport-McMoRan, Inc. and Freeport-McMoRan Copper &
Gold Inc. and their affiliates from May 1994 to January 1998; and Executive Vice
President - Planning and Development of LG&E Energy Corp. from January 1998 to
February 1999.

Before he was elected to his current positions, Mr. McCall was Executive Vice
President, General Counsel and Corporate Secretary of LG&E Energy Corp. and LG&E
from July 1994 to the present.

Before he was elected to his current positions, Mr. Newton was Director of Human
Resources, Manufacturing and Engineering at Unilever from October 1993 to July
1995; Senior Director, Human Resources, Supply Chain, at Unilever from August
1995 to July 1996; Vice President, Human Resources, at Venator Group from August
1996 to July 1997; Senior Vice President, Human Resources, at Venator Group's
Champs Sports Division from August 1997 to April 1998; and Senior Vice President
- - Human Resources and Administration of LG&E Energy Corp., LG&E and KU from May
1998 to January 1999.

Before he was elected to his current positions, Mr. Rives was Vice President and
Treasurer of LG&E Power Inc. from June 1994 to March 1995; Vice President,
Controller and Treasurer of LG&E Power Inc. from March 1995 to December 1995;
Vice President - Finance, Non-Utility Businesses of LG&E Energy Corp. from
January 1996 to March 1996; Vice President - Finance and Controller of LG&E
Energy Corp. from March 1996 to February 1999; and Senior Vice President -
Finance and Business Development from February 1999 to December 2000.

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

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

Before he was elected to his current positions, Mr. Gallus was Director, Risk
Management, then Director, Product Development, then Vice President, Trading,
then Senior Vice President, of LG&E Energy Marketing Inc., respectively,
beginning in February 1996.

Before he was elected to his current positions, Mr. Vogel served in management
positions within the Gas Department of LG&E during the five prior years to this
report.

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

Executive Officers of KU at December 31, 2000:

Effective Date of
Election to Present
Name Age Position Position
---- --- -------- --------

Roger W. Hale 56 Chairman of the Board, May 4, 1998
and Chief Executive
Officer

Victor A. Staffieri 46 President and Chief June 7, 2000
Operating Officer

R. Foster Duncan* 46 Executive Vice President February 16, 1999
and Chief Financial
Officer

John R. McCall 57 Executive Vice President, May 4, 1998
General Counsel and
Corporate Secretary

Frederick J. Newton III 45 Senior Vice President and January 2, 1999
Chief Administrative
Officer

S. Bradford Rives 42 Senior Vice President - December 11, 2000
Finance and Controller

Paul W. Thompson 43 Senior Vice President - June 7, 2000
Energy Services

Chris Hermann 53 Senior Vice President - December 11, 2000
Distribution Operations

Wendy C. Welsh 47 Senior Vice President - December 11, 2000
Information Technology

Martyn Gallus 36 Senior Vice President - December 11, 2000
Energy Marketing

Gary E. Blake 48 Vice President - Sales May 4, 1998
and Service

James J. Ellington 55 Vice President - Power May 4, 1998
Generation

David A. Vogel 35 Vice President - Retail December 11, 2000
Services

Daniel K. Arbough 39 Treasurer December 11, 2000

* Effective January 31, 2000, Richard Aitken-Davies was appointed Chief
Financial Officer.

The present term of office of each of the above executive officers extends to
the meeting of the Board of Directors following the Annual Meeting of
Shareholders, scheduled to be held in June 2001.

There are no family relationships between or among executive officers of LG&E
and KU.

Before he was elected to his current positions, Mr. McCall was Executive Vice
President, General Counsel and Corporate Secretary of LG&E Energy Corp. and LG&E
from July 1994 to the present.

1995 to December 1995; Vice President - Finance, Non-Utility Businesses of LG&E
Energy Corp. from January 1996 to March 1996; Vice President - Finance and
Controller of LG&E Energy Corp. from March 1996 to February 1999; and Senior
Vice President - Finance and Business Development from February 1999 to December
2000.

Before he was elected to his current position, Mr. Blake was Vice President -
Retail Marketing of KU from November 1992 to May 1998.

Before he was elected to his current position, Mr. Ellington was Superintendent
of KU's Ghent plant from May 1986 to May 1998.

Before he was elected to his current positions, Mr. Vogel served in management
positions within the Gas Department of LG&E during the five prior years to this
report.

PART II.

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

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

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

2000 1999
---- ----

First quarter $23,000 $22,000
Second quarter 16,500 22,000
Third quarter 16,500 22,000
Fourth quarter 17,000 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 $):

2000 1999
---- ----

First quarter $19,000 $18,000
Second quarter 25,000 18,000
Third quarter 25,000 18,000
Fourth quarter 25,500 19,000

ITEM 6. Selected Financial Data.

Years Ended December 31
(Thousands of $)
----------------
2000 1999 1998 1997 1996
---- ---- ---- ---- ----

LG&E:
Operating revenues:
Revenues $ 985,947 $ 969,984 $ 854,556 $ 845,543 $ 821,115
Provision for rate
refunds (2,500) (1,735) (4,500) -- --
----------- ----------- ----------- ----------- -----------
Total operating
revenues 983,447 968,249 850,056 845,543 821,115
=========== =========== =========== =========== ===========

Net operating income:
Before unusual items 150,361 142,263 138,207 148,186 147,263
Provision for rate
refunds (1,491) (2,172) (2,684) -- --
----------- ----------- ----------- ----------- -----------
Total net operating
income 148,870 140,091 135,523 148,186 147,263
=========== =========== =========== =========== ===========

Net income:
Before unusual items 112,064 108,442 104,381 113,273 107,941
Provision for rate
refunds (1,491) (2,172) (2,684) -- --
Merger costs -- -- (23,577) -- --
----------- ----------- ----------- ----------- -----------
Net income 110,573 106,270 78,120 113,273 107,941
=========== =========== =========== =========== ===========

Net income available
for common stock 105,363 101,769 73,552 108,688 103,373
=========== =========== =========== =========== ===========

Total assets 2,226,084 2,171,452 2,104,637 2,055,641 2,006,712
=========== =========== =========== =========== ===========

Long-term obligations
(including amounts
due within one year) $ 606,800 $ 626,800 $ 626,800 $ 646,800 $ 646,800
=========== =========== =========== =========== ===========

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

Years Ended December 31
(Thousands of $)
---------------
2000 1999 1998 1997 1996
----------- ----------- ----------- ----------- -----------

KU:
Operating revenues:
Revenues $ 851,941 $ 943,210 $ 831,614 $ 716,437 $ 711,711
Provision for rate
refund -- (5,900) (21,500) -- --
----------- ----------- ----------- ----------- -----------
Operating revenues 851,941 937,310 810,114 716,437 711,711
=========== =========== =========== =========== ===========
Net operating income:
Before unusual items 128,136 139,534 138,263 118,408 117,337
Provision for rate
refund -- (3,518) (12,875) -- --
----------- ----------- ----------- ----------- -----------
Operating income 128,136 136,016 125,388 118,408 117,337
=========== =========== =========== =========== ===========
Net income:
Before unusual items 95,524 110,076 107,303 85,713 86,163
Provision for rate refund -- (3,518) (12,875) -- --
Merger costs -- -- (21,664) -- --
----------- ----------- ----------- ----------- -----------
Net income 95,524 106,558 72,764 85,713 86,163
=========== =========== =========== =========== ===========
Net income available
for common stock 93,268 104,302 70,508 83,457 83,907
=========== =========== =========== =========== ===========
Total assets 1,739,518 1,785,090 1,761,201 1,679,880 1,673,055
=========== =========== =========== =========== ===========
Long-term obligations
(including amounts
due within one year) $ 484,830 $ 546,330 $ 546,330 $ 546,351 $ 546,373
=========== =========== =========== =========== ===========

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

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

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 2000, 1999, and 1998 and should be read in connection
with the financial statements and notes thereto.

Some of the following discussion may contain forward-looking statements that are
subject to certain risks, uncertainties and assumptions. Such forward-looking
statements are intended to be identified in this document by the words
"anticipate," "expect," "estimate," "objective," "possible," "potential" and
similar expressions. Actual results may vary materially. Factors that could
cause actual results to differ materially include: general economic conditions;
business and competitive conditions in the energy industry; changes in federal
or state legislation; unusual weather; actions by state or federal regulatory
agencies; and other factors described from time to time in LG&E's reports to the
Securities and Exchange Commission, including Exhibit No. 99.01 to this report
on Form

10-K.

MERGER

On December 11, 2000, LG&E Energy Corp. and Powergen plc successfully completed
the merger transaction involving the two companies. LG&E Energy had announced on
February 28, 2000, that its Board of Directors accepted the offer to be acquired
by Powergen for cash of approximately $3.2 billion or $24.85 per share and the
assumption of $2.2 billion of LG&E Energy's debt. Pursuant to the acquisition
agreement, LG&E Energy became a wholly owned subsidiary of Powergen and, as a
result, LG&E became an indirect subsidiary of Powergen. LG&E will continue its
separate identity and serve customers in Kentucky under its existing name. The
preferred stock and debt securities of LG&E were not affected by this
transaction and LG&E will continue to file SEC reports. Following the merger,
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.

Effective May 4, 1998, following the receipt of all required state and federal
regulatory approvals, LG&E Energy and KU Energy merged, with LG&E Energy as the
surviving corporation. The outstanding preferred stock of LG&E, a subsidiary of
LG&E Energy, was not affected by the merger. See Note 2 of LG&E's Notes to
Financial Statements under Item 8.

RESULTS OF OPERATIONS

Net Income

LG&E's net income increased $4.3 million for 2000, as compared to 1999. This
increase is mainly due to higher gas sales resulting from the colder winter
weather experienced in 2000, lower administrative costs and operating expenses
at the electric generating stations, partially offset by decreased electric
revenues due to a rate reduction ordered by the Kentucky Commission and higher
maintenance expenses.

Net income increased $28.2 million for 1999, compared to 1998, primarily due to
non-recurring charges in 1998 for merger-related expenses of $23.6 million,
after tax. Excluding these non-recurring charges, net income increased $4.6
million. This increase is mainly due to higher electric revenues, lower
administrative costs and operating expenses at the electric generating stations,
partially offset by higher maintenance expenses at the electric generating
stations.

Revenues

A comparison of operating revenues for the years 2000 and 1999, excluding the
provisions recorded for refunds in 2000 and in 1999, 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 2000 1999 2000 1999
---------------------------- --------- --------- --------- ---------

Retail sales:
Fuel and gas supply
adjustments, etc $ (9,027) $ (2,014) $ 57,156 $ (24,791)

Merger surcredit (2,331) (4,194) -- --
Performance based rate 4,114 (6,076) -- --
Demand side management/
decoupling 6 (2,985) (20) (6,462)
Environmental cost recovery
surcharge (1,308) (570) -- --
Electric rate reduction (20,727) -- -- --
Gas rate increase -- -- 4,221 --
Variation in sales volumes 5,753 22,009 23,596 17,779
--------- --------- --------- ---------
Total retail sales (23,520) 6,170 84,953 (13,474)
Wholesale sales (56,256) 121,996 9,226 (602)
Gas transportation-net -- -- 572 (575)
Other 829 1,228 159 685
--------- --------- --------- ---------
Total $ (78,947) $ 129,394 $ 94,910 $ (13,966)
========= ========= ========= =========

Electric revenues decreased in 2000 primarily due to a decrease in brokered
activity in the wholesale electric sales market and the electric rate reduction
ordered by the Kentucky Commission. In January 2000, the Kentucky Commission
ordered an electric rate reduction and the termination of LG&E's proposed
electric PBR mechanism. Gas revenues increased primarily as a result of higher
gas supply costs billed to customers through the gas supply clause coupled with
increased gas sales in 2000 due to colder weather, as heating degree days
increased 15% over 1999. Increased wholesale gas sales, and the effects of a gas
rate increase ordered by the Kentucky Commission in September 2000 also
contributed to increased gas revenues.

Electric revenues increased in 1999 primarily due to wholesale electric sales
and higher levels of retail sales volumes, partially offset by the PBR and
merger surcredit bill reductions. Wholesale sales increased in 1999 due to large
amounts of power available. Gas revenues decreased primarily as a result of
lower gas supply costs billed to customers through the gas supply clause,
partially offset by increased gas sales in 1999 due to colder weather.

Expenses

Fuel for electric generation and gas supply expenses comprises a large component
of LG&E's total operating costs. LG&E's electric rates contain an FAC and gas
rates contain a GSC, whereby increases or decreases in the cost of fuel and gas
supply are reflected in the FAC and GSC factors, subject to approval by the
Kentucky Commission. In July 1999, the Kentucky Commission implemented rates
proposed in LG&E's PBR filing resulting in the discontinuance of the FAC. In
January 2000, the Kentucky Commission rescinded the PBR rates and ordered the
reinstatement of the FAC. See Note 3 of LG&E's Notes to Financial Statements
under Item 8 for a further discussion of the PBR and the FAC.

Fuel for electric generation increased $.3 million (.2%) in 2000 because of an
increase in generation to support increased electric sales ($7.6 million),
offset partially by a lower cost of coal burned ($7.3 million). Fuel for
electric generation increased $4.4 million (2.9%) in 1999 because of an increase
in generation to support increased electric sales ($7.4 million), offset
partially by a lower cost of coal burned ($3 million). The average delivered
cost per ton of coal purchased was $20.96 in 2000, $21.49 in 1999, and $22.38 in
1998.

Power purchased decreased $72.7 million (42.9%) in 2000 primarily due to
decreased brokered sales activity in the wholesale electric market. Power
purchased increased $119.4 million (238%) in 1999 primarily due to increased
purchases to serve native load customers during the summer months and off-system
sales activity.

Gas supply expenses increased $82.2 million (71.6%) in 2000 primarily due to an
increase in cost of net gas supply ($70.4 million), and due to an increase in
the volume of gas delivered to the distribution system ($11.8

million). Gas supply expenses decreased $11.1 million (8.9%) in 1999 primarily
due to a decrease in cost of net gas supply ($17.1 million), partially offset by
an increase in the volume of gas delivered to the distribution system ($6
million). The average unit cost per Mcf of purchased gas was $5.08 in 2000,
$2.99 in 1999, and $3.05 in 1998.

Operation expenses decreased $18.7 million (12.1%) in 2000 primarily due to
lower administrative costs, $13.8 million, (due to decreases in pension expense,
$5.4 million, year 2000 expenses, $4.0 million, and decreased salaries due to
fewer employees in 2000, $2 million) and a decrease in steam production costs
primarily at the Mill Creek generating station ($5 million). Operation expenses
decreased $8.9 million (5.4%) in 1999 primarily due to decreased costs to
operate the electric generating plants ($5.7 million) and lower administrative
costs ($4.6 million).

Maintenance expenses for 2000 increased $5.6 million (9.6%) primarily due to an
increase in software maintenance agreements ($3.9 million), and maintenance of
communications equipment ($1.5 million). Maintenance expenses for 1999 increased
$5.3 million (10.1%) primarily due to increases in scheduled outages at the Mill
Creek generating station units 3 and 4, and the Cane Run generating station
units 4 and 6 ($2.4 million) and increased forced outages at Mill Creek units 1
and 4 and Cane Run unit 5 ($3.9 million).

Depreciation and amortization increased $1.1 million (1.1%) in 2000 and
increased $4 million (4.3%) in 1999 over 1998 because of additional utility
plant in service in both years.

A depreciation study was completed in late 2000 with new depreciation rates
going into effect on January 1, 2001. The new rates, as compared to rates in
effect for 2000, are expected to increase LG&E's depreciation expense by about
$.9 million in 2001.

Property and other taxes increased $2.1 million (12.1%) in 2000 primarily due to
increased payroll and property taxes.

Other income - net, increased $.8 million (18.9%) in 2000 primarily due to a
decrease in income tax expense associated with increased interest expenses.

LG&E incurred a pre-tax charge in 1998 for costs associated with the merger of
LG&E Energy and KU Energy of $32.1 million. The amount charged is in excess of
the amount permitted to be deferred as a regulatory asset by the Kentucky
Commission. The corresponding tax benefit of $8.5 million is recorded in other
income-net. See Note 2 of LG&E's Notes to Financial Statements under Item 8.

Interest charges for 2000 increased $5.3 million (13.9%) due to having
short-term borrowings for entire 2000 as compared to two months in 1999 ($7.1
million), partially offset by a decrease in interest on debt to associated
companies ($1 million) and lower interest rates on variable rate debt ($1
million). Interest charges for 1999 increased $1.6 million (4.5%) due to
short-term borrowings, partially offset by lower interest rates on variable rate
debt ($.6 million). See Note 10 of LG&E's Notes to Financial Statements under
Item 8.

LG&E's embedded cost of long-term debt was 5.40% at December 31, 2000, and 5.46%
at December 31, 1999. See Note 10 of LG&E's Notes to Financial Statements under
Item 8.

Variations in income tax expenses are largely attributable to changes in pre-tax
income as well as non-deductible merger expenses in 1998.

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.

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 $156.2 million, $180.5 million and $225.7
million in 2000, 1999, and 1998, respectively. The 2000 decrease resulted mainly
from an increase in accounts receivable, and a decrease in accrued taxes. The
1999 decrease resulted from a net decrease in non-cash income statement items
and a net decrease in net current assets, including decreases in accounts
payable and accrued taxes.

Investing Activities

LG&E's primary use of funds continues to be for capital expenditures and the
payment of dividends. Capital expenditures were $144 million, $195 million and
$138 million in 2000, 1999, and 1998, respectively. LG&E expects its capital
expenditures for 2001 and 2002 will total approximately $413 million, which
consists primarily of construction estimates associated with installation of
nitrogen oxide control equipment as described in the section titled
"Environmental Matters," purchase of two jointly owned CTs with KU and on-going
construction for the distribution systems.

Net cash used for investment activities decreased by $43.3 million in 2000 as
compared to 1999, and increased $47.2 million in 1999 compared to 1998,
primarily due to construction expenditures.

Financing Activities

Cash outflows for financing activities in 2000 were $67.7 million. Cash inflow
from financing activities in 1999 was $26.7 million and cash outflow for 1998
was $107.6 million. In 2000, total debt was paid down by $20 million to $606.8
million at December 31, 2000. LG&E received $40 million in contributed capital
from its parent company in December 2000. LG&E also refinanced $108.3 million of
its pollution control bonds in 2000.

As of December 2000, LG&E had committed credit facility aggregating $200 million
with various banks. Unused capacity under these lines were approximately $200
million after considering the commercial paper support. The credit facility will
expire in 2001 and management expects to renegotiate the credit facility at that
time.

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 its requirements through operating cash
flow, debt, preferred stock or common equity.

LG&E's debt ratings as of February 28, 2001, were:

Moody's S&P Fitch
------- --- -----

First mortgage bonds A1 A- AA-
Unsecured debt A2 BBB A+
Preferred stock a2 BBB- A
Commercial paper P-1 A-2 F-1

The Moody's and Fitch ratings are on Credit Watch with negative implications.
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.

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.

Interest Rate Sensitivity

LG&E has short-term and long-term variable rate debt obligations outstanding. At
December 31, 2000, the potential change in interest expense associated with a 1%
change in base interest rates of LG&E's unhedged debt was estimated at $1.2
million.

Interest rate swaps are used to hedge LG&E's underlying variable rate debt
obligations. These swaps hedge specific debt issuance and consistent with
management's designation are accorded hedge accounting treatment.

As of December 31, 2000, LG&E had swaps with a combined notional value of $234.3
million. The swaps exchange floating-rate interest payments for fixed interest
payments to reduce the impact of interest rate changes on LG&E's Pollution
Control Bonds. As of December 31, 2000, 66% of the outstanding variable interest
rate borrowings were converted to fixed interest rates through swaps. The
potential loss in fair value from these positions resulting from a hypothetical
1% adverse movement in base interest rates is estimated at $6.9 million as of
December 31, 2000. Changes in the market value of these swaps if held to
maturity, as LG&E intends to do, are not expected to have any effect on LG&E's
net income or cash flow. See Note 4 of LG&E's Notes to Financial Statements
under Item 8.

Commodity Price Sensitivity

LG&E has limited exposure to market price volatility in prices of fuel and
electricity, as long as cost-based regulations exist, including the FAC and GSC.

YEAR 2000 COMPUTER SOFTWARE ISSUE

Result of Year 2000 Preparation

The remediation efforts of LG&E in preparing for potential Year 2000 computer
problems were successful and

resulted in LG&E incurring no material disruptions in services or operations of
any sort. To the extent, if any, certain third parties such as interconnected
utilities, key customers or suppliers still face Year 2000 disruptions due to
incomplete remediation, LG&E may still retain risk related to Year 2000 issues.
LG&E is not presently aware of any such situations and does not anticipate such
events will have a material effect on LG&E's financial condition or results of
operations.

Cost of Year 2000 Issues

LG&E's system modification costs related to the Year 2000 issue were expensed as
incurred, while new system installations are being capitalized pursuant to
generally accepted accounting principles. See Note 1 of LG&E's Notes to
Financial Statements under Item 8. Through December 2000, LG&E incurred
approximately $18.6 million in capital and operating costs in connection with
the Year 2000 issue.

RATES AND REGULATION

LG&E is subject to the jurisdiction of the Kentucky Commission in virtually all
matters related to electric and gas utility regulation, and as such, their
accounting is subject to SFAS No. 71, ACCOUNTING FOR THE EFFECTS OF CERTAIN
TYPES OF REGULATION. Given LG&E's competitive position in the market 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.

Environmental Cost Recovery

In August 1999, a final order of the Kentucky Commission approved LG&E's
settlement agreement concerning the refund of the recovery of costs associated
with pre-1993 environmental projects. LG&E began applying the refund to
customers' bills in October 1999, and completed the refund process in the month
of November 2000. All aspects of the original litigation of this issue have now
been resolved.

In March 2000, LG&E filed an application with the Kentucky Commission to obtain
a CCN to construct up to three SCRs 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 2003.
Following a period of discovery in the proceeding, the Kentucky Commission
granted LG&E's request for a CCN in June 2000. In its order, the Kentucky
Commission ruled that LG&E's proposed plan for construction was "reasonable,
cost-effective and will not result in the wasteful duplication of facilities."
In October 2000, LG&E filed an application with the Kentucky Commission to amend
its Environmental Compliance Plan to reflect the addition of the proposed NOx
reduction technology projects and to amend its Environmental Cost Recovery
Tariff to include an overall rate of return on capital investments. Approval of
LG&E's application will allow LG&E to begin to recover the costs associated with
these new projects, subject

to Kentucky Commission oversight during normal six-month and two-year reviews.
Following the completion of hearings in March 2001, a ruling is expected by May
2001.

Electric PBR/ESM

In October 1998, LG&E filed an application with the Kentucky Commission for
approval of a new method of determining electric rates that sought to provide
financial incentives for LG&E to further reduce customers' rates. The filing was
made pursuant to the September 1997 Kentucky Commission order approving the
merger of LG&E Energy and KU Energy, wherein the Kentucky Commission directed
LG&E to indicate whether they desired to remain under traditional rate of return
regulation or commence non-traditional regulation. The proposed ratemaking
method, known as PBR, included financial incentives for LG&E to reduce fuel
costs and increase generating efficiency, and to share any resulting savings
with customers. Additionally, the PBR proposal provided for financial penalties
and rewards to assure continued high quality service and reliability.

In April 1999, LG&E filed a joint agreement with KU and the Kentucky Attorney
General to adopt the PBR plan subject to certain amendments. The Kentucky
Commission issued initial orders implementing the amended PBR plan, effective
July 1999, and subject to modification. The Kentucky Commission also
consolidated into the continuing PBR proceedings an earlier March 1999, rate
complaint by a group of industrial intervenors, KIUC, in which KIUC requested
significant reductions in electric rates. Hearings were conducted before the
Kentucky Commission on LG&E's amended PBR plan and the KIUC rate reduction
petitions in August and September 1999.

In January 2000, the Kentucky Commission issued orders for LG&E in the subject
cases, ruling that LG&E should reduce base rates by $27.2 million effective with
bills rendered beginning March 1, 2000. The Kentucky Commission eliminated
LG&E's proposal to operate under its PBR plan and reinstated the FAC mechanism
effective March 1, 2000. The Kentucky Commission offered LG&E the opportunity to
operate under an ESM for the next three years. Under this mechanism, incremental
annual earnings resulting in a rate of return on equity either above or below a
range of 10.5% to 12.5% would be shared 60% with shareholders and 40% with
ratepayers.

Later in January 2000, LG&E filed motions for correction to the January 2000
orders for computational and other errors made in the Kentucky Commission's
orders which produced overstatements in the base rate reductions to LG&E of $1.1
million. In February 2000, LG&E accepted the Kentucky Commission's proposed ESM
and filed an ESM tariff which contained detailed provisions for operation of the
ESM rates. In June 2000, the Kentucky Commission ruled that the final rate
reduction should be $26.3 million, a change of approximately $900,000 and
ordered LG&E to implement the revised rates effective with service rendered
beginning June 1, 2000. LG&E reinstated its FAC beginning with March 2000
billings.

The first ESM filing was made on March 1, 2001, for year ended December 31,
2000. By order of the Kentucky Commission rate changes prompted by the ESM
filing go into effect in April of each year. At December 31, 2000, LG&E recorded
in its financial statements an estimated refund to ratepayers of $2.5 million.

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 (decoupling), but in 1998, LG&E
and customer interest groups requested an end to the then current form of the
decoupling rate mechanism. In

September 1998, the Kentucky Commission accepted LG&E's modified tariff
discontinuing the decoupling mechanism effective as of June 1, 1998. In
September 2000, LG&E filed a plan to continue DSM programming with the Kentucky
Commission. This filing calls for the expansion of the DSM programs into the
service territory served by KU and proposes a mechanism to recover revenues from
lost sales associated with DSM programs based on program planning engineering
estimates and post-implementation evaluation.

Gas PBR

Since October 1997, LG&E has implemented an experimental performance-based
ratemaking mechanism related to gas procurement activities and off-system gas
sales only. During the three-year test period beginning October 1997, rate
adjustments related to this mechanism will be determined for each 12-month
period beginning November 1 and ending October 31. Since its implementation on
November 1, 1997, through October 31, 2000, LG&E has achieved $19.6 million in
savings. Of the total savings, LG&E has retained $8.9 million, and the remaining
portion of $10.7 million has been shared with 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 for an additional five years
as a result of the benefits provided to both LG&E and its customers during the
preceding three year experimental period. A ruling is expected by the summer of
2001.

FAC

Prior to implementation of the PBR in July 1999, and following its termination
in March 2000, LG&E employed an FAC mechanism, which under Kentucky law allowed
LG&E to recover from customers, the actual fuel costs associated with retail
electric sales. In February 1999, LG&E received orders from the Kentucky
Commission requiring a refund to retail electric customers of approximately $3.9
million resulting from reviews of the FAC from November 1994, through April
1998, of which $1.9 million was refunded in April 1999, for the period beginning
November 1994, and ending October 1996. The orders changed LG&E's method of
computing fuel costs associated with electric line losses on wholesale sales
appropriate for recovery through the FAC. Following rehearing in December 1999,
the Kentucky Commission agreed with LG&E 's position on the appropriate loss
factor to use in the FAC computation and issued an order reducing the refund
level for the 18-month period under review to approximately $800,000. LG&E
enacted the refund with billings in the month of January 2000. LG&E and KIUC
each filed separate appeals from the Kentucky Commission's February 1999 orders
with the Franklin County, Kentucky Circuit Court and in May 2000, the Court
affirmed the Kentucky Commission's orders regarding the amounts disallowed and
ordered the case remanded as to the Kentucky Commission's denial of interest,
directing the Kentucky Commission to determine whether interest should be
awarded to LG&E's ratepayers. In June 2000, LG&E appealed the Circuit Court's
decision to the Kentucky Court of Appeals. A final decision on the appeal is not
expected until late 2001 or early 2002.

Gas Rate Case

In March 2000, LG&E filed an application with the Kentucky Commission requesting
an adjustment in LG&E's gas rates. LG&E asked for a general adjustment in gas
rates for a test year for the twelve months ended December 31, 1999. The revenue
increase applied for was $26.4 million. The Kentucky Commission subsequently
suspended the effective date of the proposed new tariffs, and held hearings
during August 2000. In September 2000, the Kentucky Commission granted LG&E an
annual increase in its base gas revenues of $20.2 million effective September
28, 2000. The Kentucky Commission authorized a return on equity of 11.25%. The
Kentucky Commission approved LG&E's proposal for a weather normalization billing
adjustment mechanism that will normalize the effect of weather on revenues from
gas sales. In October 2000,

the Kentucky Attorney General requested that the Kentucky Commission grant
rehearing on a single revenue requirements issue (normalization of forfeited
discounts) on the grounds that the September order did not rule on or otherwise
discuss the issue. In November 2000, the Kentucky Commission granted the
Attorney General's request for rehearing, rejected the Attorney General's
proposed adjustment to normalize the level of forfeited discounts, and ordered
that its September 2000 order be modified to reflect its findings on the issue.

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 intends
to address two major areas in the proceedings: the tools and conditions needed
to prevent cost shifting and cross-subsidization between regulated and
non-utility operations; and whether a code of conduct should be established to
assure that non-utility segments of the holding company are not engaged in
practices that could result in unfair competition caused by cost shifting from
the non-utility affiliate to the utility. In September 1998, the Kentucky
Commission issued a draft code of conduct and cost allocation guidelines. In
January 1999, LG&E, as well as all parties to the proceeding, filed comments on
the Kentucky Commission draft proposals. In December 1999, the Kentucky
Commission issued guidelines on cost allocation and held a hearing in January
2000, on the draft code of conduct. In February 2000, the Kentucky Commission
issued a draft Code of Conduct for the purpose of further consideration in the
process to promulgate a regulation. 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. On February 14, 2001, the Kentucky Commission published notice of
their intent to promulgate new administrative regulations. In the same Bill, the
General Assembly set forth provisions to govern a utilities activities related
to the sharing of information, databases, and resources between its employees or
an affiliate involved in the marketing or the provision of nonregulated
activities and its employees or an affiliate involved in the provision of
regulated services. The legislation became law in July 2000 and LG&E has been
operating pursuant thereto since that time.

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.

units. Both rules were appealed to the U.S. Court of Appeals for the D.C.
Circuit. The D.C. Circuit subsequently upheld most provisions of the NOx SIP
Call rule, but extended the compliance date to May 2004. As the court has yet to
issue a final ruling on the Section 126 rule, all LG&E generating units remain
subject to the May 2003 compliance date under that rule. LG&E continues to
monitor the status of various appeals pending in the D.C. Circuit and U.S.
Supreme Court.

LG&E is currently implementing a plan for adding significant additional NOx
controls to its generating units. Installation of additional NOx controls will
proceed on a phased basis, with installation of controls commencing in late 2000
and continuing through the final compliance date. LG&E estimates that it will
incur total capital costs of approximately $160 million to reduce its NOx
emissions to the 0.15 lb./Mmbtu level on a company-wide basis. In addition, LG&E
will incur additional operating and maintenance costs in operating new NOx
controls. LG&E believes its costs in this regard to be comparable to those of
similarly situated utilities with like generation assets. LG&E anticipates that
such capital and operating costs are the type of costs that are eligible for
recovery from customers under its environmental surcharge mechanism and believes
that a significant portion of such costs could be recovered. However, Kentucky
Commission approval is necessary and there can be no guarantee of recovery.

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 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.

See Note 12 of LG&E's Notes to Financial Statements under Item 8 for an
additional discussion of environmental issues.

FUTURE OUTLOOK

Competition and Customer Choice

LG&E has moved aggressively over the past decade to be positioned for, and to
help promote, the energy industry's shift to customer choice and a competitive
market for energy services. Specifically, LG&E has taken many steps to prepare
for the expected increase in competition in its business, including support for
performance-based ratemaking structures, aggressive cost reduction activities;
strategic acquisitions, dispositions and growth initiatives; write-offs of
previously deferred expenses; an increase in focus on commercial and industrial
customers; an increase in employee training; and necessary corporate and
business unit realignments. LG&E continues to be active in the national debate
surrounding the restructuring of the energy industry and the move toward a
competitive, market-based environment. LG&E has urged Congress to set a specific
date for a complete transition to a competitive market, one that will quickly
and efficiently bring the benefits associated

with customer choice. LG&E has previously advocated the implementation of this
transition by January 1, 2001, and now recommends adoption of federal
legislation specifying a date certain and appropriate transition regulations
implementing deregulation.

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 and no such actions
were taken at the 2000 or 2001 legislative sessions.

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

While many states have moved forward in providing retail choice, many others
have not. Some are reconsidering their initiatives and have even delayed
implementation. Recent activities in California that have resulted in extremely
high wholesale (and in some cases, consumer) electric prices are becoming
significant factors in the deliberations by other states.

GENERAL

The following discussion and analysis by management focuses on those factors
that had a material effect on KU's financial results of operations and financial
condition during 2000, 1999, and 1998 and should be read in connection with the
financial statements and notes thereto.

Some of the following discussion may contain forward-looking statements that are
subject to certain risks, uncertainties and assumptions. Such forward-looking
statements are intended to be identified in this document by the words
"anticipate," "expect," "estimate," "objective," "possible," "potential" and
similar expressions. Actual results may vary materially. Factors that could
cause actual results to differ materially include: general economic conditions;
business and competitive conditions in the energy industry; changes in federal
or state legislation; unusual weather; actions by state or federal regulatory
agencies; and other factors described from time to time in KU's reports to the
Securities and Exchange Commission, including Exhibit No. 99.01 to this report
on Form 10-K.

MERGER

owned subsidiary of Powergen and, as a result, KU became an indirect subsidiary
of Powergen. KU will continue its separate identity and serve customers in
Kentucky and Virginia under its existing name. The preferred stock and debt
securities of KU were not affected by this transaction and KU will continue to
file SEC reports. Following the merger, Powergen became a registered holding
company under PUHCA and KU, as a subsidiary of a registered holding company,
became subject to additional regulation under PUHCA. See "Rates and Regulation"
under Item 1.

Effective May 4, 1998, following the receipt of all required state and federal
regulatory approvals, LG&E Energy and KU Energy merged, with LG&E Energy as the
surviving corporation. The outstanding preferred stock of KU, a subsidiary of KU
Energy before the merger, was not affected by the merger. See Note 2 of KU's
Notes to Financial Statements under Item 8.

RESULTS OF OPERATIONS

Net Income

KU's net income decreased $11 million for 2000, as compared to 1999, primarily
due to retail rate reductions ordered by the Kentucky Commission . The rate
reduction resulted in reduced retail revenues of $28.3 million. Excluding the
impact of the rate reduction, net income would have increased approximately $6
million. The increase was due to higher retail electric sales and lower
purchased power and operation expenses, offset by lower off-system sales and
increased depreciation and amortization.

KU's net income increased $33.8 million for 1999, as compared to 1998, primarily
due to non-recurring charges in 1998 for merger-related expenses and ECR refund
of $21.5 million and $12.9 million, after tax, respectively, offset by net rate
refunds incurred in 1999 of $3.5 million, after tax. Excluding these
non-recurring charges, net income increased $2.9 million. This increase was due
to higher retail electric and off-system sales, and lower operation and
maintenance costs, offset by higher purchased power expenses for the year.

Revenues

A comparison of operating revenues for the years 2000 and 1999, excluding the
provision for rate refunds for the ECR refund and the FAC refund previously
recovered from customers, $5.9 million in 1999 and $21.5 million in 1998, 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 2000 1999
----- ---- ----

Retail sales:
Fuel clause adjustments, etc $ 6,893 $ (1,744)
Merger surcredit (2,327) (4,123)
Environmental cost recovery surcharge (4,994) (1,977)
Performance based rate 3,439 (5,558)
Electric rate reduction (28,343) --
Variation in sales volumes 20,187 19,303
--------- ---------
Total retail sales (5,145) 5,901
Wholesale sales (88,522) 106,160
Other 2,398 (465)
--------- ---------

Total $ (91,269) $ 111,596
========= =========

The increase in wholesale sales in 1999 was primarily due to more aggressive
marketing efforts.

Provision for rate refund reflects a net charge in revenues during 1999 of $5.9
million for the refund of costs previously recovered from customers under the
fuel adjustment clause and the environmental cost recovery mechanism. Provision
for rate refund reflects a charge in revenues during 1998 of $21.5 million for
the refund of environmental costs previously recovered from customers. See Note
3 of KU's Notes to Financial Statements under Item 8.

Expenses

Fuel for electric generation comprises a large component of KU's total operating
expenses. KU's Kentucky jurisdictional electric rates were subject to a FAC
whereby increases or decreases would be reflected in the FAC factor, subject to
the approval of the Kentucky Commission. Effective July 2, 1999, the FAC was
discontinued and replaced with an amended electric PBR. In January 2000, the
Kentucky Commission rescinded KU's PBR rates and ordered the reinstatement of
the FAC. See Note 3 of KU's Notes to Financial Statements under Item 8 for a
further discussion of the PBR and the FAC. KU's wholesale and Virginia
jurisdictional electric rates contain a fuel adjustment clause whereby increases
or decreases in the cost of fuel are reflected in rates, subject to the approval
of the Virginia Commission and the FERC.

Fuel for electric generation were approximately the same in 2000 as compared to
1999. An increase in volume burned ($5.1 million) was offset by decreases in the
cost of fuel ($5.1 million). Fuel for electric generation increased $2.5 million
(1%) in 1999 because of an increase in generation ($5.1 million), partially
offset by a decrease in the cost of coal burned ($2.6 million). KU's average
delivered cost per ton of coal purchased was $25.63 in 2000, $26.65 in 1999 and
$26.97 in 1998.

Power purchased expense decreased $75.4 million in 2000 primarily due to the
decrease in wholesale sales. Power purchased increased $115.7 million in 1999
primarily to support the aforementioned wholesale sales.

Operation expenses decreased $8.4 million (7.3%) in 2000 primarily because of
decreased administrative and general expenses of $10 million offset by increased
transmission expenses ($2.1 million). The administrative and general expenses
decrease was primarily due to decreased medical expense ($3.4 million) and
pension expense ($3.9 million).

Maintenance expense increased $4.3 million (7.5%) in 2000 due to increases in
maintenance at the steam generating plants, primarily due to a scheduled turbine
outage at Ghent Unit 1. Maintenance expense decreased $6.3 million (10%) in 1999
due to decreases in maintenance at the steam generating plants and the
transmission and distribution systems.

Depreciation and amortization increased $8.3 million (9.3%) in 2000 and $3.3
million (3.8%) in 1999 because of additional utility plant in service in both
years.

A depreciation study was completed in late 2000 with new depreciation rates
going into effect on January 1, 2001. The new rates, as compared to rates in
effect for 2000, are expected to decrease KU's depreciation expense by about $6
million in 2001.

Property and other taxes increased $2.1 million in 2000 over 1999 (13.8%) due to
increases in payroll taxes ($1.4 million), property tax ($.4 million) and
Kentucky Commission fees ($.3 million).

Merger costs to achieve reflects the one-time charge during 1998 of $21.7
million (the corresponding tax benefit of $.2 million is recorded in other
income - net) for merger related expenses as discussed in Note 2 of KU's Notes
to Financial Statements under Item 8.

KU's embedded cost of long-term debt was 6.89% at December 31, 2000, and 7.00%
at December 31, 1999. See Note 10 of KU's Notes to Financial Statements under
Item 8.

Variations in income tax expense are largely attributable to changes in pre-tax
income as well as non-deductible merger expenses.

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.

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 $176.3 million, $204.2 million and $239.4
million in 2000, 1999 and 1998, respectively. The 2000 decrease resulted from a
decrease in net income caused by the aforementioned electric rate reduction
ordered by the Kentucky Commission. The decrease was further caused by a net
increase in net current assets, including increases in accounts receivable and
decreases in accounts payable, and provision for rate refunds, partially offset
by decreases in inventory. The 1999 decrease resulted from an increase in net
income and a net decrease in net current assets.

Investing Activities

KU's primary use of funds continues to be for capital expenditures and the
payment of dividends. Capital expenditures were $101 million, $181 million and
$92 million in 2000, 1999 and 1998, respectively. The higher amount in 1999
capital expenditures was primarily due to the purchase of a 62% interest in two
combustion turbines. KU expects its capital expenditures for 2001 and 2002 will
total approximately $300 million which consists primarily of construction costs
associated with installation of nitrogen oxide control equipment as described in
the section titled "Environmental Matters," purchase of two jointly owned CTs
with LG&E and on going construction for the distribution system.

Net cash used for investment activities decreased by $80.8 million in 2000
compared to 1999, and increased $89.3 million in 1999 compared to 1998,
primarily due to construction expenditures.

Financing Activities

Cash outflows from financing activities were $82.4 million, $75.2 million and
$94.0 million, in 2000, 1999 and 1998, respectively. In 2000, KU retired a $61.5
million first mortgage bond and refinanced $12.9 million of its pollution
control bonds. The long-term debt balance as of December 31, 2000, was $430.8
million. Short-term debt increased $61.2 million in 2000. KU received $15
million in contributed capital from its parent company in December 2000.

KU maintains an uncommitted line of credit which totaled $100 million at
December 31, 2000. There was no outstanding balance as of that date.

Future Capital Requirements

Future capital requirements may be affected in varying degrees by factors such
as load growth, changes in construction expenditure levels, rate actions by
regulatory agencies, new legislation, market entry of competing electric power
generators, changes in environmental regulations and other regulatory
requirements. KU anticipates funding its requirements through operating cash
flow, debt, preferred stock or common equity.

KU's debt ratings as of February 28, 2001, were:

Moody's S&P Fitch
------- --- -----

First mortgage bonds A1 A- AA-
Preferred stock a2 BBB- A
Commercial paper P-1 A-2 F-1

Market Risks

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

Interest Rate Sensitivity

KU has short-term and long-term variable rate debt obligations outstanding. At
December 31, 2000, the potential change in interest expense associated with a 1%
change in base interest rates of KU's variable rate debt is estimated at $2.2
million.

Interest rate swaps are used to hedge KU's underlying debt obligations. These
swaps hedge specific debt issuances and consistent with management's designation
are accorded hedge accounting treatment.

As of December 31, 2000, KU has swaps with a notional value of $153 million. The
swaps exchange fixed-rate interest payments for floating interest payments on
KU's Series P, R, and PCS-9 Bonds. The potential loss in

fair value from these positions resulting from a hypothetical 1% adverse
movement in base interest rates is estimated at $8.3 million as of December 31,
2000. 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, as long as cost-based regulations exist, including the FAC.

YEAR 2000 COMPUTER SOFTWARE ISSUE

Result of Year 2000 Preparation

The remediation efforts of KU in preparing for potential Year 2000 computer
problems were successful and resulted in KU incurring no material disruptions in
services or operations of any sort. To the extent, if any, certain third parties
such as interconnected utilities, key customers or suppliers still face Year
2000 disruptions due to incomplete remediation, KU may still retain risk related
to Year 2000 issues. KU is not presently aware of any such situations and does
not anticipate such events will have a material effect on KU's financial
condition or results of operations.

Cost of Year 2000 Issues

KU's system modification costs related to the Year 2000 issue were expensed as
incurred, while new system installations are being capitalized pursuant to
generally accepted accounting principles. See Note 1 of KU's Notes to Financial
Statements under Item 8. Through December 2000, KU incurred approximately $5.3
million in capital and operating costs in connection with the Year 2000 issue.

RATES AND REGULATION

Following the merger transaction involving LG&E Energy and Powergen, Powergen
became a registered holding company under PUHCA. As a result, Powergen, its
utility subsidiaries, including KU, and certain of its non-utility subsidiaries
are subject to extensive regulation by the SEC under PUHCA with respect to
issuances and sales of securities, acquisitions and sales of certain utility
properties, and intra-system sales of certain goods and services. In addition,
PUHCA generally limits the ability of registered holding companies to acquire
additional public utility systems and to acquire and retain businesses unrelated
to the utility operations of the holding company. Powergen believes that it has
adequate authority (including financing authority) under existing SEC orders and
regulations for it and its subsidiaries to conduct their businesses as proposed
during 2001. Powergen 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.

Environmental Cost Recovery

In August 1999, a final order of the Kentucky Commission approved KU's
settlement agreement concerning the refund of the recovery of costs associated
with pre-1993 environmental projects. KU began applying the refund to customers'
bills in October 1999, and completed the refund process in the month of November
2000. All aspects of the original litigation of this issue have now been
resolved.

In March 2000, KU filed an application with the Kentucky Commission to obtain a
CCN to construct up to four SCRs 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 2003.
Following a period of discovery in the proceeding, the Kentucky Commission
granted KU's request for a CCN in June 2000. 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 will allow 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. Following the completion of hearings in March
2001, a ruling is expected by May 2001.

Electric PBR/ESM

In October 1998, KU filed an application with the Kentucky Commission for
approval of a new method of determining electric rates that sought to provide
financial incentives for KU to further reduce customers' rates. The filing was
made pursuant to the September 1997 Kentucky Commission order approving the
merger of LG&E Energy and KU Energy, wherein the Kentucky Commission directed KU
to indicate whether they desired to remain under traditional rate of return
regulation or commence non-traditional regulation. The proposed ratemaking
method, known as PBR, included financial incentives for KU to reduce fuel costs
and increase generating efficiency, and to share any resulting savings with
customers. Additionally, the PBR proposal provided for financial penalties and
rewards to assure continued high quality service and reliability.

In April 1999, KU filed a joint agreement with LG&E and the Kentucky Attorney
General to adopt the PBR plan subject to certain amendments. The Kentucky
Commission issued initial orders implementing the amended PBR plan, effective
July 1999, and subject to modification. The Kentucky Commission also
consolidated into the continuing PBR proceedings an earlier March 1999, rate
complaint by a group of industrial intervenors, KIUC, in which KIUC requested
significant reductions in electric rates. Hearings were conducted before the
Kentucky Commission on KU's amended PBR plans and the KIUC rate reduction
petitions in August and September 1999.

In January 2000, the Kentucky Commission issued orders for KU in the subject
cases, ruling that KU should reduce base rates by $36.5 million effective with
bills rendered beginning March 1, 2000. The Kentucky Commission eliminated KU's
proposal to operate under its PBR plan and reinstated the FAC mechanism
effective March 1, 2000. The Kentucky Commission offered KU the opportunity to
operate under an ESM for the next three years. Under this mechanism, incremental
annual earnings for KU resulting in a rate of return on equity either above or
below a range of 10.5% to 12.5% would be shared 60% with shareholders and 40%
with ratepayers.

filing an ESM tariff, which contains the provisions operating under such
mechanism. In June 2000, the Kentucky Commission ruled that the final rate
reduction should be $30.4 million, a change of approximately $6.1 million from
the original order and ordered KU to implement the revised rates effective with
service rendered beginning June 1, 2000. KU reinstated its FAC beginning with
March 2000 billings.

The first ESM filing was made on March 1, 2001, for year ended December 31,
2000. By order of the Kentucky Commission rate changes prompted by the ESM
filing go into effect in April of each year. At December 31, 2000, KU expects to
fall within the range, therefore no adjustment was made to the financial
statements.

DSM

In September 2000, KU filed a plan with the Kentucky Commission that would
expand LG&E's current DSM programs into the service territory served by KU. The
filing includes a rate mechanism that provides for concurrent recovery of DSM
costs, provides an incentive for implementing DSM programs, and recovers
revenues from lost sales associated with the DSM program. The Kentucky
Commission has not issued an order in this case. KU expects a ruling in
mid-2001.

FAC

Prior to implementation of the PBR in July 1999, and following its termination
in March 2000, KU employed an FAC mechanism, which under Kentucky law allowed
the utilities to recover from customers the actual fuel costs associated with
retail electric sales.

In July 1999, the Kentucky Commission issued a series of orders requiring KU to
refund approximately $10.1 million resulting from reviews of the FAC from
November 1994 to October 1998. The orders changed KU's method of computing fuel
costs associated with electric line losses on off-system sales appropriate for
recovery through the FAC, and KU's method for computing system line losses for
the purpose of calculating the system sales component of the FAC charge. At KU's
request, in July 1999, the Kentucky Commission stayed the refund requirement
pending the Kentucky Commission's final determination of any rehearing request
that KU may file. In August 1999, KU filed its request for rehearing of the July
orders.

In August 1999, the Kentucky Commission issued a final order in the KU
proceedings, agreeing, in part, with KU's arguments outlined in its petition for
rehearing. While the Kentucky Commission confirmed that KU should change its
method of computing the fuel costs associated with electric line losses, it
agreed with KU that the line loss percentage should be based on KU's actual line
losses incurred in making wholesale sales rather than the percentage used in its
Open Access Transmission Tariff. The Kentucky Commission also upheld its
previous ruling concerning the computation of system line losses in the
calculation of the FAC. The net effect of the Kentucky Commission's final order
was to reduce the refund obligation to $6.7 million ($5.8 million on Kentucky
jurisdictional basis) from the original order amount of $10.1 million. In August
1999, KU recorded its estimated share of anticipated FAC refunds. KU began
implementing the refund in October and completed the refund in September 2000.
Both KU and the KIUC appealed the order to the Franklin Circuit Court. In
October 2000, the Court affirmed the Kentucky Commission's orders concerning all
issues except interest, with respect to which it held that KU will be required
to pay interest on the amount disallowed "if the Commission within its
discretion so determines", and ordered the case be remanded to the Kentucky
Commission on that issue. In November 2000, KU appealed the Circuit Court's
decision to the Kentucky Court of Appeals. A decision is not expected until late
2001 or early 2002.

Kentucky Commission Administrative Case for Affiliate Transactions

In December 1997, the Kentucky Commission opened Administrative Case No. 369 to
consider Kentucky Commission policy regarding cost allocations, affiliate
transactions and codes of conduct governing the relationship between utilities
and their non-utility operations and affiliates. The Kentucky Commission intends
to address two major areas in the proceedings: the tools and conditions needed
to prevent cost shifting and cross-subsidization between regulated and
non-utility operations; and whether a code of conduct should be established to
assure that non-utility segments of the holding company are not engaged in
practices that could result in unfair competition caused by cost shifting from
the non-utility affiliate to the utility. In September 1998, the Kentucky
Commission issued a draft code of conduct and cost allocation guidelines. In
January 1999, KU, as well as all parties to the proceeding, filed comments on
the Kentucky Commission draft proposals. In December 1999, the Kentucky
Commission issued guidelines on cost allocation and held a hearing in January
2000, on the draft code of conduct. In February 2000, the Kentucky Commission
issued its ruling in the case, including a draft Code of Conduct for the purpose
of further consideration in the process to promulgate a regulation. 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. On February 14, 2001, the
Kentucky Commission published notice of their intent to promulgate new
administrative regulations. In the same Bill, the General Assembly set forth
provisions to govern a utilities activities related to the sharing of
information, databases, and resources between its employees or an affiliate
involved in the marketing or the provision of nonregulated activities and its
employees or an affiliate involved in the provision of regulated services. The
legislation became law in July 2000 and KU has been operating pursuant thereto
since that time.

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 State
Implementation Plan or "SIP" to require reductions in NOx emissions from
coal-fired generating units to the 0.15 lb./Mmbtu level on a system-wide basis.
In related proceedings in response to petitions filed by various Northeast
states, in December 1999, EPA issued a final rule pursuant to Section 126 of the
Clean Air Act directing similar NOx reductions from a number of specifically
targeted generating units including all KU units in the eastern half of
Kentucky. Additional petitions currently pending before EPA may potentially
result in rules encompassing KU's remaining generating units. Both rules were
appealed to the U.S. Court of Appeals for the D.C. Circuit. The D.C. Circuit
subsequently upheld most provisions of the NOx SIP Call rule, but extended the
compliance date to May 2004. As the court has yet to issue a final ruling on the
Section 126 rule, all KU generating units, except for KU's Green River
generating station, remain subject to the May 2003

compliance date under that rule. As KU's Green River station is not covered by
the Section 126 rule, those facilities are subject to the May 2004 compliance
date as extended by the D.C. Circuit. KU continues to monitor the status of
various appeals pending in the D.C. Circuit and U.S. Supreme Court.

KU is currently implementing a plan for adding significant additional NOx
controls to its generating units. Installation of additional NOx controls will
proceed on a phased basis, with installation of controls commencing in late 2000
and continuing through the final compliance date. KU estimates that it will
incur total capital costs of approximately $195 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 anticipates that
such capital and operating costs are the type of costs that are eligible for
recovery from customers under its environmental surcharge mechanism and believes
that a significant portion of such costs could be recovered. However, Kentucky
Commission approval is necessary and there can be no guarantee of recovery.

KU owns or formerly owned several properties which 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 expects to incur costs of approximately
$1.5 million.

KU is monitoring the status of EPA's revised NAAQS for ozone and particulate
matter. In May 1999, the Washington D.C. Circuit remanded the final rule and
directed EPA to undertake additional rulemaking efforts. KU continues to monitor
EPA actions to challenge that ruling.

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

FUTURE OUTLOOK

Competition and Customer Choice

KU has moved aggressively over the past decade to be positioned for, and to help
promote the energy industry's shift to customer choice and a competitive market
for energy services. Specifically, KU has taken many steps to prepare for the
expected increase in competition in its business, including support for PBR
structures, aggressive cost reduction activities; strategic acquisitions,
dispositions and growth initiatives; write-offs of previously deferred expenses;
an increase in focus on commercial and industrial customers; an increase in
employee training; and necessary corporate and business unit realignments. KU
continues to be active in the national debate surrounding the restructuring of
the energy industry and the move toward a competitive, market-based environment.
KU has urged Congress to set a specific date for a complete transition to a
competitive market, one that will quickly and efficiently bring the benefits
associated with customer choice. KU has previously advocated the implementation
of this transition by January 1, 2001, and now recommends adoption

of federal legislation specifying a date certain and appropriate transition
regulations implementing deregulation.

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 and no such actions were taken at
the 2000 or 2001 legislative sessions.

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

KU's customers in Virginia will have retail choice beginning January 2002,
pursuant to the Virginia Electric Restructuring Act. The Virginia Commission is
promulgating regulations to govern the various activities required by the Act.
KU has filed unbundled rates that become effective January 1, 2002, for those
customers who choose to be provided the energy from a supplier other than KU.

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.

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

Years Ended December 31
2000 1999 1998
--------- --------- ---------

OPERATING REVENUES:
Electric .............................. $ 713,458 $ 792,405 $ 663,011
Gas ................................... 272,489 177,579 191,545
Provision for rate refunds (Note 3) ... (2,500) (1,735) (4,500)
--------- --------- ---------
Total operating revenues (Note 1) ... 983,447 968,249 850,056
--------- --------- ---------

OPERATING EXPENSES:
Fuel for electric generation .......... 159,418 159,129 154,683
Power purchased ....................... 96,894 169,573 50,176
Gas supply expenses ................... 196,912 114,745 125,894
Other operation expenses .............. 135,943 154,667 163,584
Maintenance ........................... 63,709 58,119 52,786
Depreciation and amortization ......... 98,291 97,221 93,178
Federal and state income taxes (Note 8) 64,425 57,774 56,307
Property and other taxes .............. 18,985 16,930 17,925
--------- --------- ---------
Total operating expenses ............ 834,577 828,158 714,533
--------- --------- ---------

Net operating income ..................... 148,870 140,091 135,523

Merger costs (Note 2) .................... -- -- 32,072
Other income - net (Note 9) .............. 4,921 4,141 10,991
Interest charges ......................... 43,218 37,962 36,322
--------- --------- ---------
Net income ............................... 110,573 106,270 78,120

Preferred stock dividends ................ 5,210 4,501 4,568
--------- --------- ---------
Net income available for common stock .... $ 105,363 $ 101,769 $ 73,552
========= ========= =========

Statements of Retained Earnings
(Thousands of $)

Years Ended December 31
2000 1999 1998
---- ---- ----

Balance January 1 ....................... $259,231 $247,462 $258,910
Add net income .......................... 110,573 106,270 78,120
-------- -------- --------

369,804 353,732 337,030
-------- -------- --------

Deduct: Cash dividends declared on stock:
5% cumulative preferred ............... 1,075 1,075 1,075
Auction rate cumulative preferred ..... 2,666 1,957 2,024
$5.875 cumulative preferred ........... 1,469 1,469 1,469
Common ................................ 50,000 90,000 85,000
-------- -------- --------
55,210 94,501 89,568
-------- -------- --------

Balance December 31 ..................... $314,594 $259,231 $247,462
======== ======== ========

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

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

Years Ended December 31
2000 1999 1998
---- ---- ----

Net income available for common stock .......... $ 105,363 $ 101,769 $ 73,552

Unrealized holding losses on available-for-sale
securities arising during the period ........ -- (402) (14)

Income tax (expense) benefit related to items of
other comprehensive income .................. -- 163 (18)
--------- --------- ---------
Comprehensive income ........................... $ 105,363 $ 101,530 $ 73,520
========= ========= =========

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

Louisville Gas and Electric Company
Balance Sheets
(Thousands of $)

December 31
2000 1999
---- ----

ASSETS:

Utility plant, at original cost (Note 1):
Electric ........................................ $2,459,206 $2,396,707
Gas ............................................. 389,371 365,128
Common .......................................... 148,530 141,009
---------- ----------
2,997,107 2,902,844
Less: reserve for depreciation ................. 1,296,865 1,215,032
---------- ----------
1,700,242 1,687,812
Construction work in progress ................... 189,218 162,995
---------- ----------
1,889,460 1,850,807
---------- ----------
Other property and investments - less reserve ...... 1,357 1,224

Current assets:
Cash and temporary cash investments ............. 2,495 54,761
Marketable securities (Note 6) .................. 4,056 6,936
Accounts receivable - less reserve of $1,286
in 2000 and $1,233 in 1999 .................... 170,852 113,859
Materials and supplies - at average cost:
Fuel (predominantly coal) ..................... 9,325 17,350
Gas stored underground ........................ 54,441 38,780
Other ......................................... 31,685 35,010
Prepayments and other ........................... 1,317 2,775
---------- ----------
274,171 269,471
---------- ----------

Deferred debits and other assets:
Unamortized debt expense ........................ 5,784 5,607
Regulatory assets (Note 3) ...................... 36,808 31,443
Other ........................................... 18,504 12,900
---------- ----------
61,096 49,950
---------- ----------
$2,226,084 $2,171,452
========== ==========
CAPITAL AND LIABILITIES:
Capitalization (see statements of capitalization):
Common equity ................................... $ 778,928 $ 683,376
Cumulative preferred stock ...................... 95,140 95,328
Long-term debt (Note 10) ........................ 360,600 380,600
---------- ----------
1,234,668 1,159,304
---------- ----------
Current liabilities:
Current portion of long-term debt (Note 10) ..... 246,200 246,200
Notes payable (Note 11) ......................... 114,589 120,097
Accounts payable ................................ 134,392 113,008
Provision for rate refunds ...................... 2,500 8,962
Dividends declared .............................. 1,367 24,236
Accrued taxes ................................... 8,073 23,759
Accrued interest ................................ 6,350 9,265
Other ........................................... 15,826 15,725
---------- ----------
529,297 561,252
---------- ----------

Deferred credits and other liabilities:
Accumulated deferred income taxes (Notes 1 and 8) 289,232 255,910
Investment tax credit, in process of amortization 62,979 67,253
Accumulated provision for pensions and related
benefits (Note 7) ............................... 31,257 38,431
Customers' advances for construction ............ 9,578 11,104
Regulatory liabilities (Note 3) ................. 55,152 58,726
Other ........................................... 13,921 19,472
---------- ----------
462,119 450,896
---------- ----------
Commitments and contingencies (Note 12)
$2,226,084 $2,171,452
========== ==========

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

Louisville Gas and Electric Company
Statements of Cash Flows
(Thousands of $)

Years Ended December 31
2000 1999 1998
---- ---- ----

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income .................................... $ 110,573 $ 106,270 $ 78,120
Items not requiring cash currently:
Depreciation and amortization ............... 98,291 97,221 93,178
Deferred income taxes - net ................. 31,020 (5,279) 2,747
Investment tax credit - net ................. (4,274) (4,289) (4,258)
Other ....................................... 8,481 6,924 5,534
Change in certain net current assets:
Accounts receivable ......................... (56,993) 28,721 (17,708)
Materials and supplies ...................... (4,311) (559) 423
Accounts payable ............................ 21,384 (20,665) 34,779
Provision for rate refunds .................. (6,462) (4,299) 13
Accrued taxes ............................... (15,686) (8,170) 13,206
Accrued interest ............................ (2,915) 1,227 22
Prepayments and other ....................... 1,561 (7) 976
Other ......................................... (24,431) (16,602) 18,679
--------- --------- ---------
Net cash flows from operating activities .... 156,238 180,493 225,711
--------- --------- ---------

CASH FLOWS FROM INVESTING ACTIVITIES:
Purchases of securities ....................... (708) (1,144) (17,397)
Proceeds from sales of securities ............. 4,089 11,662 18,841
Construction expenditures ..................... (144,216) (194,644) (138,345)
--------- --------- ---------
Net cash flows used for investing activities . (140,835) (184,126) (136,901)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term borrowing .......................... (5,508) 120,097 --
Issuance of pollution control bonds ........... 106,545 -- --
Retirement of first mortgage bonds and
pollution control bonds ....................... (130,627) -- (20,000)
Additional paid-in capital .................... 40,000 -- --
Payment of dividends .......................... (78,079) (93,433) (87,552)
--------- --------- ---------
Net cash flows from financing activities .... (67,669) 26,664 (107,552)
--------- --------- ---------

Change in cash and temporary cash investments .... (52,266) 23,031 (18,742)

Cash and temporary cash investments at
beginning of year ............................. 54,761 31,730 50,472
--------- --------- ---------
Cash and temporary cash investments at end of
year .......................................... $ 2,495 $ 54,761 $ 31,730
========= ========= =========
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Income taxes ................................ $ 46,562 $ 76,761 $ 40,334
Interest on borrowed money .................. 42,958 33,507 34,245

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

Louisville Gas and Electric Company
Statements of Capitalization
(Thousands of $)

December 31
2000 1999
---- ----

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 --
Unrealized loss on marketable securities, net of income
taxes ($128) in 1999 (Note 6) .............................. -- (189)
Retained earnings ............................................ 314,594 259,231
----------- -----------
778,928 683,376
----------- -----------
CUMULATIVE PREFERRED STOCK:
Redeemable on 30 days notice by LG&E

Current
Shares Redemption
Outstanding 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 ................... 250,000 103.53 25,000 25,000
Preferred stock expense ........... (1,367) (1,179)
----------- ----------
95,140 95,328
----------- ----------

LONG-TERM DEBT (Note 10):
First mortgage bonds -
Series due July 1, 2002, 7 1/2% ............................ -- 20,000
Series due August 15, 2003, 6% ............................. 42,600 42,600
Pollution control series:
P due June 15, 2015, 7.45% ............................... -- 25,000
Q due November 1, 2020, 7 5/8% ........................... -- 83,335
R due November 1, 2020, 6.55% ............................ 41,665 41,665
S due September 1, 2017, variable ........................ 31,000 31,000
T due September 1, 2017, variable ........................ 60,000 60,000
U due August 15, 2013, variable .......................... 35,200 35,200
V due August 15, 2019, 5 5/8% ............................ 102,000 102,000
W due October 15, 2020, 5.45% ............................ 26,000 26,000
X due April 15, 2023, 5.90% .............................. 40,000 40,000
Y due May 1, 2027, variable .............................. 25,000 --
Z due August 1, 2030, variable ........................... 83,335 --
----------- -----------
Total first mortgage bonds ............................ 486,800 506,800
Pollution control bonds (unsecured) -
Series due September 1, 2026, variable ..................... 22,500 22,500
Series due September 1, 2026, variable ..................... 27,500 27,500
Series due November 1, 2027, variable ...................... 35,000 35,000
Series due November 1, 2027, variable ...................... 35,000 35,000
----------- -----------
Total unsecured pollution control bonds .................. 120,000 120,000
----------- -----------
Total bonds outstanding .................................... 606,800 626,800
Less current portion of long-term debt ..................... 246,200 246,200
----------- -----------
Long-term debt ............................................. 360,600 380,600
----------- -----------
Total capitalization ....................................... $ 1,234,668 $ 1,159,304
=========== ===========

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

Louisville Gas and Electric Company
Notes to Financial Statements

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

LG&E, a subsidiary of LG&E Energy and an indirect subsidiary of Powergen, is a
regulated public utility engaged in the generation, transmission, distribution,
and sale of electric energy and the storage, distribution, and sale of natural
gas in Louisville and adjacent areas in Kentucky. LG&E Energy is an exempt
public utility holding company with wholly-owned subsidiaries including LG&E,
KU, Capital Corp., LEM, and LG&E Services. All of the LG&E's Common Stock is
held by LG&E Energy.

On December 11, 2000, LG&E Energy Corp. and Powergen plc completed the merger
involving the two companies. Powergen is a registered public utility holding
company under PUHCA. No costs associated with the Powergen merger nor any of the
effects of purchase accounting have been reflected in the financial statements
of LG&E.

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

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

DEPRECIATION. Depreciation is provided on the straight-line method over the
estimated service lives of depreciable plant. The amounts provided for 2000 were
3.6% (3.3% electric, 3.8% gas and 7.3% common); for 1999 were 3.4% (3.2%
electric, 3.2% gas, and 7.1% common); and for 1998 were 3.4% (3.2% electric,
3.4% gas, and 7.4% common) of average depreciable plant.

Pursuant to a recently completed depreciation study, LG&E will implement new
depreciation rates as of January 1, 2001. The new rates are expected to be 3.5%
(3.3% electric, 3.4% gas, and 7.3% common).

CASH AND TEMPORARY CASH INVESTMENTS. LG&E considers all highly liquid debt
instruments purchased with a maturity of three months or less to be cash
equivalents. Temporary cash investments are carried at cost, which approximates
fair value.

GAS STORED UNDERGROUND. Gas inventories of $54.4 million and $38.8 million at
December 31, 2000 and 1999, 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. LG&E also uses exchange-traded U.S. Treasury note and bond
futures to hedge its exposure to fluctuations in the value of its investments in
the preferred stocks of other companies. Gains and losses on interest-rate swaps
used to hedge interest rate risk are reflected in interest charges monthly.
Gains and losses on U.S. Treasury note and bond futures used to hedge
investments in preferred stocks are charged or credited to other income - net.
The treasury futures are now listed as assets held for sale. See Note 4,
Financial Instruments.

DEBT EXPENSE. Debt expense is amortized over the lives of the related bond
issues, consistent with regulatory

practices.

DEFERRED INCOME TAXES. Deferred income taxes have been provided for all
material book-tax temporary differences.

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

REVENUE RECOGNITION. Revenues are recorded based on service rendered to
customers through month-end. LG&E accrues an estimate for unbilled revenues from
each meter reading date to the end of the accounting period. The unbilled
revenue estimates included in accounts receivable for LG&E at December 31, 2000
and 1999, were approximately $62.8 million and $31.1 million, respectively.
Under an agreement approved by the Kentucky Commission in 1994, LG&E implemented
a demand side management program, including a "decoupling mechanism" which
allowed LG&E to recover a predetermined level of revenue on electric and gas
residential sales. In 1998, the decoupling mechanism was suspended. See Note 3,
Rates and Regulatory Matters.

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
experimental performance-based ratemaking mechanism related to gas procurement
and off-system gas sales activity in October 1997. See Note 3, Rates and
Regulatory Matters.

MANAGEMENT'S USE OF ESTIMATES. The preparation of financial statements in
conformity with generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported assets and liabilities
and disclosure of contingent items at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates. See Note 12, Commitments and
Contingencies, for a further discussion.

NEW ACCOUNTING PRONOUNCEMENTS. During 2000 and 1999, the following accounting
pronouncements were issued that affect LG&E:

SFAS No. 133, ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES,
establishes accounting and reporting standards requiring that every derivative
instrument (including certain derivative instruments embedded in other
contracts) be recorded on the balance sheet as either an asset or a liability
measured at its fair value. SFAS No. 133 requires that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. Special accounting for qualifying hedges
allows a derivative's gains and losses to offset related results on the hedged
item in the income statement, and requires that LG&E must formally document,
designate, and assess the effectiveness of transactions that receive hedge
accounting. SFAS No. 133 could increase the volatility in earnings and other
comprehensive income. SFAS No. 137, ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND
HEDGING ACTIVITIES -- DEFERRAL OF THE EFFECTIVE DATE OF SFAS NO. 133, deferred
the effective date of SFAS No. 133 until January 1, 2001. LG&E adopted SFAS No.
133 on January 1, 2001. The effect of this statement will be a charge of $3.6
million to cumulative effect of change in accounting principle (net of tax) in
other comprehensive income.

EITF No. 98-10, ACCOUNTING FOR ENERGY TRADING AND RISK MANAGEMENT ACTIVITIES was
adopted effective January 1, 1999. The pronouncement requires energy trading
contracts to be marked to market on the balance sheet, with the gains and losses
shown net in the income statement. EITF No. 98-10 more broadly defines what
represents energy trading to include economic activities related to physical
assets which were not previously marked to market by established industry
practice. Adoption of EITF No. 98-10 did not have a material impact on LG&E's
consolidated results of operations or financial position.

NOTE 2 - MERGERS AND ACQUISITIONS

On December 11, 2000, LG&E Energy Corp. and Powergen plc successfully
completed the merger transaction involving the two companies. LG&E Energy had
announced on February 28, 2000, that its Board of Directors accepted the
offer to be acquired by Powergen for cash of approximately $3.2 billion or
$24.85 per share and the assumption of $2.2 billion of LG&E Energy's debt.
Pursuant to the acquisition agreement, LG&E Energy became a wholly owned
subsidiary of Powergen and, as a result, LG&E became an indirect subsidiary
of Powergen. LG&E will continue its separate identity and serve customers in
Kentucky under its existing name. The preferred stock and debt securities of
LG&E were not affected by this transaction and LG&E will continue to file SEC
reports. Following the merger, Powergen became a registered holding company
under PUHCA, and LG&E, as a subsidiary of a registered holding company,
became subject to additional regulations under PUHCA.

LG&E Energy and KU Energy merged on May 4, 1998, with LG&E Energy as the
surviving corporation. As a result of the merger, the LG&E Energy, which is the
parent of LG&E, became the parent company of KU. The operating utility
subsidiaries (LG&E and KU) have continued to maintain their separate corporate
identities and serve customers in Kentucky and Virginia under their present
names. LG&E Energy has estimated approximately $760 million in gross non-fuel
savings over a ten-year period following the merger. Costs to achieve these
savings for LG&E of $50.2 million were recorded in the second quarter of 1998,
$18.1 million of which were initially deferred and are being amortized over a
five-year period pursuant to regulatory orders. Primary components of the merger
costs were separation benefits, relocation costs, and transaction fees, the
majority of which were paid by December 31, 1998. LG&E expensed the remaining
costs associated with the merger ($32.1 million) in the second quarter of 1998.
In regulatory filings associated with approval of the merger, LG&E committed not
to seek increases in existing base rates and proposed reductions in their retail
customers' bills in amounts based on one-half of the savings, net of the
deferred and amortized amount, over a five-year period. The preferred stock and
debt securities of LG&E were not affected by the merger.

Management has accounted for the LG&E Energy - KU Energy merger as a pooling
of interests and as a tax-free reorganization under the Internal Revenue Code.

As part of its LG&E Energy - KU Energy merger order, the Kentucky Commission
approved a surcredit whereby 50% of the net non-fuel cost savings estimated
to be achieved from the merger, less $18.1 million or 50% of the originally
estimated costs to achieve such savings, be applied to reduce customer rates
through a surcredit on customers' bills and the remaining 50% be retained by
the companies. The surcredit is allocated 53% to KU and 47% to LG&E pursuant
to Kentucky Commission order. The surcredit will be about 2% of customer
bills through mid 2003 and will amount to approximately $55 million in net
non-fuel savings to LG&E. Any fuel cost savings are passed to Kentucky
customers through the companies' fuel adjustment clauses. See Note 3 for more
information about LG&E's rates and regulatory matters.

NOTE 3 - RATES AND REGULATORY MATTERS

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

as of December 31 (in thousands of $):

2000 1999
---- ----

Unamortized loss on bonds $ 19,036 $ 16,556
Merger costs 9,073 12,702
Manufactured gas sites 2,368 2,185
One utility costs 6,331 -
-------- ---------
Total regulatory assets 36,808 31,443
-------- ---------

Deferred income taxes - net (54,593) (56,767)
Deferred net gain (559) (1,959)
---------- ---------
Total regulatory liabilities (55,152) (58,726)
--------- ---------

Regulatory liabilities - net $(18,344) $(27,283)
======== ========

PUHCA. Following the merger transaction involving LG&E Energy and Powergen,
Powergen became a registered holding company under PUHCA. As a result, Powergen,
its utility subsidiaries, including LG&E, and certain of its non-utility
subsidiaries are subject to extensive regulation by the SEC under PUHCA with
respect to issuances and sales of securities, acquisitions and sales of certain
utility properties, and intra-system sales of certain goods and services. In
addition, PUHCA generally limits the ability of registered holding companies to
acquire additional public utility systems and to acquire and retain businesses
unrelated to the utility operations of the holding company. Powergen believes
that it has adequate authority (including financing authority) under existing
SEC orders and regulations for it and its subsidiaries to conduct their
businesses as proposed during 2001. Powergen will seek additional authorization
when necessary.

ENVIRONMENTAL COST RECOVERY. In August 1999, a final order of the Kentucky
Commission approved LG&E's settlement agreement concerning the refund of the
recovery of costs associated with pre-1993 environmental projects. LG&E began
applying the refund to customers' bills in October 1999, and completed the
refund process in the month of November 2000. All aspects of the original
litigation of this issue have now been resolved.

ELECTRIC PBR/ESM. In October 1998, LG&E filed an application with the Kentucky
Commission for approval of a new method of determining electric rates that
sought to provide financial incentives for LG&E to further reduce customers'
rates. The filing was made pursuant to the September 1997 Kentucky Commission
order approving the merger of LG&E Energy and KU Energy, wherein the Kentucky
Commission directed LG&E to indicate whether they desired to remain under
traditional rate of return regulation or commence non-traditional regulation.
The proposed ratemaking method, known as PBR, included financial incentives for
LG&E to

reduce fuel costs and increase generating efficiency, and to share any resulting
savings with customers. Additionally, the PBR proposal provided for financial
penalties and rewards to assure continued high quality service and reliability.

The first ESM filing was made on March 1, 2001, for year ended December 31,
2000. By order of the Kentucky Commission rate changes prompted by the ESM
filing go into effect in April of each year. At December 31, 2000, LG&E
recorded in its financial statements an estimated refund to ratepayers of
$2.5 million.

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 (decoupling),
but in 1998, LG&E and customer interest groups requested an end to the then
current form of the decoupling rate mechanism. In September 1998, the Kentucky
Commission accepted LG&E's modified tariff discontinuing the decoupling
mechanism effective as of June 1, 1998. In September 2000, LG&E filed a plan to
continue DSM programming with the Kentucky Commission. This filing calls for the
expansion of the DSM programs into the service territory served by KU and
proposes a mechanism to recover revenues from lost sales associated with DSM
programs based on program planning engineering estimates and post-implementation
evaluation.

GAS PBR. Since October 1997, LG&E has implemented an experimental
performance-based ratemaking mechanism related to gas procurement activities and
off-system gas sales only. During the three-year test period beginning October
1997, rate adjustments related to this mechanism will be determined for each
12-month period beginning November 1 and ending October 31. Since its
implementation on November 1, 1997, through October 31, 2000, LG&E has achieved
$19.6 million in savings. Of the total savings, LG&E has retained $8.9 million,
and the remaining portion of $10.7 million has been shared with 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 for an
additional five years as a result of the benefits provided to both

LG&E and its customers during the preceding three year experimental period. A
ruling is expected by the summer of 2001.

FAC. Prior to implementation of the PBR in July 1999, and following its
termination in March 2000, LG&E employed an FAC mechanism, which under Kentucky
law allowed LG&E to recover from customers, the actual fuel costs associated
with retail electric sales. In February 1999, LG&E received orders from the
Kentucky Commission requiring a refund to retail electric customers of
approximately $3.9 million resulting from reviews of the FAC from November 1994,
through April 1998, of which $1.9 million was refunded in April 1999, for the
period beginning November 1994, and ending October 1996. The orders changed
LG&E's method of computing fuel costs associated with electric line losses on
wholesale sales appropriate for recovery through the FAC. Following rehearing in
December 1999, the Kentucky Commission agreed with LG&E 's position on the
appropriate loss factor to use in the FAC computation and issued an order
reducing the refund level for the 18-month period under review to approximately
$800,000. LG&E enacted the refund with billings in the month of January 2000.
LG&E and KIUC each filed separate appeals from the Kentucky Commission's
February 1999 orders with the Franklin County, Kentucky Circuit Court and in May
2000, the Court affirmed the Kentucky Commission's orders regarding the amounts
disallowed and ordered the case remanded as to the Kentucky Commission's denial
of interest, directing the Kentucky Commission to determine whether interest
should be awarded to LG&E's ratepayers. In June 2000, LG&E appealed the Circuit
Court's decision to the Kentucky Court of Appeals. A final decision on the
appeal is not expected until late 2001 or early 2002.

GAS RATE CASE. In March 2000, LG&E filed an application with the Kentucky
Commission requesting an adjustment in LG&E's gas rates. LG&E asked for a
general adjustment in gas rates for a test year for the twelve months ended
December 31, 1999. The revenue increase applied for was $26.4 million. The
Kentucky Commission subsequently suspended the effective date of the proposed
new tariffs, and held hearings during August 2000. In September 2000, the
Kentucky Commission granted LG&E an annual increase in its base gas revenues of
$20.2 million effective September 28, 2000. The Kentucky Commission authorized a
return on equity of 11.25%. The Kentucky Commission approved LG&E's proposal for
a weather normalization billing adjustment mechanism that will normalize the
effect of weather on revenues from gas sales. In October 2000, the Kentucky
Attorney General requested that the Kentucky Commission grant rehearing on a
single revenue requirements issue (normalization of forfeited discounts) on the
grounds that the September order did not rule on or otherwise discuss the issue.
In November 2000, the Kentucky Commission granted the Attorney General's request
for rehearing, rejected the Attorney General's proposed adjustment to normalize
the level of forfeited discounts, and ordered that its September 2000 order be
modified to reflect its findings on the issue.

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 intends to
address two major areas in the proceedings: the tools and conditions needed to
prevent cost shifting and cross-subsidization between regulated and non-utility
operations; and whether a code of conduct should be established to assure that
non-utility segments of the holding company are not engaged in practices that
could result in unfair competition caused by cost shifting from the non-utility
affiliate to the utility. In September 1998, the Kentucky Commission issued a
draft code of conduct and cost allocation guidelines. In January 1999, LG&E, as
well as all parties to the proceeding, filed comments on the Kentucky Commission
draft proposals. In December 1999, the Kentucky Commission issued guidelines on
cost allocation and held a hearing in January 2000, on the draft code of
conduct. In February 2000, the Kentucky Commission issued including a draft Code
of Conduct for the purpose of further consideration in the process to promulgate
a regulation. 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. On
February 14, 2001, the Kentucky Commission published notice

of their intent to promulgate new administrative regulations. In the same Bill,
the General Assembly set forth provisions to govern a utilities activities
related to the sharing of information, databases, and resources between its
employees or an affiliate involved in the marketing or the provision of
nonregulated activities and its employees or an affiliate involved in the
provision of regulated services. The legislation became law in July 2000 and
LG&E has been operating pursuant thereto since that time.

NOTE 4 - FINANCIAL INSTRUMENTS

The cost and estimated fair values of LG&E's non-trading financial instruments
as of December 31, 2000 and 1999 follow (in thousands of $):

2000 1999
---- ----
Fair Fair
Cost Value Cost Value
---- ----- ---- -----

Marketable securities $ 4,403 $ 4,056 $ 7,253 $ 6,936
Long-term investments -
Not practicable to estimate
fair value 564 564 746 746
Preferred stock subject
to mandatory redemption 25,000 25,275 25,000 24,861
Long-term debt (including
current portion) 606,800 606,236 626,800 623,498
U.S. Treasury note and
bond futures -- -- -- 81
Interest-rate swaps -- (5,998) -- 1,666

All of the above valuations reflect prices quoted by exchanges except for the
swaps and the long-term investments. The fair values of the swaps reflect price
quotes from dealers or amounts calculated using accepted pricing models. The
fair values of the long-term investments reflect cost, since LG&E cannot
reasonably estimate fair value.

INTEREST RATE SWAPS. LG&E enters into interest rate swap agreements to exchange
variable interest rate payment obligations without the exchange of underlying
principal amounts. As of December 31, 2000, and 1999, LG&E was party to various
interest rate swaps with aggregate notional amounts of $234.3 million in each
year. Under swap agreements LG&E paid fixed rates averaging 4.40% and 3.80% and
received variable rates averaging 4.84% and 5.46% at December 31, 2000, and
1999, respectively. The swaps mature on dates ranging from 2001 to 2020.

At December 31, 2000, LG&E held U.S. Treasury note and bond futures contracts
with notional amounts totaling $6.1 million. These contracts are used to hedge
price risk associated with certain marketable securities and mature in March
2001.

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 299,000 customers and electricity to
approximately 364,000 customers in Louisville and adjacent areas in

Kentucky. For the year ended December 31, 2000, 72% of total revenue was derived
from electric operations and 28% from gas operations.

In December 1998, LG&E and IBEW Local 2100 employees, which represent
approximately 60% of LG&E's workforce, entered into a three-year collective
bargaining agreement.

NOTE 6 - MARKETABLE SECURITIES

In 2000, LG&E classified marketable securities as "trading securities" under the
provisions of SFAS No. 115, ACCOUNTING FOR CERTAIN INVESTMENTS IN DEBT AND
EQUITY SECURITIES. Prior to that, LG&E's marketable securities had been
determined to be "available-for-sale." All unrealized holding gains and losses
were immediately recognized in earnings on the date of transfer. Proceeds from
sales of trading securities in 2000 were approximately $4.1 million. Proceeds
from sales of available-for-sale securities in 1999 were approximately $11.7
million. The sales for both years resulted in immaterial net realized gains and
losses, calculated using the specific identification method.

Approximate cost, fair value, and other required information pertaining to
LG&E's securities by major security type, as of December 31, 2000 and 1999,
follow (in thousands of $):

Fixed
Equity Income Total
------ ------ -----

2000:

Cost $ 4,403 $ -- $ 4,403
Realized losses (347) -- (347)
------- ------- -------
Fair values $ 4,056 $ -- $ 4,056
======= ======= =======
Fair values:
No maturity $ 4,056 $ -- $ 4,056
------- ------- -------
Total fair values $ 4,056 $ -- $ 4,056
======= ======= =======

1999:

Cost $ 4,385 $ 2,868 $ 7,253
Unrealized gains 90 3 93
Unrealized losses (304) (106) (410)
------- ------- -------
Fair values $ 4,171 $ 2,765 $ 6,936
======= ======= =======

Fair values:
No maturity $ 4,171 $ -- $ 4,171
Contractual maturities:
Less than one year -- 2,134 2,134
One to five years -- 631 631
------- ------- -------
Total fair values $ 4,171 $ 2,765 $ 6,936
======= ======= =======

NOTE 7 - PENSION PLANS AND RETIREMENT BENEFITS

PENSION PLANS. LG&E sponsors several qualified and non-qualified pension plans
and other postretirement benefit plans for its employees. The following tables
provide a reconciliation of the changes in the plans' benefit obligations and
fair value of assets over the three-year period ending December 31, 2000, and a
statement of the funded status as of December 31 for each of the last three
years (in thousands of $):

2000 1999 1998
---- ---- ----

PENSION PLANS:
Change in benefit obligation
Benefit obligation at beginning of year $ 283,267 $ 311,935 $ 274,095
Service cost 3,408 5,005 6,333
Interest cost 22,698 21,014 19,873
Plan amendments 17,042 (2,397) 3,724
Curtailment (gain) or loss -- -- (2,218)
Special termination benefits -- -- 18,295
Benefits paid (16,656) (15,471) (10,866)
Actuarial (gain) or loss and other 1,063 (36,819) 2,699
--------- --------- ---------
Benefit obligation at end of year $ 310,822 $ 283,267 $ 311,935
========= ========= =========

Change in plan assets
Fair value of plan assets at
beginning of year $ 360,095 $ 308,660 $ 280,238
Actual return on plan assets (6,150) 51,995 38,913
Employer contributions and plan
transfers (1,804) 16,142 375
Benefits paid (16,656) (15,471) (10,866)
Administrative expenses (2,107) (1,231) --
--------- --------- ---------
Fair value of plan assets at end of
year $ 333,378 $ 360,095 $ 308,660
========= ========= =========

Reconciliation of funded status
Funded status $ 22,556 $ 76,828 $ (3,275)
Unrecognized actuarial (gain) or
loss (74,086) (126,554) (72,037)
Unrecognized transition (asset) or
obligation (5,853) (6,965) (8,076)
Unrecognized prior service cost 47,984 35,588 41,447
--------- --------- ---------
Net amount recognized at end of year $ (9,399) $ (21,103) $ (41,941)
========= ========= =========

OTHER BENEFITS:
Change in benefit obligation
Benefit obligation at beginning of
year $ 44,997 $ 44,964 $ 43,373
Service cost 822 1,205 761
Interest cost 4,225 3,270 2,946
Plan amendments 5,826 2,377 599
Curtailment (gain) or loss -- -- 344
Special termination benefits -- -- 2,855
Benefits paid (4,889) (3,050) (2,634)
Actuarial (gain) or loss 6,000 (3,769) (3,280)
--------- --------- ---------
Benefit obligation at end of year $ 56,981 $ 44,997 $ 44,964
========= ========= =========

Change in plan assets
Fair value of plan assets at
beginning of year $ 10,526 $ 6,062 $ 4,384
Actual return on plan assets (92) 1,776 199
Employer contributions 1,621 4,681 3,207
Benefits paid (4,889) (1,993) (1,728)
--------- --------- ---------
Fair value of plan assets at end
of year $ 7,166 $ 10,526 $ 6,062
========= ========= =========

Reconciliation of funded status
Funded status $ (49,815) $ (34,471) $ (38,902)
Unrecognized actuarial (gain) or loss 5,623 (1,638) (285)
Unrecognized transition (asset) or
obligation 13,374 14,489 18,080
Unrecognized prior service cost 8,960 4,292 3,519
--------- --------- ---------
Net amount recognized at end of year $ (21,858) $ (17,328) $ (17,588)
========= ========= =========

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

The following tables provide the amounts recognized in the balance sheet and
information for plans with benefit obligations in excess of plan assets as of
December 31, 2000, 1999 and 1998 (in thousands of $):

2000 1999 1998
---- ---- ----

PENSION PLANS:
Amounts recognized in the balance sheet
consisted of:
Prepaid benefits cost $ 18,880 $ 6,466 $ --
Accrued benefit liability (28,279) (27,569) (41,977)
Intangible asset -- -- 36
--------- --------- ---------
Net amount recognized at year-end $ (9,399) $ (21,103) $ (41,941)
========= ========= =========

Additional year-end information for plans with
accumulated benefit obligations in excess of
plan assets (1):
Projected benefit obligation $ 4,088 $ 4,845 $ 148,005
Accumulated benefit obligation 3,501 4,327 131,430
Fair value of plan assets -- -- 107,988

(1) 1998 includes non-union plan and SERPs. 2000 and 1999 include SERPs only.

OTHER BENEFITS:
Amounts recognized in the balance sheet
consisted of:
Accrued benefit liability $(21,858) $(17,328) $(17,588)
======== ======== ========

Additional year-end information for plans with
benefit obligations in excess of plan assets:
Projected benefit obligation $ 56,981 $ 44,997 $ 44,964
Fair value of plan assets 7,166 10,526 6,062

The following table provides the components of net periodic benefit cost for the
plans for 2000, 1999 and 1998 (in thousands of $):

2000 1999 1998
---- ---- ----

PENSION PLANS:
Components of net periodic benefit cost
Service cost $ 3,408 $ 5,005 $ 6,333
Interest cost 22,698 21,014 19,873
Expected return on plan assets (33,025) (28,946) (23,701)
Amortization of prior service cost 4,646 3,462 3,882
Amortization of transition (asset) or
obligation (1,112) (1,112) (1,112)
Recognized actuarial (gain) or loss (6,856) (2,621) (2,248)
-------- -------- --------
Net periodic benefit cost $(10,241) $ (3,198) $ 3,027
======== ======== ========
Special charges
Curtailment gain $ -- $ -- $ (2,168)
Prior service cost recognized -- -- 1,914
Special termination benefits -- -- 18,295
-------- -------- --------
Total charges $ -- $ -- $ 18,041
======== ======== ========

OTHER BENEFITS:

Components of net periodic benefit cost
Service cost $ 822 $ 1,205 $ 761
Interest cost 4,225 3,270 2,946
Expected return on plan assets (683) (401) (296)
Amortization of prior service cost 1,158 473 367
Amortization of transition (asset) or obligation 1,114 1,114 1,315
Recognized actuarial gain (485) (183) -
-------- -------- --------
Net periodic benefit cost $ 6,151 $ 5,478 $ 5,093
======== ======== ========
Special charges
Curtailment loss $ - $ - $ 1,005
Prior service cost recognized - - 124
Special termination benefits - - 2,855
--------- -------- --------
Total charges $ - $ - $ 3,984
========= ======== ========

On May 4, 1998, LG&E Energy and KU Energy merged, with LG&E Energy as the
surviving corporation. During 1998, LG&E invested approximately $18 million in
special termination benefits as a result of its early retirement program offered
to eligible employees post-merger.

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

2000 1999 1998
---- ---- ----

Weighted-average assumptions as of December 31:
Discount rate 7.75% 8.00% 7.00%
Expected long-term rate of return on plan assets 9.50% 9.50% 8.50%
Rate of compensation increase 4.75% 5.00% 3.50%-4.00%

For measurement purposes, a 7.00% annual increase in the per capita cost of
covered health care benefits was assumed for 2000. The rate was assumed to
decrease gradually to 5.00% for 2005 and remain at that level thereafter.

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

1% Decrease 1% Increase
----------- -----------

Effect on total of service and interest cost components for 2000 $ (246) $ 279
Effect on year-end 2000 postretirement benefit obligations (1,781) 2,009

THRIFT SAVINGS PLANS. LG&E has a thrift savings plan under section 401(k) of the
Internal Revenue Code. Under the plan, eligible employees may defer and
contribute to the plan a portion of current compensation in order to provide
future retirement benefits. LG&E makes contributions to the plan by matching a
portion of the employee contributions. The costs were approximately $2.7
million, $2.7 million, and $2.4 million for 2000, 1999, and 1998, respectively.

NOTE 8 - INCOME TAXES

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

2000 1999 1998
---- ---- ----

Included in operating expenses:
Current - federal $32,612 $53,981 $45,716
- state 5,018 13,680 11,895
Deferred - federal - net 24,272 (4,818) 2,276
- state - net 6,797 (780) 678
Deferred investment tax credit - - 55
Amortization of investment tax credit (4,274) (4,289) (4,313)
-------- --------- --------
Total 64,425 57,774 56,307
-------- -------- --------

Included in other income - net:

Current - federal (2,187) 217 660
- federal - merger costs - - (6,758)
- state (568) (30) 6
- state - merger costs - - (1,737)
Deferred - federal - net (39) 254 (165)
- state - net (10) 65 (42)
-------- -------- --------
Total (2,804) 506 (8,036)
-------- -------- --------

Total income tax expense $61,621 $58,280 $48,271
======= ======= =======

Net deferred tax liabilities resulting from book-tax temporary differences
are shown below (in thousands of $):

2000 1999
---- ----

Deferred tax liabilities:
Depreciation and other
plant-related items $329,836 $321,889
Other liabilities 22,621 5,324
---------- ----------
352,457 327,213
---------- ----------
Deferred tax assets:
Investment tax credit 25,444 27,145
Income taxes due to customers 22,086 22,588
Pension overfunding 5,595 2,193
Accrued liabilities not currently
deductible and other 10,100 19,377
---------- ----------
63,225 71,303
---------- ----------
Net deferred income tax liability $289,232 $255,910
======== ========

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

2000 1999 1998
---- ---- ----

Statutory federal income tax rate 35.0% 35.0% 35.0%
State income taxes, net of federal benefit 4.3 5.1 5.5
Amortization of investment tax credit (2.6) (2.8) (3.4)
Nondeductible merger expenses - - 2.4
Other differences - net (.9) (1.9) (1.3)
----- ----- -----
Effective income tax rate 35.8% 35.4% 38.2%
==== ==== ====

NOTE 9 - OTHER INCOME - NET

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

2000 1999 1998
---- ---- ----

Interest and dividend income $3,103 $ 4,086 $ 4,245
Gains on fixed asset disposals 1,014 2,394 530
Income taxes and other 804 (2,339) (2,279)
Income tax benefit on merger costs - - 8,495
-------- ------- -------

Other income - net $4,921 $ 4,141 $10,991
====== ======= =======

NOTE 10 - FIRST MORTGAGE BONDS AND POLLUTION CONTROL BONDS

Long-term debt and the current portion of long-term debt, summarized below (in
thousands of $), consists primarily of first mortgage bonds and pollution
control bonds. Interest rates and maturities in the table below are for the
amounts outstanding at December 31, 2000.

Weighted
Average
Stated Interest Principal
Interest Rates Rate Maturities Amounts
-------------- ---- ---------- -------

Noncurrent portion Variable - 6.55% 5.49% 2003 - 2030 $360,600
Current portion (pollution
control bonds) Variable 4.74% 2013 - 2027 246,200

Under the provisions for LG&E's variable-rate pollution control bonds, the bonds
are subject to tender for purchase at the option of the holder and to mandatory
tender for purchase upon the occurrence of certain events, causing the bonds to
be classified as current portion of long-term debt. The average annualized
interest rate for these bonds during 2000 was 4.74%.

LG&E's First Mortgage Bonds, 6% Series of $42.6 million is scheduled to mature
in 2003. There are no scheduled maturities of Pollution Control Bonds for the
five years subsequent to December 31, 2000.

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

In May 2000, LG&E issued $25 million variable rate pollution control bonds due
May 1, 2027 and exercised its call option on $25 million, 7.45%, pollution
control bonds due June 15, 2015. In August 2000, LG&E issued $83 million in
variable rate pollution control bonds due August 1, 2030 and exercised its call
option on its $83 million, 7 5/8%, pollution control bonds due November 1, 2020.

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

Substantially all of LG&E's utility plants are pledged as security for its first
mortgage bonds. LG&E's indenture, as supplemented, provides that portions of
retained earnings will not be available for the payment of

dividends on common stock, under certain specified conditions. No portion of
retained earnings is presently restricted by this provision.

NOTE 11 - NOTES PAYABLE

LG&E had no outstanding commercial paper at December 31, 2000. LG&E had
outstanding commercial paper totaling $120.1 million at an average rate of 6.02%
at December 31, 1999.

At December 31, 2000, LG&E had $114.6 million in notes payable to LG&E Energy
Corp. The note payable is due on demand and has an average percentage rate at
December 31, 2000 of 6.84%. The rate is based on the available borrowing rate as
of the last day of the prior month.

At December 31, 2000, LG&E had unused lines of credit of $200 million, for which
it pays commitment fees. The credit facility provides support of commercial
paper borrowings. The credit lines are scheduled to expire in 2001. Management
expects to renegotiate these lines when they expire.

NOTE 12 - COMMITMENTS AND CONTINGENCIES

CONSTRUCTION PROGRAM. LG&E had commitments in connection with its construction
program aggregating approximately $12.6 million at December 31, 2000.
Construction expenditures for the years 2001 and 2002 are estimated to total
approximately $413 million. Included in 2001 is $57 million for the purchase of
53% of two CTs currently under construction. One of the CTs is being built at
LG&E's Paddy Run location and the other at KU's E.W. Brown location. KU will own
47% of the two CTs. LG&E has received approval from the Kentucky Commission for
the purchase of the CTs.

OPERATING LEASE. LG&E leases office space and accounts for all of its office
space leases as operating leases. Total lease expense for 2000, 1999, and 1998,
less amounts contributed by the parent company, was $.9 million, $1.5 million,
and $1.6 million, respectively. The future minimum annual lease payments under
lease agreements for years subsequent to December 31, 2000, are as follows (in
thousands of $):

2001 $ 3,654
2002 3,594
2003 3,507
2004 3,507
2005 1,754
--------
Total $16,016
=======

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.
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 State
Implementation Plan or "SIP" to require reductions in NOx emissions from
coal-fired generating units to the 0.15 lb./Mmbtu level on a system-wide basis.
In related proceedings in response to petitions filed by various Northeast
states, in December 1999, EPA issued a final rule pursuant to Section 126 of the
Clean Air Act directing similar NOx reductions from a number of specifically
targeted generating units including all LG&E units. Both rules were appealed to
the U.S. Court of Appeals for the D.C. Circuit. The D.C. Circuit subsequently
upheld most provisions of the NOx SIP Call rule, but extended the compliance
date to May 2004. As the court has yet to issue a final ruling on the Section
126 rule, all LG&E generating units remain subject to the May 2003 compliance
date under that rule. LG&E continues to monitor the status of various appeals
pending in the D.C. Circuit and U.S. Supreme Court.

NOTE 13 - JOINTLY OWNED ELECTRIC UTILITY PLANT

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

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

The following data represent shares of the jointly owned property:

Trimble County
LG&E IMPA IMEA Total
---- ---- ---- -----

Ownership interest 75% 12.88% 12.12% 100%
Mw capacity 371.25 63.75 60.00 495.00

(in thousands of $):
Cost $555,829
Accumulated
depreciation 157,252
--------
Net book value $398,577
========

Construction work
in progress
(included above) $12,704

In July 1999, following approval from the Kentucky Commission, LG&E purchased
for $45.7 million a 38% interest in two 164.5 Mw natural gas turbines installed
at KU's E.W. Brown facility (Units 6 and 7) from Capital Corp.

See also Note 12, Construction Program, for LG&E's purchase of two jointly owned
CTs in 2001.

NOTE 14 - SEGMENTS OF BUSINESS AND RELATED INFORMATION

Effective December 31, 1998, LG&E adopted SFAS No. 131, DISCLOSURE ABOUT
SEGMENTS OF AN ENTERPRISE AND RELATED INFORMATION. LG&E is a regulated public
utility engaged in the generation, transmission, distribution, and sale of
electricity and the storage, distribution, and sale of natural gas. Financial
data for business segments, follow (in thousands of $):

Electric Gas Total
-------- --- -----

2000

Operating revenues $710,958(a) $272,489 $983,447
Depreciation and amortization 84,761 13,530 98,291
Interest income 2,551 552 3,103
Interest expense 35,604 7,614 43,218
Operating income taxes 57,869 6,556 64,425
Net income 100,395 10,178 110,573
Total assets 1,760,305 465,779 2,226,084
Construction expenditures 109,798 34,418 144,216

1999

Operating revenues $ 790,670(b) $177,579 $ 968,249
Depreciation and amortization 83,619 13,602 97,221
Interest income 3,435 651 4,086
Interest expense 31,558 6,404 37,962
Operating income taxes 56,883 891 57,774
Net income 104,853 1,417 106,270
Total assets 1,775,498 395,954 2,171,452
Construction expenditures 160,844 33,800 194,644

1998

Operating revenues $ 658,511(c) $191,545 $ 850,056
Depreciation and amortization 79,866 13,312 93,178
Interest income 3,566 679 4,245
Interest expense 30,389 5,933 36,322
Merger costs 32,072 - 32,072
Operating income taxes 56,401 (94) 56,307
Net income 75,368 2,752 78,120
Total assets 1,727,463 377,174 2,104,637
Construction expenditures 105,836 32,509 138,345

(a) Net of provision for rate refunds of $2.5 million.
(b) Net of provision for rate refunds of $1.7 million.
(c) Net of provision for rate refunds of $4.5 million.

NOTE 15 - SELECTED QUARTERLY DATA (UNAUDITED)

Selected financial data for the four quarters of 2000 and 1999 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 $)

2000

Operating revenues $249,642 $209,731 $229,640 $294,434
Net operating income 26,592 37,285 48,161 36,832
Net income 17,421 28,009 38,117 27,026
Net income available
for common stock 16,256 26,692 36,756 25,659

1999

Operating revenues $226,620 $214,097 $296,395 $231,137
Net operating income 27,016 30,596 51,036 31,443
Net income 18,916 22,040 41,704 23,610
Net income available
for common stock 17,826 20,954 40,614 22,375

NOTE 16 - SUBSEQUENT EVENTS

On January 9, 2001, LG&E Energy announced a voluntary workforce separation
program for non-union employees. On January 18, 2001, the union members at LG&E
voted to approve a similar voluntary separation package. LG&E targeted areas
where reductions were necessary and employees in these targeted areas had a
one-time opportunity to accept the separation package. Employees began leaving
LG&E at the end of February 2001 and will continue through the end of the year.
LG&E estimates that the separation program will result in a workforce reduction
of approximately 700 employees.

On February 1, 2001, Roger Hale, Chairman of the Board and Chief Executive
Officer announced his retirement from LG&E Energy, LG&E, and KU effective April
30, 2001. Victor A. Staffieri will replace Roger Hale as Chairman and Chief
Executive Officer of LG&E Energy, LG&E, and KU.

On February 6, 2001, LG&E sold accounts receivables to a wholly-owned special
purpose subsidiary.

Simultaneously, the subsidiary entered into three-year accounts receivables
securitization facilities with two financial institutions whereby an undivided
interest in certain receivables are sold, on a revolving basis, for up to $75
million, at a cost of funds linked to commercial paper rates. Under the program
LG&E pays fees for administrative and credit support services.

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 generally accepted accounting principles applied on a consistent
basis and, necessarily, include amounts that reflect the best estimates and
judgment of management.

LG&E's financial statements have been audited by Arthur Andersen LLP,
independent public accountants. Management has made available to Arthur Andersen
LLP all LG&E's financial records and related data as well as the minutes of
shareholders' and directors' meetings. Management has established and maintains
a system of internal controls that provides reasonable assurance that
transactions are completed in accordance with management's authorization, that
assets are safeguarded and that financial statements are prepared in conformity
with generally accepted accounting principles. Management believes that an
adequate system of internal controls is maintained through the selection and
training of personnel, appropriate division of responsibility, establishment and
communication of policies and procedures and by regular reviews of internal
accounting controls by LG&E's internal auditors. Management reviews and modifies
its system of internal controls in light of changes in conditions and
operations, as well as in response to recommendations from the internal
auditors. These recommendations for the year ended December 31, 2000, did not
identify any material weaknesses in the design and operation of LG&E's internal
control structure.

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

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

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 sheets and statements 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 1999,
and the related statements of income, retained earnings, cash flows and
comprehensive income for each of the three years in the period ended December
31, 2000. These financial statements are the responsibility of LG&E'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 1999, and the results of its operations and
its cash flows for each of the three years in the period ended December 31,
2000, in conformity with accounting principles generally accepted in the United
States.

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

Louisville, Kentucky Arthur Andersen LLP
January 26, 2001 (Except with respect
to the matters discussed in Note 16, as
to which the date is February 6, 2001.)

Kentucky Utilities Company
Statements of Income
(Thousands of $)

Years Ended December 31
2000 1999 1998
---- ---- ----

OPERATING REVENUES:
Electric (Note 1)............................ $851,941 $943,210 $831,614
Provision for rate refunds (Note 3).......... - (5,900) (21,500)
--------- ---------- ----------
Total operating revenues................... 851,941 937,310 810,114
--------- ---------- ---------

OPERATING EXPENSES:
Fuel for electric generation................. 219,923 219,883 217,401
Power purchased.............................. 166,918 242,315 126,584
Other operation expenses..................... 108,072 116,521 121,275
Maintenance.................................. 61,643 57,318 63,608
Depreciation and amortization................ 98,256 89,922 86,657
Federal and state income taxes (Note 7)...... 51,963 60,380 53,256
Property and other taxes..................... 17,030 14,955 15,945
--------- ---------- ----------
Total operating expenses................... 723,805 801,294 684,726
--------- ---------- ----------

Net operating income............................ 128,136 136,016 125,388

Merger costs (Note 2)........................... - - 21,830
Other income - net (Note 8)..................... 6,843 9,437 7,846
Interest charges................................ 39,455 38,895 38,640
--------- ---------- ----------
Net income...................................... 95,524 106,558 72,764

Preferred stock dividends....................... 2,256 2,256 2,256
--------- ---------- ----------

Net income available for common stock........... $ 93,268 $104,302 $ 70,508
========= ========= ==========

Statements of Retained Earnings
(Thousands of $)

Years Ended December 31
2000 1999 1998
---- ---- ----

Balance January 1............................... $329,470 $299,167 $304,750
Add net income.................................. 95,524 106,558 72,764
--------- --------- ---------
424,994 405,725 377,514
--------- --------- ---------

Deduct: Cash dividends declared on stock:

4.75% cumulative preferred............. 950 950 950
6.53% cumulative preferred............. 1,306 1,306 1,306
Common................................. 75,500 73,999 76,091
---------- ---------- ----------
77,756 76,255 78,347
---------- ---------- ----------

Balance December 31............................. $347,238 $329,470 $299,167
======== ======== ========

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

Kentucky Utilities Company
Balance Sheets
(Thousands of $)

December 31
2000 1999
---- ----

ASSETS:
Utility plant, at original cost (Note 1)............... $2,826,383 $2,744,380
Less: reserve for depreciation........................ 1,378,283 1,288,819
----------- -----------
1,448,100 1,455,561
Construction work in progress.......................... 106,380 106,686
------------ ------------
1,554,480 1,562,247
------------ ------------
Other property and investments - less reserve.......... 14,538 14,349

Current assets:
Cash and temporary cash investments................. 314 6,793
Accounts receivable - less reserve of $800 in 2000
and 1999....................................... 90,419 88,549
Materials and supplies - at average cost:
Fuel (predominantly coal)......................... 12,495 30,225
Other............................................. 25,812 26,213
Prepayments and other............................... 1,899 3,743
-------------- --------------
130,939 155,523
------------ ------------

Deferred debits and other assets:
Unamortized debt expense............................ 4,651 4,827
Regulatory assets (Note 3).......................... 26,441 23,033
Other............................................... 8,469 25,111
---------- -----------
39,561 52,971
---------- -----------
$1,739,518 $1,785,090
========== ===========
CAPITAL AND LIABILITIES:
Capitalization (see statements of capitalization):
Common equity....................................... $ 669,783 $ 637,015
Cumulative preferred stock.......................... 40,000 40,000
Long-term debt (Note 9)............................. 430,830 430,830
------------ ------------
1,140,613 1,107,845
------------ ------------
Current liabilities:
Current portion of long-term debt (Note 9).......... 54,000 115,500
Notes payable (Note 10)............................. 61,239 -
Accounts payable.................................... 76,339 116,546
Provision for rate refunds.......................... - 20,567
Dividends declared.................................. 188 19,150
Accrued taxes....................................... 19,622 10,502
Accrued interest.................................... 6,373 7,329
Other............................................... 18,579 18,617
------------ ------------
236,340 308,211
------------ ------------

Deferred credits and other liabilities:

Accumulated deferred income taxes (Notes 1 and 7)... 246,680 243,620
Investment tax credit, in process of amortization... 14,901 18,575
Accumulated provision for pensions and related
benefits (Note 6).................................. 47,495 48,285
Customers' advances for construction................ 1,540 1,174
Regulatory liabilities (Note 3)..................... 38,392 46,069
Other............................................... 13,557 11,311
------------ ------------
362,565 369,034
------------ ------------
Commitments and contingencies (Note 11)
$1,739,518 $1,785,090
============ ============

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

Kentucky Utilities Company
Statements of Cash Flows
(Thousands of $)

Years Ended December 31
2000 1999 1998
---- ---- ----

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income....................................... $ 95,524 $ 106,558 $ 72,764
Items not requiring cash currently:
Depreciation and amortization.................. 98,256 89,922 86,657
Deferred income taxes - net.................... (2,449) (3,763) (2,437)
Investment tax credit - net.................... (3,674) (3,727) (3,829)
Change in certain net current assets:
Accounts receivable............................ (1,870) 17,576 (31,482)
Materials and supplies......................... 18,131 (8,263) 3,272
Accounts payable............................... (40,207) 6,514 71,162
Provision for rate refunds..................... (20,567) (933) 21,500
Accrued taxes.................................. 9,120 (6,231) 9,260
Accrued interest............................... (956) (781) (173)
Prepayments and other.......................... 1,806 (3,042) (53)
Other............................................ 23,136 10,346 12,776
--------- --------- ---------
Net cash flows from operating activities....... 176,250 204,176 239,417
--------- --------- ---------

CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from insurance reimbursement............ 259 206 179
Construction expenditures........................ (100,587) (181,341) (91,992)
--------- --------- ---------
Net cash flows used for investing activities... (100,328) (181,135) (91,813)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term borrowings............................ 61,239 - 381,500
Repayments of short-term borrowings.............. - - (415,100)
Retirement of long-term debt..................... (74,784) - (42)
Issuance of long-term debt....................... 12,900 - -
Additional paid-in capital....................... 15,000 - -
Payment of dividends............................. (96,756) (75,197) (60,347)
--------- --------- ---------
Net cash flows used for financing
activities.................................... (82,401) (75,197) (93,989)
--------- --------- ---------
Change in cash and temporary cash investments....... (6,479) (52,156) 53,615

Cash and temporary cash investments at
beginning of year.................................. 6,793 58,949 5,334
--------- --------- ---------
Cash and temporary cash investments at end of
year............................................... $ 314 $ 6,793 $ 58,949
========= ========= ========
Supplemental disclosures of cash flow
information:
Cash paid during the year for:
Income taxes................................ $ 49,871 $ 71,258 $ 46,490
Interest on borrowed money.................. 35,196 35,508 36,008

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

Kentucky Utilities Company
Statements of Capitalization
(Thousands of $)

December 31
2000 1999
---- ----

COMMON EQUITY:
Common stock, without par value -
outstanding 37,817,878 shares....................... $ 308,140 $ 308,140
Additional paid-in capital............................ 15,000 -
Retained earnings..................................... 347,238 329,470
Other................................................. (595) (595)
---------- ----------
669,783 637,015
---------- ----------
CUMULATIVE PREFERRED STOCK:

Shares Current
Outstanding Redemption Price
----------- ----------------

Without par value, 5,300,000
shares authorized -
4.75% series, $100 stated value
Redeemable on 30 days notice
by KU ....................... 200,000 $101.00 20,000 20,000
6.53% series, $100 stated value .. 200,000 Not redeemable 20,000 20,000
------------ -----------
40,000 40,000
------------ -----------
LONG-TERM DEBT - first mortgage bonds (Note 9):
Q due June 15, 2000, 5.95%............................ - 61,500
Q due June 15, 2003, 6.32%............................ 62,000 62,000
S due January 15, 2006, 5.99%......................... 36,000 36,000
P due May 15, 2007, 7.92%............................. 53,000 53,000
R due June 1, 2025, 7.55%............................. 50,000 50,000
P due May 15, 2027, 8.55%............................. 33,000 33,000
Pollution control series:
1B due February 1, 2018, 6.25%...................... 20,930 20,930
2B due February 1, 2018, 6.25%...................... 2,400 2,400
3B due February 1, 2018, 6.25%...................... 7,200 7,200
4B due February 1, 2018, 6.25%...................... 7,400 7,400
7, due May 1, 2010, 7.375%.......................... - 4,000
7, due May 1, 2020, 7.60%........................... - 8,900
8, due September 15, 2016, 7.45%.................... 96,000 96,000
9, due December 1, 2023, 5.75%...................... 50,000 50,000
10, due November 1, 2024, variable.................. 54,000 54,000
A, due May 1, 2023, variable........................ 12,900 -
------------- -----------
Total bonds outstanding............................. 484,830 546,330
Less current portion of long-term debt.............. 54,000 115,500
------------- ------------
Long-term debt...................................... 430,830 430,830
------------- ------------
Total capitalization................................ $1,140,613 $1,107,845
========== ==========

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

Kentucky Utilities Company
Notes to Financial Statements

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

KU, a subsidiary of LG&E Energy and an indirect subsidiary of Powergen, is a
regulated public utility engaged in the generation, transmission, distribution,
and sale of electric energy. LG&E Energy is an exempt public utility holding
company with wholly-owned subsidiaries including LG&E, KU, Capital Corp., LEM,
and LG&E Services. All of the KU's Common Stock is held by LG&E Energy.

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

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

DEPRECIATION AND AMORTIZATION. Depreciation is provided on the straight-line
method over the estimated service lives of depreciable plant. The amounts
provided for KU approximated 3.5% in 2000, 1999 and 1998.

Pursuant to a recently completed depreciation study, KU will implement the new
depreciation rates effective January 1, 2001. The new rate is expected to be 3%.

FINANCIAL INSTRUMENTS. KU uses over-the-counter interest-rate swap agreements to
hedge its exposure to interest rates. Gains and losses on interest-rate swaps
used to hedge interest rate risk are reflected in interest charges monthly. See
Note 4, Financial Instruments.

DEBT EXPENSE. Debt expense is amortized over the lives of the related bond
issues, consistent with regulatory practices.

DEFERRED INCOME TAXES. Deferred income taxes have been provided for all material
book-tax temporary differences.

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

REVENUE RECOGNITION. Revenues are recorded based on service rendered to
customers through month-end. KU accrues an estimate for unbilled revenues from
each meter reading date to the end of the accounting period. The unbilled
revenue estimates included in accounts receivable for KU equaled approximately
$34.8 million and $29.6 million at December 31, 2000 and 1999, respectively.

FUEL COSTS. The cost of fuel for electric generation is charged to expense as
used.

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

NEW ACCOUNTING PRONOUNCEMENTS. During 2000 and 1999, the following accounting
pronouncements were issued that affect KU:

SFAS No. 133, ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES,
establishes accounting and reporting standards requiring that every derivative
instrument (including certain derivative instruments embedded in other
contracts) be recorded on the balance sheet as either an asset or a liability
measured at its fair value. SFAS No. 133 requires that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. Special accounting for qualifying hedges
allows a derivative's gains and losses to offset related results on the hedged
item in the income statement, and requires that KU must formally document,
designate, and assess the effectiveness of transactions that receive hedge
accounting. SFAS No. 133 could increase the volatility in earnings and other
comprehensive income. SFAS No. 137, ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND
HEDGING ACTIVITIES -- DEFERRAL OF THE EFFECTIVE DATE OF SFAS NO. 133, deferred
the effective date of SFAS No. 133 until January 1, 2001. KU adopted SFAS No.
133 on January 1, 2001. The effect of this statement will result in a credit of
$1.6 million to cumulative effect of change in accounting principle (net of tax)
in other comprehensive income.

NOTE 2 - MERGERS AND ACQUISITIONS

On December 11, 2000, LG&E Energy Corp. and Powergen plc successfully
completed the merger transaction involving the two companies. LG&E Energy had
announced on February 28, 2000, that its Board of Directors accepted the
offer to be acquired by Powergen for cash of approximately $3.2 billion or
$24.85 per share and the assumption of $2.2 billion of LG&E Energy's debt.
Pursuant to the acquisition agreement, LG&E Energy became a wholly owned
subsidiary of Powergen and, as a result, KU became an indirect subsidiary of
Powergen. KU will continue its separate identity and serve customers in
Kentucky and Virginia under its existing name. The preferred stock and debt
securities of KU were not affected by this transaction and KU will continue
to file SEC reports. Following the merger, Powergen became a registered
holding company under PUHCA and KU, as a subsidiary of a registered holding
company, became subject to additional regulations under PUHCA.

LG&E Energy and KU Energy merged on May 4, 1998, with LG&E Energy as the
surviving corporation. As a

result of the merger, the LG&E Energy, which is the parent of LG&E, became the
parent company of KU. The operating utility subsidiaries (LG&E and KU) have
continued to maintain their separate corporate identities and serve customers in
Kentucky and Virginia under their present names. LG&E Energy has estimated
approximately $760 million in gross non-fuel savings over a ten-year period
following the merger. Costs to achieve these savings for KU of $42.3 million
were recorded in the second quarter of 1998, $20.5 million of which were
initially deferred and are being amortized over a five-year period pursuant to
regulatory orders. Primary components of the merger costs were separation
benefits, relocation costs, and transaction fees, the majority of which were
paid by December 31, 1998. KU expensed the remaining costs associated with the
merger ($21.8 million) at the time of the merger in the second quarter of 1998.
In regulatory filings associated with approval of the merger, KU committed not
to seek increases in existing base rates and proposed reductions in their retail
customers' bills in amounts based on one-half of the savings, net of the
deferred and amortized amount, over a five-year period. The preferred stock and
debt securities of KU were not affected by the merger.

Management has accounted for the LG&E Energy - KU Energy merger as a pooling
of interests and as a tax-free reorganization under the Internal Revenue Code.

As part of its LG&E Energy - KU Energy merger order, the Kentucky Commission
approved a surcredit whereby 50% of the net non-fuel cost savings estimated
to be achieved from the merger, less $38.6 million or 50% of the originally
estimated costs to achieve such savings, be applied to reduce customer rates
through a surcredit on customers' bills and the remaining 50% be retained by
the companies. The surcredit is allocated 53% to KU and 47% to LG&E pursuant
to Kentucky Commission order. The surcredit will be about 2% of customer
bills through mid 2003 and will amount to approximately $63 million in net
non-fuel savings to KU. Any fuel cost savings are passed to Kentucky
customers through the companies' fuel adjustment clauses. See Note 3 for more
information about KU's rates and regulatory matters.

NOTE 3 - UTILITY RATES AND REGULATORY MATTERS

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

2000 1999
---- ----

Unamortized loss on bonds $ 7,011 $ 7,594
Merger costs 10,232 14,324
Other 925 1,115
One utility costs 8,273 -
----------- ---------
Total regulatory assets 26,441 23,033
--------- ---------

Deferred income taxes - net (37,484) (42,992)
Other (908) (3,077)
----------- ----------
Total regulatory liabilities (38,392) (46,069)
--------- ---------

Regulatory liabilities - net $(11,951) $(23,036)
======== ========

PUHCA. Following the merger transaction involving LG&E Energy and Powergen,
Powergen became a registered holding company under PUHCA. As a result, Powergen,
its utility subsidiaries, including KU, and certain of its non-utility
subsidiaries are subject to extensive regulation by the SEC under PUHCA with
respect to issuances and sales of securities, acquisitions and sales of certain
utility properties, and intra-system sales of certain goods and services. In
addition, PUHCA generally limits the ability of registered holding companies to
acquire additional public utility systems and to acquire and retain businesses
unrelated to the utility operations of the holding company. Powergen believes
that it has adequate authority (including financing authority) under existing
SEC orders and regulations for it and its subsidiaries to conduct their
businesses as proposed during 2001. Powergen will seek additional authorization
when necessary.

ENVIRONMENTAL COST RECOVERY. In August 1999, a final order of the Kentucky
Commission approved KU's settlement agreement concerning the refund of the
recovery of costs associated with pre-1993 environmental projects. KU began
applying the refund to customers' bills in October 1999 and completed the refund
process in the month of November 2000. All aspects of the original litigation of
this issue have now been resolved.

ELECTRIC PBR/ESM. In October 1998, KU filed an application with the Kentucky
Commission for approval of a new method of determining electric rates that
sought to provide financial incentives for KU to further reduce customers'
rates. The filing was made pursuant to the September 1997 Kentucky Commission
order approving the merger of LG&E Energy and KU Energy, wherein the Kentucky
Commission directed KU to indicate whether they desired to remain under
traditional rate of return regulation or commence non-traditional regulation.
The proposed ratemaking method, known as PBR, included financial incentives for
KU to reduce fuel costs and increase generating efficiency, and to share any
resulting savings with customers. Additionally, the PBR proposal provided for
financial penalties and rewards to assure continued high quality service and
reliability.

the next three years. Under this mechanism, incremental annual earnings for KU
resulting in a rate of return on equity either above or below a range of 10.5%
to 12.5% would be shared 60% with shareholders and 40% with ratepayers.

Later in January 2000, KU filed motions for correction to the January 2000
orders for computational and other errors made in the Kentucky Commission's
orders which produced overstatements in the base rate reductions to KU of $7.7
million. In February 2000, KU accepted the Kentucky Commission's opportunity to
use an ESM by filing an ESM tariff, which contains the provisions operating
under such mechanism. In June 2000, the Kentucky Commission ruled that the final
rate reduction should be $30.4 million, a change of approximately $6.1 million
from the original order and ordered KU to implement the revised rates effective
with service rendered beginning June 1, 2000. KU reinstated its FAC beginning
with March 2000 billings.

The first ESM filing was made on March 1, 2001, for year ended December 31,
2000. By order of the Kentucky Commission rate changes prompted by the ESM
filing go into effect in April of each year. At December 31, 2000, KU expects to
fall within the range, therefore no adjustment was made to the financial
statements.

DSM. In September 2000, KU filed a plan with the Kentucky Commission that would
expand LG&E's current DSM programs into the service territory served by KU. The
filing includes a rate mechanism that provides for concurrent recovery of DSM
costs, provides an incentive for implementing DSM programs, and recovers
revenues from lost sales associated with the DSM program. The Kentucky
Commission has not issued an order in this case. KU expects a ruling by
mid-2001.

FAC. Prior to implementation of the PBR in July 1999, and following its
termination in March 2000, KU employed an FAC mechanism, which under Kentucky
law allowed the utilities to recover from customers the actual fuel costs
associated with retail electric sales.

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 intends to
address two major areas in the proceedings: the tools and conditions needed to
prevent cost shifting and cross-subsidization between regulated and non-utility
operations; and whether a code of conduct should be established to assure that
non-utility segments of the holding company are not engaged in practices that
could result in unfair competition caused by cost shifting from the non-utility
affiliate to the utility. In September 1998, the Kentucky Commission issued a
draft code of conduct and cost allocation guidelines. In January 1999, KU, as
well as all parties to the proceeding, filed comments on the Kentucky Commission
draft proposals. In December 1999, the Kentucky Commission issued guidelines on
cost allocation and held a hearing in January 2000, on the draft code of
conduct. In February 2000, the Kentucky Commission issued its ruling in the
case, including a draft Code of Conduct for the purpose of further consideration
in the process to promulgate a regulation. 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. On February 14, 2001, the Kentucky Commission
published notice of their intent to promulgate new administrative regulations.
In the same Bill, the General Assembly set forth provisions to govern a
utilities activities related to the sharing of information, databases, and
resources between its employees or an affiliate involved in the marketing or the
provision of nonregulated activities and its employees or an affiliate involved
in the provision of regulated services. The legislation became law in July 2000
and KU has been operating pursuant thereto since that time.

NOTE 4 - FINANCIAL INSTRUMENTS

The cost and estimated fair values of the KU's non-trading financial instruments
as of December 31, 2000, and 1999 follow (in thousands of $):

2000 1999
---- ----
Fair Fair
Cost Value Cost Value
---- ----- ---- -----

Long-term debt (including
current portion) $484,830 $491,277 $546,330 $542,242
Interest-rate swaps - 3,559 - (1,951)

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 is party to three interest rate swaps with notional
amounts totaling $153 million. In each case, KU pays a variable rate based on
either LIBOR or the Bond Market Association's municipal swap index. In return,
KU receives a fixed rate equal to the rate on underlying long-term debt of
Series P, R, and PCS-9. At year end, KU paid an average rate of 6.69% and
received an average rate of 7.13%. The swaps mature on dates ranging from 2007
to 2025.

NOTE 5 - CONCENTRATIONS OF CREDIT AND OTHER RISK

to meet contractual obligations to be similarly affected by changes in economic
or other conditions.

KU's customer receivables and revenues arise from deliveries of electricity to
about 464,000 customers in over 600 communities and adjacent suburban and rural
areas in 77 counties in central, southeastern and western Kentucky and to about
29,000 customers in five counties in southwestern Virginia. For the year ended
December 31, 2000, 100% of total utility revenue was derived from electric
operations.

In August 2000, KU and their employees represented by IBEW Local 2100 entered
into a one-year collective bargaining agreement. At the same time, KU and their
employees represented by USWA Local 9447-01 entered into a two year collective
bargaining agreement with a reopener for wages only to be effective August 1,
2001. The employees represented by these two bargaining units makeup
approximately 15% of KU's workforce.

NOTE 6 - PENSION PLANS AND RETIREMENT BENEFITS

PENSION PLANS. KU sponsors qualified and non-qualified pension plans and other
postretirement benefit plans for its employees. The following tables provide a
reconciliation of the changes in the plans' benefit obligations and fair value
of assets over the three-year period ending December 31, 2000, and a statement
of the funded status as of December 31 for each of the last three years (in
thousands of $):

2000 1999 1998
---- ---- ----

PENSION PLANS:
Change in benefit obligation
Benefit obligation at beginning of
year $219,628 $233,288 $214,657
Service cost 4,312 6,210 6,672
Interest cost 17,205 15,564 15,043
Plan amendment 11,757 - 2,226
Acquisitions/divestitures - - (2,243)
Curtailment (gain) or loss - - 1,901
Special termination benefits - - 5,427
Benefits paid (16,512) (12,822) (12,762)
Actuarial (gain) or loss and other (3,356) (22,612) 2,367
-------- -------- --------
Benefit obligation at end of year $233,034 $219,628 $233,288
======== ======== ========

Change in plan assets
Fair value of plan assets at
beginning of year $274,109 $238,124 $217,500
Actual return on plan assets (10,943) 49,883 31,209
Employer contributions and plan
transfers (994) - 2,273
Benefits paid (16,512) (12,822) (12,762)
Administrative expenses (983) (1,076) (96)
-------- -------- --------
Fair value of plan assets at end
of year $244,677 $274,109 $238,124
======== ======== ========

Reconciliation of funded status
Funded status $ 11,643 $ 54,481 $ 4,835
Unrecognized actuarial (gain) or loss (36,435) (74,579) (26,487)
Unrecognized transition (asset) or
obligation (847) (988) (1,128)
Unrecognized prior service cost 14,176 3,564 4,943
-------- --------- --------
Net amount recognized at year-end $(11,463) $ (17,522) $(17,837)
======== ========= ========

OTHER BENEFITS:
Change in benefit obligation
Benefit obligation at beginning
of year $ 54,201 $ 79,650 $ 72,139

Service cost 757 1,596 2,012
Interest cost 4,781 3,837 5,207
Plan amendments 7,127 (24,488) -
Curtailment (gain) or loss - - 3,240
Special termination benefits - - -
Benefits paid (4,318) (4,646) (2,617)
Actuarial (gain) or loss 1,665 (1,748) (331)
-------- -------- --------
Benefit obligation at end of year $ 64,213 $ 54,201 $ 79,650
======== ======== ========

Change in plan assets
Fair value of plan assets at
beginning of year $ 28,720 $ 24,337 $ 17,763
Actual return on plan assets (1,162) 5,322 5,117
Employer contributions 522 3,520 3,805
Benefits paid (4,318) (4,459) (2,348)
-------- -------- --------
Fair value of plan assets at end
of year $ 23,762 $ 28,720 $ 24,337
======== ======== ========

Reconciliation of funded status
Funded status $(40,451) $(25,481) $(55,313)
Unrecognized actuarial (gain) or loss (23,561) (28,976) (19,944)
Unrecognized transition (asset) or
obligation 21,871 23,694 45,701
Unrecognized prior service cost 6,109 - -
-------- -------- --------
Net amount recognized at year-end $(36,032) $(30,763) $(29,556)
======== ======== ========

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

2000 1999 1998
---- ---- ----

PENSION PLANS:
Amounts recognized in the balance
sheet consisted of:
Accrued benefit liability $(11,463) $(17,522) $(17,837)
Other - - (22)
-------- -------- --------
Net amount recognized at
year-end $(11,463) $(17,522) $(17,859)
======== ======== ========

Additional year-end information for
plans with accumulated benefit
obligations in excess of plan assets:

Projected benefit obligation $ 1,505 $ 1,132 $ 2,300
Accumulated benefit obligation 336 40 99

OTHER BENEFITS:
Amounts recognized in the balance
sheet consisted of:
Accrued benefit liability $(36,032) $ (30,763) $(29,556)
Other - - (2,817)
-------- -------- --------
Net amount recognized at
year-end $(36,032) $ (30,763) $(32,373)
======== ======== ========

Additional year-end information for
plans with benefit obligations in
excess of plan assets:
Projected benefit obligation $ 64,213 $ 54,201 $ 79,650
Fair value of plan assets 23,762 28,720 24,337

The following table provides the components of net periodic benefit cost for the
plans for 2000, 1999 and 1998

(in thousands of $):

2000 1999 1998
---- ---- ----

PENSION PLANS:
Components of net periodic benefit
cost
Service cost $ 4,312 $ 6,211 $ 6,673
Interest cost 17,205 15,564 15,043
Expected return on plan assets (25,170) (21,957) (18,264)
Amortization of transition (asset)
or obligation (141) (141) 435
Amortization of prior service cost 1,145 410 (146)
Amortization of net (gain) loss (3,410) (319) (151)
-------- -------- --------
Net periodic benefit cost $ (6,059) $ (232) $ 3,590
======== ======== ========

Special charges
Prior service cost recognized $ - $ - $ 67
Special termination benefits - - 5,427
-------- -------- --------
Total charges $ - $ - $ 5,494
======== ======== ========

OTHER BENEFITS:
Components of net periodic benefit cost
Service cost $ 757 $ 1,596 $ 2,012
Interest cost 4,781 3,837 5,207
Expected return on plan assets (1,768) (1,897) (1,424)
Amortization of prior service cost 1,018 - -
Amortization of transition (asset) or
obligation 1,823 1,823 3,303
Amortization of net (gain) loss (820) (445) (536)
-------- -------- --------
Net periodic benefit cost $ 5,791 $ 4,914 $ 8,562
======== ======== ========

Special charges
Curtailment loss $ - $ - $ 1,114
======== ======== ========

On May 4, 1998 LG&E Energy and KU Energy merged, with LG&E Energy as the
surviving corporation. At the time of the merger KU had both qualified and
nonqualified pension plans.

Effective May 4, 1998, due to the change in control, the present value balance
of KU's SERP of $4.9 million was transferred and allocated between LG&E Energy's
Nonqualified Savings Plan and KU's Nonqualified Savings plan of $2.2 million and
$2.7 million, respectively. The plan is an unfunded, pretax deferred
compensation program which provides officers and senior managers of KU the
opportunity to defer earnings above the qualified savings plan limits. As an
"Unfunded" plan the money is not specifically invested or secured and future
distributions will be made from the general assets of KU. Currently interest is
credited at a rate equal to the average yield on five-year Treasury notes.

During 1998, KU invested approximately $6.6 million in special termination
benefits as a result of its early retirement program offered to eligible
employees post-merger.

KU provides nonpension postretirement benefits for eligible retired employees.

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

2000 1999 1998
---- ---- ----

Weighted-average assumptions as of
December 31:

Discount rate 7.75% 8.00% 7.00%
Expected long-term rate of return on
plan assets 9.50% 9.50% 8.25%
Rate of compensation increase 4.75% 5.00% 4.00%

1% Decrease 1% Increase
----------- -----------

Effect on total of service and interest cost
components for 2000 $ (426) $ 483
Effect on year-end 2000 postretirement benefit
obligations (4,085) 4,640

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 $2.5 million for 2000, $2.3 million for 1999 and $2.2 million for
1998.

NOTE 7 - INCOME TAXES

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

2000 1999 1998
---- ---- ----

Included in operating expenses:
Current - federal $44,927 $50,969 $46,321
- state 9,333 13,459 10,245
Deferred - federal - net (3,254) (4,833) (3,186)
- state - net 957 785 (124)
------- ------- -------
Total 51,963 60,380 53,256
------- ------- -------

Included in other income - net:

Current - federal 349 1,028 (617)
- state 67 54 (237)
Deferred - federal - net (122) 182 694
- state - net (30) 102 178
Amortization of investment tax credit (3,674) (3,727) (3,829)
------- ------- -------
Total (3,410) (2,361) (3,811)
------- ------- -------

Total income tax expense $48,553 $58,019 $49,445
======= ======= =======

Net deferred tax liabilities resulting from book-tax temporary differences are
shown below (in thousands of $):

2000 1999

Deferred tax liabilities:
Depreciation and other
plant-related items $279,047 $313,202
Other liabilities 13,718 11,286
-------- --------

292,765 324,488
-------- --------
Deferred tax assets:
Investment tax credit 6,014 7,497
Income taxes due to customers 15,124 16,712
Pension overfunding 3,974 5,797
Accrued liabilities not currently
deductible and other 20,973 50,862
-------- --------
46,085 80,868
-------- --------
Net deferred income tax liability $246,680 $243,620
======== ========

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

2000 1999 1998
---- ---- ----

Statutory federal income tax rate 35.0% 35.0% 35.0%
State income taxes, net of federal benefit 4.9 5.7 5.4
Amortization of investment tax credit (2.6) (2.9) (3.1)
Nondeductible merger expenses - - 6.4
Other differences - net (3.6) (2.5) (2.2)
----- ----- -----

Effective income tax rate 33.7% 35.3% 41.5%
==== ==== ====

NOTE 8 - OTHER INCOME - NET

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

2000 1999 1998
---- ---- ----

Equity in earnings - subsidiary company $ 2,242 $ 2,334 $ 2,167
Interest and dividend income 1,206 4,293 1,811
Gains on fixed asset disposals 5 759 272
Income taxes and other 3,390 2,051 3,596
-------- -------- --------

Other income - net $ 6,843 $9,437 $ 7,846
======= ====== =======

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, 2000.

Stated interest rates Variable, 5.75% - 8.55%
Weighted-average interest rate 6.64%
Maturities 2003 - 2027
Noncurrent portion $430,830
Current portion $54,000

Under the provisions for KU's variable-rate pollution control bonds, the bonds
are subject to tender for purchase at the option of the holder and to mandatory
tender for purchase upon the occurrence of certain events, causing

the bonds to be classified as current portion of long-term debt. The average
annualized interest rate for these bonds during 2000 was 4.36%.

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

KU's First Mortgage Bond, 6.32% Series Q of $62 million is scheduled to mature
in 2003. There are no scheduled maturities of Pollution Control Bonds for the
five years subsequent to December 31, 2000.

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

NOTE 10 - NOTES PAYABLE

At December 31, 2000, KU had $61.2 million in notes payable to LG&E Energy Corp.
The note payable is due on demand and has an average percentage rate at December
31, 2000 of 6.68%. The rate is based on the available borrowing rate as of the
last day of the prior month.

KU had no short-term borrowings at December 31, 1999.

KU maintains an uncommitted line of credit which totaled $100 million at
December 31, 2000. There was no outstanding balance as of that date.

NOTE 11 - COMMITMENTS AND CONTINGENCIES

CONSTRUCTION PROGRAM. KU had $11.5 million of commitments in connection with its
construction program at December 31, 2000. Construction expenditures for the
years 2001 and 2002 are estimated to total approximately $300 million. Included
in 2001 is $51 million for the purchase of 47% of two CTs currently under
construction. One of the CTs is being built at KU's E.W. Brown location and the
other at LG&E's Paddy Run location. LG&E will own 53% of the two CTs. KU has
received approval from the Kentucky Commission for the purchase of the CTs. KU
is still waiting for confirmation of certain matters from the Virginia
Commission.

OPERATING LEASES. KU leases office space, office equipment, and vehicles. KU
accounts for these leases as operating leases. Total lease expense for 2000,
1999, and 1998, was $2.3 million, $1.7 million, and $1.9 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.
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 technology. KU will
continue to monitor these developments to ensure that its environmental

obligations are met in the most efficient and cost-effective manner.

In September 1998, the EPA announced its final "NOx SIP Call" rule requiring
states to impose significant additional reductions in NOx emissions by May 2003,
in order to mitigate alleged ozone transport impacts on the Northeast region.
The Commonwealth of Kentucky is currently in the process of revising its State
Implementation Plan or "SIP" to require reductions in NOx emissions from
coal-fired generating units to the 0.15 lb./Mmbtu level on a system-wide basis.
In related proceedings in response to petitions filed by various Northeast
states, in December 1999, EPA issued a final rule pursuant to Section 126 of the
Clean Air Act directing similar NOx reductions from a number of specifically
targeted generating units including all KU units in the eastern half of
Kentucky. Additional petitions currently pending before EPA may potentially
result in rules encompassing KU's remaining generating units. Both rules were
appealed to the U.S. Court of Appeals for the D.C. Circuit. The D.C. Circuit
subsequently upheld most provisions of the NOx SIP Call rule, but extended the
compliance date to May, 2004. As the court has yet to issue a final ruling on
the Section 126 rule, all KU generating units, except for KU's Green River
generating station, remain subject to the May 2003 compliance date under that
rule. As KU's Green River station is not covered by the Section 126 rule, those
facilities are subject to the May 2004 compliance date as extended by the D.C.
Circuit. KU continues to monitor the status of various appeals pending in the
D.C. Circuit and U.S. Supreme Court.

KU is currently implementing a plan for adding significant additional NOx
controls to its generating units. Installation of additional NOx controls will
proceed on a phased basis, with installation of controls commencing in late 2000
and continuing through the final compliance date. KU estimates that it will
incur total capital costs of approximately $195 million to reduce its NOx
emissions to the 0.15 lb./Mmbtu level on a company-wide basis. 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 anticipates that
such capital and operating costs are the type of costs that are eligible for
recovery from customers under its environmental surcharge mechanism and believes
that a significant portion of such costs could be recovered. However, Kentucky
Commission approval is necessary and there can be no guarantee of recovery.

KU is also addressing other air quality issues. First, KU is monitoring the
status of EPA's revised NAAQS for ozone and particulate matter. In May 1999, the
Washington D.C. Circuit remanded the final rule and directed EPA to undertake
additional rulemaking efforts. KU continues to monitor EPA actions to challenge
that ruling.

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 2001-2005, which is expected to be
approximately 10% of KU's total kWh requirements, is dependent upon a number of
factors including the units' availability, maintenance schedules, fuel costs and
OMU requirements. Payments are based on the total

costs of the station allocated per terms of the OMU agreement, which generally
follows delivered kWh. Included in the total costs is KU's proportionate share
of debt service requirements on $164 million of OMU bonds outstanding at
December 31, 2000. The debt service is allocated to KU based on its annual
allocated share of capacity, which averaged approximately 46% in 2000.

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

KU has several other contracts for purchased power during 2001 - 2005 of various
Mw capacities and for varying periods with a maximum entitlement at any time of
62 Mw.

The estimated future minimum annual payments under purchased power agreements
for the five years ended December 31, 2005, are as follows (in thousands of $):

2001 $ 31,545
2002 30,683
2003 30,946
2004 31,155
2005 31,310
--------
Total $155,639
========

NOTE 12 - JOINTLY OWNED ELECTRIC UTILITY PLANT

In July 1999, following approval from the Kentucky Commission, KU purchased for
$76.7 million a 62% interest in two 164.5 Mw natural gas turbines installed at
the E.W. Brown facility (Units 6 and 7) from Capital Corp.

See also Note 11, Construction Program, for KU's purchase of two jointly owned
CTs in 2001.

NOTE 13 - SELECTED QUARTERLY DATA (UNAUDITED)

Quarters Ended
March June September December
----- ---- --------- --------
(Thousands of $)

2000
Revenues $217,778 $205,324 $215,984 $212,855
Operating income 28,753 28,912 37,161 33,310
Net income 20,174 21,532 28,483 25,335
Net income available
for common stock 19,610 20,968 27,919 24,771

1999
Revenues $217,349 $225,794 $281,503 $212,664
Operating income 36,966 34,997 32,529 31,524
Net income (loss) 29,628 27,757 24,426 24,747
Net income (loss) available
for common stock 29,064 27,193 23,862 24,183

NOTE 14 - SUBSEQUENT EVENTS

On January 9, 2001, LG&E Energy announced a voluntary workforce separation
program for non-union employees. On January 18, 2001, the union members at KU
voted to approve a similar voluntary separation package. KU targeted areas where
reductions were necessary and employees in these targeted areas had a one-time
opportunity to accept the separation package. Employees began leaving KU at the
end of February 2001 and will continue through the end of the year. KU estimates
that the separation program will result in a workforce reduction of
approximately 250 employees.

On February 6, 2001, KU sold accounts receivables to a wholly-owned special
purpose subsidiary. Simultaneously, the subsidiary entered into three-year
accounts receivables securitization facilities with two financial institutions
whereby an undivided interest in certain receivables are sold, on a revolving
basis, for up to $50 million, at a cost of funds linked to commercial paper
rates. Under the program, KU pays fees for administrative and credit support
services.

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
generally accepted accounting principles applied on a consistent basis and,
necessarily, include amounts that reflect the best estimates and judgment of
management.

KU's financial statements have been audited by Arthur Andersen LLP, independent
public accountants. Management has made available to Arthur Andersen LLP all
KU's financial records and related data as well as the minutes of shareholders'
and directors' meetings.

Management has established and maintains a system of internal controls that
provide reasonable assurance that transactions are completed in accordance with
management's authorization, that assets are safeguarded and that financial
statements are prepared in conformity with generally accepted accounting
principles. Management believes that an adequate system of internal controls is
maintained through the selection and training of personnel, appropriate division
of responsibility, establishment and communication of policies and procedures
and by regular reviews of internal accounting controls by KU's internal
auditors. Management reviews and modifies its system of internal controls in
light of changes in conditions and operations, as well as in response to
recommendations from the internal auditors. These recommendations for the year
ended December 31, 2000, did not identify any material weaknesses in the design
and operation of KU's internal control structure.

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

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

Kentucky Utilities Company
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Shareholders of Kentucky Utilities Company:

We have audited the accompanying balance sheets and statements 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 1999,
and the related statements of income, retained earnings and cash flows for each
of the three years in the period ended December 31, 2000. These financial
statements are the responsibility of KU's management. Our responsibility is to
express an opinion on these financial statements based on our audits.

In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Kentucky Utilities Company as
of December 31, 2000 and 1999, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 2000, in
conformity with accounting principles generally accepted in the United States.

Louisville, Kentucky Arthur Andersen LLP
January 26, 2001 (Except with respect
to the matters discussed in Note 14, as
to which the date is February 6, 2001.)

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

None.

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 is
set forth in Exhibit 99.02 filed herewith and is incorporated by reference
thereto. Additionally, in accordance with General Instruction G,
the information required by ITEM 10 relating to executive officers of LG&E
and KU has been included in Part I of this Form 10-K.

PART IV

ITEM 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.

(a) 1. Financial Statements (included in Item 8):

LG&E:

Statements of income for the three years ended December 31, 2000 (page
49).
Statements of retained earnings for the three years ended December 31,
2000 (page 49).
Statements of comprehensive income for the three years ended December
31, 2000 (page 50).
Balance sheets - December 31, 2000, and 1999 (page 51).
Statements of cash flows for the three years ended December 31, 2000
(page 52).
Statements of capitalization - December 31, 2000, and 1999 (page 53).
Notes to financial statements (pages 54-71).
Report of management (page 72). Report of independent public accountants
(page 73).

KU:

Statements of income for the three years ended December 31, 2000 (page
74).
Statements of retained earnings for the three years ended December 31,
2000 (page 74).
Balance sheets - December 31, 2000, and 1999 (page 75).
Statements of cash flows for the three years ended December 31, 2000
(page 76).
Statements of capitalization - December 31, 2000, and 1999 (page 77).
Notes to financial statements (pages 78-92).
Report of management (page 93). Report of independent public accountants
(page 94).

2. Financial Statement Schedules (included in Part IV):

Schedule II Valuation and Qualifying Accounts for the three years ended
December 31, 2000, for LG&E (page 114), and KU (page 115).

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

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

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

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

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

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

3.02 x Copy of By-Laws of LG&E, as amended through June 2, 1999.
[Filed as Exhibit 3.02 to LG&E's Annual Report on Form 10-K
for the year ended December 31, 1999 and incorporated by
reference herein.]

3.03 x Copy of Amended and Restated Articles of Incorporation of KU
[Filed as Exhibits 4.03 and 4.04 to Form 8-K Current Report
of KU, dated December 10, 1993, and incorporated by
reference herein]

3.04 x Copy of By-laws of KU, as amended through June 2, 1999.
[Filed as Exhibit 3.04 to KU's Annual Report on Form 10-K
for the year ended December 31, 1999 and incorporated by
reference herein.]

4.01 x Copy of Trust Indenture dated November 1, 1949, from LG&E to
Harris Trust and Savings Bank, Trustee. [Filed as Exhibit
7.01 to LG&E's Registration Statement 2-8283 and
incorporated by reference herein]

4.02 x Copy of Supplemental Indenture dated February 1, 1952, which
is a supplemental instrument to Exhibit 4.01 hereto. [Filed
as Exhibit 4.05 to LG&E's Registration Statement 2-9371 and
incorporated by reference herein]

4.03 x Copy of Supplemental Indenture dated February 1, 1954, which
is a

supplemental instrument to Exhibit 4.01 hereto. [Filed as
Exhibit 4.03 to LG&E's Registration Statement 2-11923 and
incorporated by reference herein]

4.04 x Copy of Supplemental Indenture dated September 1, 1957,
which is a supplemental instrument to Exhibit 4.01 hereto.
[Filed as Exhibit 2.04 to LG&E's Registration Statement
2-17047 and incorporated by reference herein]

4.05 x Copy of Supplemental Indenture dated October 1, 1960, which
is a supplemental instrument to Exhibit 4.01 hereto. [Filed
as Exhibit 2.05 to LG&E's Registration Statement 2-24920 and
incorporated by reference herein]

4.06 x Copy of Supplemental Indenture dated June 1, 1966, which is
a supplemental instrument to Exhibit 4.01 hereto. [Filed as
Exhibit 2.06 to LG&E's Registration Statement 2-28865 and
incorporated by reference herein]

4.07 x Copy of Supplemental Indenture dated June 1, 1968, which is
a supplemental instrument to Exhibit 4.01 hereto. [Filed as
Exhibit 2.07 to LG&E's Registration Statement 2-37368 and
incorporated by reference herein]

4.08 x Copy of Supplemental Indenture dated June 1, 1970, which is
a supplemental instrument to Exhibit 4.01 hereto. [Filed as
Exhibit 2.08 to LG&E's Registration Statement 2-37368 and
incorporated by reference herein]

4.09 x Copy of Supplemental Indenture dated August 1, 1971, which
is a supplemental instrument to Exhibit 4.01 hereto. [Filed
as Exhibit 2.09 to LG&E's Registration Statement 2-44295 and
incorporated by reference herein]

4.10 x Copy of Supplemental Indenture dated June 1, 1972, which is
a supplemental instrument to Exhibit 4.01 hereto. [Filed as
Exhibit 2.10 to LG&E's Registration Statement 2-52643 and
incorporated by reference herein]

4.11 x Copy of Supplemental Indenture dated February 1, 1975, which
is a supplemental instrument to exhibit 4.01 hereto. [Filed
as Exhibit 2.11 to LG&E's Registration Statement 2-57252 and
incorporated by reference herein]

4.12 x Copy of Supplemental Indenture dated September 1, 1975,
which is a supplemental instrument to Exhibit 4.01 hereto.
[Filed as Exhibit 2.12 to LG&E's Registration Statement
2-57252 and incorporated by reference herein]

4.13 x Copy of Supplemental Indenture dated September 1, 1976,
which is a supplemental instrument to Exhibit 4.01 hereto.
[Filed as Exhibit 2.13 to LG&E's Registration Statement
2-57252 and incorporated by reference herein]

4.14 x Copy of Supplemental Indenture dated October 1, 1976, which
is a supplemental instrument to Exhibit 4.01 hereto. [Filed
as Exhibit 2.14 to LG&E's Registration Statement 2-65271 and
incorporated by reference herein]

4.15 x Copy of Supplemental Indenture dated June 1, 1978, which is
a supplemental instrument to Exhibit 4.01 hereto. [Filed as
Exhibit 2.15 to LG&E's Registration Statement 2-65271 and
incorporated by reference herein]

4.16 x Copy of Supplemental Indenture dated February 15, 1979,
which is a supplemental instrument to Exhibit 4.01 hereto.
[Filed as Exhibit 2.16 to LG&E's Registration Statement
2-65271 and incorporated by reference herein]

4.17 x Copy of Supplemental Indenture dated September 1, 1979,
which is a supplemental instrument to Exhibit 4.01 hereto.
[Filed as Exhibit 4.17 to LG&E's Annual Report on Form 10-K
for the year ended December 31, 1980, and incorporated by
reference herein]

4.18 x Copy of Supplemental Indenture dated September 15, 1979,
which is a supplemental instrument to Exhibit 4.01 hereto.
[Filed as Exhibit 4.18 to LG&E's Annual Report on Form 10-K
for the year ended December 31, 1980, and incorporated by
reference herein]

4.19 x Copy of Supplemental Indenture dated September 15, 1981,
which is a supplemental instrument to Exhibit 4.01 hereto.
[Filed as Exhibit 4.19 to LG&E's Annual Report on Form 10-K
for the year ended December 31, 1981, and incorporated by
reference herein]

4.20 x Copy of Supplemental Indenture dated March 1, 1982, which is
a supplemental instrument to Exhibit 4.01 hereto. [Filed as
Exhibit 4.20 to

LG&E's Annual Report on Form 10-K for the year ended
December 31, 1982, and incorporated by reference herein]

4.21 x Copy of Supplemental Indenture dated March 15, 1982, which
is a supplemental instrument to Exhibit 4.01 hereto. [Filed
as Exhibit 4.21 to LG&E's Annual Report on Form 10-K for the
year ended December 31, 1982, and incorporated by reference
herein]

4.22 x Copy of Supplemental Indenture dated September 15, 1982,
which is a supplemental instrument to Exhibit 4.01 hereto.
[Filed as Exhibit 4.22 to LG&E's Annual Report on Form 10-K
for the year ended December 31, 1982, and incorporated by
reference herein]

4.23 x Copy of Supplemental Indenture dated February 15, 1984,
which is a supplemental instrument to Exhibit 4.01 hereto.
[Filed as Exhibit 4.23 to LG&E's Annual Report on Form 10-K
for the year ended December 31, 1984, and incorporated by
reference herein]

4.24 x Copy of Supplemental Indenture dated July 1, 1985, which is
a supplemental instrument to Exhibit 4.01 hereto. [Filed as
Exhibit 4.24 to LG&E's Annual Report on Form 10-K for the
year ended December 31, 1985, and incorporated by reference
herein]

4.25 x Copy of Supplemental Indenture dated November 15, 1986,
which is a supplemental instrument to Exhibit 4.01 hereto.
[Filed as Exhibit 4.25 to LG&E's Annual Report on Form 10-K
for the year ended December 31, 1986, and incorporated by
reference herein]

4.26 x Copy of Supplemental Indenture dated November 16, 1986,
which is a supplemental instrument to Exhibit 4.01 hereto.
[Filed as Exhibit 4.26 to LG&E's Annual Report on Form 10-K
for the year ended December 31, 1986, and incorporated by
reference herein]

4.27 x Copy of Supplemental Indenture dated August 1, 1987, which
is a supplemental instrument to Exhibit 4.01 hereto. [Filed
as Exhibit 4.27 to LG&E's Annual Report on Form 10-K for the
year ended December 31, 1987, and incorporated by reference
herein]

4.28 x Copy of Supplemental Indenture dated February 1, 1989, which
is a supplemental instrument to Exhibit 4.01 hereto. [Filed
as Exhibit 4.28 to LG&E's Annual Report on Form 10-K for the
year ended December 31, 1988, and incorporated by reference
herein]

4.29 x Copy of Supplemental Indenture dated February 2, 1989, which
is a supplemental instrument to Exhibit 4.01 hereto. [Filed
as Exhibit 4.29 to LG&E's Annual Report on Form 10-K for the
year ended December 31, 1988, and incorporated by reference
herein]

4.30 x Copy of Supplemental Indenture dated June 15, 1990, which is
a supplemental instrument to Exhibit 4.01 hereto. [Filed as
Exhibit 4.30 to LG&E's Annual Report on Form 10-K for the
year ended December 31, 1990, and incorporated by reference
herein]

4.31 x Copy of Supplemental Indenture dated November 1, 1990, which
is a supplemental instrument to Exhibit 4.01 hereto. [Filed
as Exhibit 4.31 to LG&E's Annual Report on Form 10-K for the
year ended December 31, 1990, and incorporated by reference
herein]

4.32 x Copy of Supplemental Indenture dated September 1, 1992,
which is a supplemental instrument to Exhibit 4.01 hereto.
[Filed as Exhibit 4.32 to LG&E's Annual Report on Form 10-K
for the year ended December 31, 1992, and incorporated by
reference herein]

4.33 x Copy of Supplemental Indenture dated September 2, 1992,
which is a supplemental instrument to Exhibit 4.01 hereto.
[Filed as Exhibit 4.33 to LG&E's Annual Report on Form 10-K
for the year ended December 31, 1992, and incorporated by
reference herein]

4.34 x Copy of Supplemental Indenture dated August 15, 1993, which
is a supplemental instrument to Exhibit 4.01 hereto. [Filed
as Exhibit 4.34 to LG&E's Annual Report on Form 10-K for the
year ended December 31, 1993, and incorporated by reference
herein]

4.35 x Copy of Supplemental Indenture dated August 16, 1993, which
is a supplemental instrument to Exhibit 4.01 hereto. [Filed
as Exhibit 4.35 to LG&E's Annual Report on Form 10-K for the
year ended December 31, 1993, and incorporated by reference
herein]

4.36 x Copy of Supplemental Indenture dated October 15, 1993, which
is a supplemental instrument to Exhibit 4.01 hereto. [Filed
as Exhibit 4.36 to LG&E's Annual Report on Form 10-K for the
year ended December 31, 1993, and incorporated by reference
herein]

4.37 x Copy of Supplemental Indenture dated May 1, 2000,
which is a supplemental instrument to Exhibit 4.01
hereto.

100

4.38 x Copy of Supplemental Indenture dated August 1, 2000,
which is a supplemental instrument to Exhibit 4.01
hereto.

4.39 x Indenture of Mortgage or Deed of Trust dated May 1, 1947,
between KU and First Trust National Association (successor
Trustee) and a successor individual co-trustee, as Trustees
(the Trustees) (Amended Exhibit 7(a) in File No. 2-7061),
and Supplemental Indentures thereto dated, respectively,
January 1, 1949 (Second Amended Exhibit 7.02 in File No.
2-7802), July 1, 1950 (Amended Exhibit 7.02 in File No.
2-8499), June 15, 1951 (Exhibit 7.02(a) in File No. 2-8499),
June 1, 1952 (Amended Exhibit 4.02 in File No. 2-9658),
April 1, 1953 (Amended Exhibit 4.02 in File No. 2-10120),
April 1, 1955 (Amended Exhibit 4.02 in File No. 2-11476),
April 1, 1956 (Amended Exhibit 2.02 in File No. 2-12322),
May 1, 1969 (Amended Exhibit 2.02 in File No. 2-32602),
April 1, 1970 (Amended Exhibit 2.02 in File No. 2-36410),
September 1, 1971 (Amended Exhibit 2.02 in File No.
2-41467), December 1, 1972 (Amended Exhibit 2.02 in File No.
2-46161), April 1, 1974 (Amended Exhibit 2.02 in File No.
2-50344), September 1, 1974 (Exhibit 2.04 in File No.
2-59328), July 1, 1975 (Exhibit 2.05 in File No. 2-59328),
May 15, 1976 (Amended Exhibit 2.02 in File No. 2-56126),
April 15, 1977 (Exhibit 2.06 in File No. 2-59328), August 1,
1979 (Exhibit 2.04 in File No. 2-64969), May 1, 1980
(Exhibit 2 to Form 10-Q Quarterly Report of KU for the
quarter ended June 30, 1980), September 15, 1982 (Exhibit
4.04 in File No. 2-79891), August 1, 1984 (Exhibit 4B to
Form 10-K Annual Report of KU for the year ended December
31, 1984), June 1, 1985 (Exhibit 4 to Form 10-Q Quarterly
Report of KU for the quarter ended June 30, 1985), May 1,
1990 (Exhibit 4 to Form 10-Q Quarterly Report of KU for the
quarter ended June 30, 1990), May 1, 1991 (Exhibit 4 to Form
10-Q Quarterly Report of KU for the quarter ended June 30,
1991), May 15, 1992 (Exhibit 4.02 to Form 8-K of KU dated
May 14, 1992), August 1, 1992 (Exhibit 4 to Form 10-Q
Quarterly Report of KU for the quarter ended September 30,
1992), June 15, 1993 (Exhibit 4.02 to Form 8-K of KU dated
June 15, 1993) and December 1, 1993 (Exhibit 4.01 to Form
8-K of KU dated December 10, 1993), November 1, 1994
(Exhibit 4.C to Form 10-K Annual Report of KU for the year
ended December 31, 1994), June 1, 1995 (Exhibit 4 to Form
10-Q Quarterly Report of KU for the quarter ended June 30,
1995) and January 15, 1996 (Exhibit 4.E to Form 10-K Annual
Report of KU for the year ended December 31, 1995).
Incorporated by reference.

4.40 x Supplemental Indenture dated March 1, 1992 between KU and
the Trustees, providing for the conveyance of properties
formerly held by Old Dominion Power Company [Filed as
Exhibit 4B to Form 10-K Annual

101

Report of KU for the year ended December 31, 1992, and
incorporated by reference herein]

4.41 x Copy of Supplemental Indenture dated May 1, 2000,
which is a supplemental instrument to Exhibit 4.39
hereto.

10.01 x Copies of Agreement between Sponsoring Companies re:
Project D of Atomic Energy Commission, dated May 12, 1952,
Memorandums of Understanding between Sponsoring Companies
re: Project D of Atomic Energy Commission, dated September
19, 1952 and October 28, 1952, and Power Agreement between
Ohio Valley Electric Corporation and Atomic Energy
Commission, dated October 15, 1952. [Filed as Exhibit 13(y)
to LG&E's Registration Statement 2-9975 and incorporated by
reference herein]

10.02 x Copy of Modification No. 1 dated July 23, 1953, to the Power
Agreement between Ohio Valley Electric Corporation and
Atomic Energy Commission. [Filed as Exhibit 4.03(b) to
LG&E's Registration Statement 2-24920 and incorporated by
reference herein]

10.03 x Copy of Modification No. 2 dated March 15, 1964, to the
Power Agreement between Ohio Valley Electric Corporation and
Atomic Energy Commission. [Filed as Exhibit 5.02c to LG&E's
Registration Statement 2-61607 and incorporated by reference
herein]

10.04 x Copy of Modification No. 3 and No. 4 dated May 12, 1966 and
January 7, 1967, respectively, to the Power Agreement
between Ohio Valley Electric Corporation and Atomic Energy
Commission. [Filed as Exhibits 4(a)(13) and 4(a)(14) to
LG&E's Registration Statement 2-26063 and incorporated by
reference herein]

10.05 x Copy of Modification No. 5 dated August 15, 1967, to the
Power Agreement between Ohio Valley Electric Corporation and
Atomic Energy Commission. [Filed as Exhibit 13(c) to LG&E's
Registration Statement 2-27316 and incorporated by reference
herein]

10.06 x x Copies of (i) Inter-Company Power Agreement, dated July 10,
1953, between Ohio Valley Electric Corporation and
Sponsoring Companies (which Agreement includes as Exhibit A
the Power Agreement, dated July 10, 1953, between Ohio
Valley Electric Corporation and Indiana-Kentucky Electric
Corporation); (ii) First Supplementary Transmission
Agreement, dated July 10, 1953, between Ohio Valley Electric
Corporation and Sponsoring Companies; (iii) Inter-Company
Bond

102

Agreement, dated July 10, 1953, between Ohio Valley Electric
Corporation and Sponsoring Companies; (iv) Inter-Company
Bank Credit Agreement, dated July 10, 1953, between Ohio
Valley Electric Corporation and Sponsoring Companies.
[Filed as Exhibit 5.02f to LG&E's Registration Statement
2-61607 and incorporated by reference herein]

10.07 x x Copy of Modification No. 1 and No. 2 dated June 3, 1966 and
January 7, 1967, respectively, to Inter-Company Power
Agreement dated July 10, 1953. [Filed as Exhibits 4(a)(8)
and 4(a)(10) to LG&E's Registration Statement 2-26063 and
incorporated by reference herein]

10.08 x Copies of Amendments to Agreements (iii) and (iv) referred
to under 10.06 above as follows: (i) Amendment to
Inter-Company Bond Agreement and (ii) Amendment to
Inter-Company Bank Credit Agreement. [Filed as Exhibit
5.02h to LG&E's Registration Statement 2-61607 and
incorporated by reference herein]

10.09 x Copy of Modification No. 1, dated August 20, 1958, to First
Supplementary Transmission Agreement, dated July 10, 1953,
among Ohio Valley Electric Corporation and the Sponsoring
Companies. [Filed as Exhibit 5.02i to LG&E's Registration
Statement 2-61607 and incorporated by reference herein]

10.10 x Copy of Modification No. 2, dated April 1, 1965, to the
First Supplementary Transmission Agreement, dated July 10,
1953, among Ohio Valley Electric Corporation and the
Sponsoring Companies. [Filed as Exhibit 5.02j to LG&E's
Registration Statement 2-61607 and incorporated by reference
herein]

10.11 x Copy of Modification No. 3, dated January 20, 1967, to First
Supplementary Transmission Agreement, dated July 10, 1953,
among Ohio Valley Electric Corporation and the Sponsoring
Companies. [Filed as Exhibit 4(a)(7) to LG&E's Registration
Statement 2-26063 and incorporated by reference herein]

10.12 x Copy of Modification No. 6 dated November 15, 1967, to the
Power Agreement between Ohio Valley Electric Corporation and
Atomic Energy Commission. [Filed as Exhibit 4(g) to LG&E's
Registration Statement 2-28524 and incorporated by reference
herein]

10.13 x x Copy of Modification No. 3 dated November 15, 1967, to the
Inter-Company Power Agreement dated July 10, 1953. [Filed
as Exhibit 4.02m to LG&E's Registration Statement 2-37368
and incorporated by reference

103

herein]

10.14 x Copy of Modification No. 7 dated November 5, 1975, to the
Power Agreement between Ohio Valley Electric Corporation and
Atomic Energy Commission. [Filed as Exhibit 5.02n to LG&E's
Registration Statement 2-56357 and incorporated by reference
herein]

10.15 x x Copy of Modification No. 4 dated November 5, 1975, to the
Inter-Company Power Agreement dated July 10, 1953. [Filed
as Exhibit 5.02o to LG&E's Registration Statement 2-56357
and incorporated by reference herein]

10.16 x Copy of Modification No. 4 dated April 30, 1976, to First
Supplementary Transmission Agreement, dated July 10, 1953,
among Ohio Valley Electric Corporation and the Sponsoring
Companies. [Filed as Exhibit 5.02p to LG&E's Registration
Statement 2-61607 and incorporated by reference herein]

10.17 x Copy of Modification No. 8 dated June 23, 1977, to the Power
Agreement between Ohio Valley Electric Corporation and
Atomic Energy Commission. [Filed as Exhibit 5.02q to LG&E's
Registration Statement 2-61607 and incorporated by reference
herein]

10.18 x Copy of Modification No. 9 dated July 1, 1978, to the Power
Agreement between Ohio Valley Electric Corporation and
Atomic Energy Commission. [Filed as Exhibit 5.02r to LG&E's
Registration Statement 2-63149 and incorporated by reference
herein]

10.19 x Copy of Modification No. 10 dated August 1, 1979, to the
Power Agreement between Ohio Valley Electric Corporation and
Atomic Energy Commission. [Filed as Exhibit 2 to LG&E's
Annual Report on Form 10-K for the year ended December 31,
1979, and incorporated by reference herein]

10.20 x Copy of Modification No. 11 dated September 1, 1979, to the
Power Agreement between Ohio Valley Electric Corporation and
Atomic Energy Commission. [Filed as Exhibit 3 to LG&E's
Annual Report on Form 10-K for the year ended December 31,
1979, and incorporated by reference herein]

10.21 x x Copy of Modification No. 5 dated September 1, 1979, to
Inter-Company Power Agreement dated July 5, 1953, among Ohio
Valley Electric Corporation and Sponsoring Companies.
[Filed as Exhibit 4 to LG&E's

104

Annual Report on Form 10-K for the year ended December 31,
1979, and incorporated by reference herein]

10.22 x Copy of Modification No. 12 dated August 1, 1981, to the
Power Agreement between Ohio Valley Electric Corporation and
Atomic Energy Commission. [Filed as Exhibit 10.25 to LG&E's
Annual Report on Form 10-K for the year ended December 31,
1981, and incorporated by reference herein]

10.23 x x Copy of Modification No. 6 dated August 1, 1981, to
Inter-Company Power Agreement dated July 5, 1953, among Ohio
Valley Electric Corporation and Sponsoring Companies.
[Filed as Exhibit 10.26 to LG&E's Annual Report on Form 10-K
for the year ended December 31, 1981, and incorporated by
reference herein]

10.24 [Not used.]

10.25 x * Copy of Supplemental Executive Retirement Plan for R. W.
Hale, effective June 1, 1989. [Filed as Exhibit 10.42 to
the Company's Annual Report on Form 10-K for the year ended
December 31, 1992, and incorporated by reference herein]

10.26 x * Copy of Nonqualified Savings Plan covering officers of
the Company, effective January 1, 1992. [Filed as Exhibit
10.43 to the Company's Annual Report on Form 10-K for the
year ended December 31, 1992, and incorporated by reference
herein]

10.27 x Copy of Modification No. 13 dated September 1, 1989, to the
Power Agreement between Ohio Valley Electric Corporation and
Atomic Energy Commission. [Filed as Exhibit 10.42 to LG&E's
Annual Report on Form 10-K for the year ended December 31,
1993, and incorporated by reference herein]

10.28 x Copy of Modification No. 14 dated January 15, 1992, to the
Power Agreement between Ohio Valley Electric Corporation and
Atomic Energy Commission. [Filed as Exhibit 10.43 to LG&E's
Annual Report on Form 10-K for the year ended December 31,
1993, and incorporated by reference herein]

10.29 x x Copy of Modification No. 7 dated January 15, 1992, to
Inter-Company Power Agreement dated July 10, 1953, among
Ohio Valley Electric Corporation and Sponsoring Companies.
[Filed as Exhibit 10.44 to LG&E's Annual Report on Form 10-K
for the year ended December 31,

105

1993, and incorporated by reference herein]

10.30 x Copy of Modification No. 15 dated February 15, 1993, to the
Power Agreement between Ohio Valley Electric Corporation and
Atomic Energy Commission. [Filed as Exhibit 10.45 to LG&E's
Annual Report on Form 10-K for the year ended December 31,
1993, and incorporated by reference herein]

10.31 x Copy of Firm No Notice Transportation Agreement effective
November 1, 1993, between Texas Gas Transmission Corporation
and LG&E (expires October 31, 2001) covering the
transmission of natural gas.

Copy of Firm No Notice Transportation Agreement
effective November 1, 1993, between Texas Gas
Transmission Corporation and LG&E (expires October
31, 2000) covering the transmission of natural gas.

Copy of Firm No Notice Transportation Agreement
effective November 1, 1993, between Texas Gas
Transmission Corporation and LG&E (expires October
31, 2003) covering the transmission of natural gas.

[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]

10.32 [Not used.]

10.33 x x Copy of Modification No. 8 dated January 19, 1994, to
Intercompany Power Agreement, dated July 10, 1953, among
Ohio Valley Electric Corporation and the Sponsoring
Companies. [Filed as Exhibit 10.43 to LG&E's Annual Report
on Form 10-K for the year ended December 31, 1995, and
incorporated by reference herein]

10.34 x Copy of Amendment dated March 1, 1995, to Firm No-Notice
Transportation Agreements dated November 1, 1993 (2-Year,
5-Year and 8-Year), between Texas Gas Transmission
Corporation and LG&E covering the transmission of natural
gas. [Filed as Exhibit 10.44 of LG&E's Annual Report on
Form 10-K for the year ended December 31, 1995, and
incorporated by reference herein]

10.35 x x Copy of Modification No. 9, dated August 17, 1995, to the
Inter-Company Power Agreement dated July 10, 1953, among
Ohio Valley Electric Corporation and the Sponsoring
Companies. [Filed as Exhibit 10.39 to LG&E's Annual Report
on Form 10-K for the year ended December 31, 1996, and
incorporated by reference herein]

106

10.36 x Copy of Agreement and Plan of Merger, dated February 10,
1995, between LG&E Natural Inc., formerly known as Hadson
Corporation, Carousel Acquisition Corporation and the
Company. [Filed as Exhibit 2 of Schedule 13D by the Company
on February 21, 1995, and incorporated by reference herein]

10.37 x Copy of Firm Transportation Agreement, dated March 1, 1995,
between Texas Gas Transmission Corporation and LG&E (expires
October 31, 2003) covering the transportation of natural
gas.

Copy of Firm Transportation Agreement, dated March 1, 1995,
between Texas Gas Transmission Corporation and LG&E (expires
October 31, 2001) covering the transportation of natural
gas. [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]

10.38 x Copy of Firm Transportation Agreement, dated March 1, 1995,
between Texas Gas Transmission Corporation and LG&E (expires
October 31, 2000) covering the transportation of natural gas
[Filed as Exhibit 10.41 to LG&E's Annual Report on Form 10-K
for the year ended December 31, 1996, and incorporated by
reference herein]

10.39 [Not used.]

10.40 [Not used.]

10.41 x * Copy of Amendment to the Non-Qualified Savings Plan,
effective January 1, 1992. [Filed as Exhibit 10.55 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1995, and incorporated by reference herein]

10.42 x * Copy of Amendment to the Non-Qualified Savings Plan,
effective January 1, 1995. [Filed as Exhibit 10.56 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1995, and incorporated by reference herein]

10.43 x * Copy of Amendment to the Non-Qualified Savings Plan,
effective January 1, 1995. [Filed as Exhibit 10.57 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1995, and incorporated by reference herein]

10.44 x Copy of Form of Master Gas Purchase Agreement, dated
December 14,

107

1993, among Santa Fe, SFEOP and AGPC. [Filed as Exhibit
10.23 to LG&E Natural Inc.'s, formerly known as Hadson
Corporation, Registration Statement on Form S-4, File No.
33-68224, and incorporated by reference herein]

10.45 x Copy of Credit Agreement, dated as of December 18, 1995,
among LG&E, as Borrower, the Banks named therein, PNC Bank,
Kentucky, Inc. as Agent and Bank of Montreal as Co-Agent.
[Filed as Exhibit 10.01 to the LG&E's Quarterly Report on
Form 10-Q/A for the quarter ended March 31, 1996, and
incorporated by reference herein]

10.46 x Copy of Firm Transportation Agreement, dated November 1,
1996, between LG&E and Tennessee Gas Pipeline Company for
30,000 Mmbtu per day in Firm Transportation Service under
Tennessee's Rate FT-A (expires October 31, 2001). [Filed as
Exhibit 10.42 to LG&E's Annual Report on Form 10-K for the
year ended December 31, 1996, and incorporated by reference
herein]

10.47 x Copy of Amendment No. 1, dated as of November 5, 1996, to
Credit Agreement dated as of December 18, 1995, by and among
Louisville Gas and Electric Company, the Banks party
thereto, and PNC Bank, Kentucky, Inc. as Agent and Bank of
Montreal as Co-Agent. [Filed as Exhibit 10.59 to LG&E's
Annual Report on Form 10-K for the year ended December 31,
1996, and incorporated by reference herein]

10.48 - [Not used.]
10.55

10.56 x * Copy of LG&E Energy Corp. and Louisville Gas and Electric
Company Non-Officer Senior Management Pension
Restoration Plan, effective May 1, 1996. [Filed as
Exhibit 10.69 to LG&E Energy's Annual Report on Form
10-K for the year ended December 31, 1996, and
incorporated by reference herein]

10.57 - [Not used.]
10.58

10.59 x x * Copy of Supplemental Executive Retirement Plan as amended
through January 1, 1998, covering officers of LG&E Energy.
[Filed as Exhibit 10.74 to LG&E Energy's Annual Report on
Form 10-K for the year ended December 31, 1997, and
incorporated by reference herein]

10.60 [Not used.]

108

10.61 x Copy of Coal Supply Agreement between LG&E and Kindill
Mining, Inc., dated July 1, 1997. [Filed as Exhibit 10.76
to LG&E Energy's Annual Report on Form 10-K for the year
ended December 31, 1997, and incorporated by reference
herein]

10.62 x Copy of Coal Supply Agreement between LG&E and Warrior Coal
Corp. dated January 1, 1997, and Amendments #1 and #2 dated
May 1, 1997, and December 1, 1997, thereto. [Filed as
Exhibit 10.79 to LG&E Energy's Annual Report on Form 10-K
for the year ended December 31, 1997, and incorporated by
reference herein]

10.63 x Copies of Amendments dated September 23, 1997, to Firm
No-Notice Transportation Agreements dated November 1, 1993,
between Texas Gas Transmission Corporation and LG&E, as
amended. [Filed as Exhibit 10.81 to LG&E Energy's Annual
Report on Form 10-K for the year ended December 31, 1997,
and incorporated by reference herein]

10.64 x Copies of Amendments dated September 23, 1997, to Firm
Transportation Agreements dated March 1, 1995, between Texas
Gas Transmission Corporation and LG&E, as amended. [Filed
as Exhibit 10.82 to LG&E Energy's Annual Report on Form 10-K
for the year ended December 31, 1997, and incorporated by
reference herein]

10.65 x Copy of Gas Transportation Agreement dated November 1, 1996,
between Tennessee Gas Pipeline Company and LG&E and
amendments dated February 4, 1997, thereto. [Filed as
Exhibit 10.83 to LG&E Energy's Annual Report on Form 10-K
for the year ended December 31, 1997, and incorporated by
reference herein] [Certain portions of this exhibit have
been omitted pursuant to a confidential treatment request
filed with the Securities and Exchange Commission]

10.66 - [Not used.]
10.75

10.76 x Copy of Amended and Restated Coal Supply Agreement dated
April 1, 1998 between LG&E and Hopkins County Coal LLC.
[Filed as Exhibit 10.76 to LG&E's Annual Report on Form 10-K
for the year ended December 31, 1998 and incorporated by
reference herein]

10.77 x Copy of Coal Supply Agreement dated January 1, 1999 between
LG&E and Peabody COALSALES Company. [Filed as Exhibit 10.77
to LG&E's Annual Report on Form 10-K for the year ended
December 31, 1998 and

109

incorporated by reference herein]

10.78 [Not used.]

10.79 [Not used.]

10.80 x Copy of Assignment and Assumption Agreement dated November
16, 1998 between KU, Leslie Resources, Inc. and AEI Coal
Sales Company, Inc. regarding Coal Supply Agreement dated
December 31, 1997. [Filed as Exhibit 10.80 to KU's Annual
Report on Form 10-K for the year ended December 31, 1998 and
incorporated by reference herein]

10.81 x Copy of Coal Supply Agreement dated April 1, 1995 between KU
and Consolidation Coal Company, Quarto Mining Company,
McElroy Coal Company, Consol Pennsylvania Coal Company,
Greenon Coal Company and Nineveh Coal Company. [Filed as
Exhibit 10.81 to KU's Annual Report on Form 10-K for the
year ended December 31, 1998 and incorporated by reference
herein]

10.82 x Copy of Amendment to Coal Supply Agreement dated October 1,
1996 between KU and Consolidation Coal Company, Quarto
Mining Company, McElroy Coal Company, Consol Pennsylvania
Coal Company, Greenon Coal Company and Nineveh Coal Company
regarding Coal Supply Agreement dated April 1, 1995. [Filed
as Exhibit 10.82 to KU's Annual Report on Form 10-K for the
year ended December 31, 1998 and incorporated by reference
herein]

10.83 - [Not used.]
10.89

10.90 x x * Copy of Amendment to LG&E Energy's Supplemental Executive
Retirement Plan, effective September 2, 1998. [Filed as
Exhibit 10.90 to LG&E Energy's Annual Report on Form 10-K
for the year ended December 31, 1998 and incorporated by
reference herein]

10.91 x x * Copy of Amendment effective September 2, 1998 to
Supplemental Executive Retirement Plan for R. W. Hale
effective June 1, 1989. [Filed as Exhibit 10.91 to LG&E
Energy's Annual Report on Form 10-K for the year ended
December 31, 1998 and incorporated by reference herein]

10.92 [Not used.]

10.93 x x * Copy of Employment Agreement, dated as of February 25,
2000, by and among LG&E Energy, Powergen plc and Roger W.
Hale. [Filed as Exhibit 1 to Appendix A of LG&E Energy's
Preliminary Proxy Statement on Schedule 14A on March 13,
2000 and incorporated by reference herein]

110

10.94 x x * Copy of form of Employment and Severance
Agreement, dated as of February 25, 2000, by and
among LG&E Energy, Powergen plc and certain
executive officers of the Company. [Filed as
Exhibit 10.94 to LG&E's and KU's Annual Report on
Form 10-K for the year ended December 31, 1999 and
incorporated herein by reference.]

10.95 x x * Copy of form of First Amendment to Employment and
Severance Agreement by and among LG&E Energy, Powergen
plc and certain executive officers of the Company.

10.96 x x * Copy of Amendment, effective October 1, 1999, to LG&E
Energy's Non-Qualified Savings Plan. [Filed as Exhibit
10.96 to LG&E's and KU's Annual Report on Form 10-K for the
year ended December 31, 1999 and incorporated herein by
reference.]

10.97 x x * Copy of Amendment, effective December 1, 1999, to LG&E
Energy's Non-Qualified Savings Plan. [Filed as Exhibit
10.97 to LG&E's and KU's Annual Report on Form 10-K for the
year ended December 31, 1999 and incorporated herein by
reference.]

10.98 - [Not used.]
10.101

10.102 x x Copy of Modification No. 10., dated January 1, 1998, to the
Inter-Company Power Agreement dated July 10, 1953,
among Ohio Valley Electric Corporation and the
Sponsoring Companies. [Filed as Exhibit 10.102 to LG&E's
and KU's Annual Report on Form 10-K for the year ended
December 31, 1999 and incorporated herein by reference.]

10.103 x x Copy of Modification No. 11, dated April 1, 1999, to the
Inter-Company Power Agreement dated July 10, 1953, among
Ohio Valley Electric Corporation and the Sponsoring
Companies. [Filed as Exhibit 10.103 to LG&E's and KU's
Annual Report on Form 10-K for the year ended December 31,
1999 and incorporated herein by reference.]

10.104 x Copy of Amendment No. 1, dated January 1, 2000, to Amended
and Restated Coal Supply Agreement, dated April 1, 1998,
among LG&E, Hopkins County Coal, LLC and Webster County
Coal, LLC. [Filed as Exhibit 10.104 to LG&E's Annual Report
on Form 10-K for the year ended December 31, 1999 and
incorporated herein by reference.]

10.105 x Copy of Amendment No. 1, dated January 1, 2000, to Coal
Supply Contract, dated January 1, 1999, between LG&E and
Peabody CoalSales Company. [Filed as Exhibit 10.105 to
LG&E's Annual Report on Form 10-K for the year ended
December 31, 1999 and incorporated herein by reference.]

10.106 x Copy of Letter Amendment, dated September 15, 1999, to
Transportation Agreement, dated November 1, 1993, between
LG&E and Texas Gas Transmission Corporation. [Filed as
Exhibit 10.106 to LG&E's Annual Report on Form 10-K for the
year ended December 31, 1999 and incorporated herein by
reference.]

10.107 x x * Copy of Powergen Long-Term Incentive Plan, effective
December 11, 2000, applicable to certain employees of
LG&E Energy Corp. and its subsidiaries.

10.108 x x * Copy of Powergen Long-Term Incentive Plan - Roger Hale,
effective December 11, 2000.

10.109 x x * Copy of Powergen Short-Term Incentive Plan, effective
January 1, 2001, applicable to certain employees of LG&E
Energy Corp. and its subsidiaries.

10.110 x x * Copy of two forms of Change-In-Control Agreement
applicable to certain employees of LG&E Energy Corp. and
its subsidiaries.

12 x x Computation of Ratio of Earnings to Fixed Charges for LG&E
and KU. (previously filed)

21 x x Subsidiaries of the Registrant. (previously filed)

23.01 x Consent of Independent Public Accountants for LG&E.
(previously filed)

23.02 x Consent of Independent Public Accountants for KU.
(previously filed)

111

24 x x Power of Attorney. (previously filed)

99.01 x x Cautionary Statement for purposes of the "Safe Harbor"
provisions of the Private Securities Litigation Reform Act
of 1995. (previously filed)

99.02 x x Louisville Gas and Electric Company and Kentucky
Utilities Company - Information Concerning Directors and
Officers

(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.

On December 11, 2000, a report on Form 8-K was filed announcing that LG&E
Energy and Powergen had completed the merger involving the two companies.

(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.

112

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.

113

Louisville Gas and Electric Company Schedule II
Schedule II - Valuation and Qualifying Accounts
For the Three Years Ended December 31, 2000
(Thousands of $)

Other Accounts
Property Receivable
and (Uncollectible
Investments Accounts)
----------- ---------

Balance December 31, 1997 $ 63 $ 1,295

Additions:
Charged to costs and expenses - 2,300
Deductions:
Net charges of nature for which
reserves were created - 2,196
---------- -------
Balance December 31, 1998 63 1,399

Additions:
Charged to costs and expenses - 1,925
Deductions:
Net charges of nature for which
reserves were created - 2,091
---------- -------

Balance December 31, 1999 63 1,233

Additions:
Charged to costs and expenses - 2,803
Deductions:
Net charges of nature for which
reserves were created - 2,750
---------- -------

Balance December 31, 2000 $ 63 $ 1,286
======== =======

114

Kentucky Utilities Company Schedule II
Schedule II - Valuation and Qualifying Accounts
For the Three Years Ended December 31, 2000
(Thousands of $)

Other Accounts
Property Receivable
and (Uncollectible
Investments Accounts)
----------- ---------

Balance December 31, 1997 $ 345 $ 520

Additions:
Charged to costs and expenses 231 1,308
Deductions:
Net charges of nature for which
reserves were created - 1,308
---------- -------

Balance December 31, 1998 576 520

Additions:
Charged to costs and expenses 111 1,707
Deductions:
Net charges of nature for which
reserves were created - 1,427
---------- -------

Balance December 31, 1999 687 800

Additions:
Charged to costs and expenses 64 1,430
Deductions:
Net charges of nature for which
reserves were created - 1,430
---------- -------

Balance December 31, 2000 $ 751 $ 800
======= =======

115

SIGNATURES - LOUISVILLE GAS AND ELECTRIC COMPANY

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.

LOUISVILLE GAS AND ELECTRIC COMPANY
Registrant

March 30, 2001 /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
- --------- ----- ----
Roger W. Hale Chairman of the Board
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);

Sir Frederick Crawford Director;

David J. Jackson Director;

Sydney Gillibrand Director;

Dr. David K-P Li Director;

Paul Myners Director;

Roberto Quarta Director;

Edmund Wallis Director.

By /s/ S. Bradford Rives March 30, 2001
---------------------------

(Attorney-In-Fact)

116

SIGNATURES - KENTUCKY UTILITIES COMPANY

KENTUCKY UTILITIES COMPANY
Registrant

March 30, 2001 /s/ S. Bradford Rives
- --------------- -----------------------------------
(Date)

SIGNATURE TITLE DATE
- --------- ----- ----
Roger W. Hale Chairman of the Board
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);

Sir Frederick Crawford Director;

David J. Jackson Director;

Sydney Gillibrand Director;

Dr. David K-P Li Director;

Paul Myners Director;

Roberto Quarta Director;

Edmund Wallis Director.

By /s/ S. Bradford Rives March 30, 2001
-------------------------

(Attorney-In-Fact)

117